20040415Volume VII Part I.pdf

ORIGINAL
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AUTHORITY
TO INCREASE ITS INTERIM AND BASE
RATES AND CHARGES FOR ELECTRIC
SERVICE.
) CASE NO. IPC-E-O3-
Idaho Public Util~ies CommisSion
Office of the SecretaryRECEIVED
APR 1 5 2004
Boise, IdahO
BEFORE
COMMISSIONER MARSHA SMITH (Presiding)
COMMISSIONER PAUL KJELLANDER
COMMISSIONER DENNIS HANSEN
PLACE:Commission Hearing Room
472 West Washington
Boise, Idaho
DATE:March 29, 2004
" VOLUME VII - Pages 547 - 909
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CSB" REpORTING
Constance S.Bucy, CSR No. 187
17688 A1lendale Road * Wilder, Idaho 83676
[phone] *[phone]
Email csb~spro.net
For the Staff:Lisa Nordstrom, Esq.
and Weldon Stutzman, Esq.
Deputy Attorney Generals
472 West Washington
Boise, Idaho 83720-0074
Barton L. Kline, Esq.
and Monica B. Moen, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
RICHARDSON & 0 I LEARY
by Peter J. Richardson, Esq.
Post Office Box 1849
Eagle , Idaho 83616
RACINE , OLSEN , NYE , BUDGE
& BAI LEY
by Randall C. Budge, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
Lawrence A. Gollomp, Esq.
Assistant General Counsel
U. S. Department of Energy
1000 Independence Ave., SWWashington, DC 20585
McDEVITT & MILLER
by Dean J. Miller, Esq.
Post Office Box 2564
Boise , Idaho 83701
William M. Eddie
Advocates for the West
Post Office Box 1612Boise, Idaho 83701
GIVENS PURSLEY LLP
by Conley E. Ward, Esq.
Post Office Box 2720
Boise, Idaho 83701-2720
For Idaho Power
Company:
AP PEARANCE S
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For Industrial Customers
of Idaho Power:
For Idaho Irrigation
Pumpers Association:
For The United States
Department of Energy:
For United Water Idaho,
Inc:
For NW Energy Coalition:
For Micron Technology,
Inc.
CSB REPORTING
Wilder , Idaho 83676
A P P A R N C E S (Continued)
For Community Action
Partnership Association
of Idaho and AARP:
Brad M. Purdy, Esq.
Attorney at Law
2019 North 17th StreetBoise, Idaho 83702
For Kroger Company:
(Of Record)
BOEHM, KURSZ & LOWRY
by Kurt J. Boehm, Esq.
36 E. Seventh Street
Suite 2110
Cincinnati , Ohio 45202
CSB REPORTING
Wilder , Idaho
APPEARANCES
83676
----", _.
WITNESS
Phil Obenchain
(Idaho Power)
Paul Prescott
Idaho Powe r )
Gregory Said
Idaho Powe r )
Maggie Brilz
Idaho Power)
EXAMINATION BY
Mr. Kline (Direct)
Prefiled Testimony
Ms. Nordstrom (Cross)Mr. Budge (Cross)Mr. Ward (Cross)
Mr. Kline (Redirect)
Mr. Kline (Direct-Reb)
Prefiled Rebuttal Testimony
Mr. Ward Cross-Reb)Mr. Richardson (Cross-Reb)Mr. Budge (Cross-Reb)Ms. Nordstrom (Cross-Reb)
Commissioner Smith
Mr. Kline (Redirect-Reb)
Ms. Moen (Direct)
Prefiled Direct Testimony
Ms. Nordstrom (Cross)Mr. Budge (Cross)Mr. Richardson (Cross)Mr. Ward (Cross)Mr. Purdy (Cross)Mr. Eddie (Cross)
Commissioner Smith
Mr. Kline (Direct)
Prefiled Direct Testimony
Mr. Stutzman (Cross)Mr. Richardson (Cross)
Mr. Miller (Cross)Mr. Purdy (Cross)
Mr. Eddie (Cross)Commissioner Smith
PAGE
547
549
581
582
592
597
598
600
653
657
678
681
683
684
688
690
724
725
736
739
741
742
743
747
749
866
868
889
894
897
906
CSB REPORTING
Wilder , Idaho 83676 INDEX
NUMBER DESCRIPTION
FOR IDAHO POWER COMPANY:
PAGE
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
Summary of Total Rate Base and Net
Income Adj ustments
Summary of Adj ustments - Electric
Plant In Service
Summary of Adjustments
Accumulated Provision for
Depreciation and Amortization
Summary of Adjustments - Additions
or Deletions to Ratebase
Summary of Adjustments - OperatingRevenues
Summary of Adj ustments - Operation
and Maintenance Expenses
Summary of Adjustments
Depreciation and Amortization
Expense
Summary of Adj ustments - Taxes
Other Than Income Taxes
Summary of Adj ustments - Income
Taxes
Jurisdictional Separation Study
Idaho Revenue Requirement
Development of Jurisdictional
Allocation Factors/Ratios
Power Supply Expenses Normalized
Prior to Known and Measurable Power
Supply Adj ustments
Power Supply Expenses Normalized
Including Known and Measurable
Power Supply Adj ustments
CSB REPORTING
Wilder , Idaho 83676
EXHIBITS
NUMBER
E X H I B T S (Continued)
DESCRIPTION
FOR IDAHO POWER COMPANY:(Continued)
PAGE
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
47.
48.
49.
69.
Known and Measurable Adj ustments
to Power Supply Expenses
PCA Regression Derivation
Computation of PCA Factors
Functionalization and Classification
of Costs
Summary of Functionalized Costs
Allocation to Classes
Development of Weighted Demand and
Energy Allocators
Revenue Requirement Summary
Class Cost -of -Service Unit Costs
Summary of Revenue Impact and
Calculation of Proposed Rates
Billing Comparisons and Rate Design
Impacts of Proposed Rates
Derivation of Schedule 19 Charges
Derivation of Schedule 24 Charges
Derivation of Schedule 45 Charges
Proposed Tariff in Legislative
Format
Proposed Tariff
2003-2004 Cloud Seeding Program
CSB REPORTING
Wilder , Idaho 83676 EXHIBITS
E X H I B T S (Continued)
NUMBER DESCRIPTION PAGE
FOR THE INDUSTRIAL CUSTOMERS OF IDAHO POWER:
216. IPC - Residential Time-of-Use
Pricing Variability Study
Identified 666
217. Letter & Report from Idaho Power to
the PUC , dated May 9, 2003
Identified 670
CSB REPORTING
Wilder, Idaho
EXHIBITS
83676
BOISE , IDAHO , MONDAY , MARCH 29 , 2004 , 1:30 P.
COMMISSIONER SMITH:Okay, if you're ready,
we'll go back on the record.
CSB REPORTING
Wilder, Idaho
Mr. Kline.
MR. KLINE:Idaho Power's next witness is
Phil Obenchain.
PHILLIP OBENCHAIN
produced as a witness at the instance of Idaho Power
Company, having been first duly sworn , was examined and
testified as follows:
DIRECT EXAMINATION
Could you please state your name for the
Phil A. Obenchain.
And what is your position at Idaho Power?
Senior Pricing Analyst.
And Mr. Obenchain, have you previously of
30 pages of prefiled direct testimony and Exhibits 21
BY MR.KLINE:
record?
through 31?
547 OBENCHAIN (Di)
Idaho Power Company83676
I have.
Do you have any corrections that you need
to make to your prefiled direct testimony.
I do not.
So if I were to ask you the same questions
contained in your prefiled direct testimony today, would
your answers be the same?
They would.
MR. KLINE:Madame Chai rman , wi th that, I
would request that Mr.Obenchain's prefiled direct
testimony be spread on the record read its
entirety and that Mr.Obenchain I Exhibits through 31
identified for the record.
COMMISSIONER SMITH:If there I s no
objection, it is so ordered.
(The following prefiled direct testimony of
Mr. Phil Obenchain is spread upon the record.
CSB REPORTING
Wilder , Idaho
548 OBENCHAIN (Di)
Idaho Power Company83676
Please state your name and business address.
My name is Phil A. Obenchain , and my business
address is 1221 West Idaho Street, Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by Idaho Power Company as a
Senior Pricing Analyst in the Pricing and Regulatory
Services Department.
Please describe your educational background and
professional experience.
In May of 1979 , I received a Bachelor of Arts
Degree in Economics from Boise State University in Boise,
Idaho.
In August of 1979, I was employed as an Economic
Research Assistant with Idaho First National Bank
(presently U. S. Bank).
In August of 1981, I left Idaho First to attend the
Uni versi ty of Idaho in Moscow , Idaho to pursue a Masters
of Science Degree in Economics, with emphasis in
Regulatory Economics.I completed the necessary course
work in the spring of 1982.
In January of 1983 , I accepted the position of
Pricing Analyst with Idaho Power Company.My duties
as Pricing Analyst include the preparation of
cost-of -service information for use in the
development of jurisdictional
549 OBENCHAIN
Idaho Power Company
separation studies and class cost -of - service studies.
More specifically, I am responsible for gathering and
analyzing data from various sources to carry out
cost -of - service related analyses as required by the three
jurisdictions regulating Idaho Power Company.
I was the Company I s revenue requirement witness
before this Commission in Case No. IPC-E-94-5 and
testif ied on the earnings test results as part of Case
No. IPC-97-12.In addition, I have sponsored testimony
before the Oregon Public Utility Commission in Case UE
on the Oregon jurisdictional revenue requirement.
What is the scope of your testimony in this
proceeding?
I am sponsoring testimony in this proceeding on
the Idaho jurisdictional revenue requirement resulting
from the Jurisdictional Separation Study (JSS).
My testimony is outlined as follows:
First , I am offering testimony summarizing the
adjustments to total system test year data used by the
Company for purposes of restating the Company's rate
base, revenues, and expenses for the 12 months ending
December 31 , 2003.
Second, I am offering testimony relative to the
preparation of a jurisdictional separation study prepared
using the adjusted total system data for the
550 OBENCHAIN
Idaho Power Company
months ending December 31, 2003 for the purpose of
determining the Idaho jurisdictional revenue deficiency.
Have you prepared or supervised the preparation
of various exhibits for this proceeding?
I have prepared or supervised theYes.
preparation of the following exhibits:
EXHIBIT TITLE
Exhibit No. 21 Summary of Total Rate Base and Net
Income Adj ustments
Exhibit No. 22 Summary of Adj ustments - Electric
Plant In Service
Exhibit No. 23 Summary of Adj ustments - Accumulated
provision for Depreciation and
Amortization
Exhibit No. 24 Summary of Adjustments - Additions
and Deductions to Rate Base
Exhibit No. 25 Summary of Adjustments - Operating
Revenues
Exhibit No. 26 Summary of Adjustments - Operation
and Maintenance Expenses
Exhibit No. 27 Summary of Adj ustments - Depreciation
and Amortization Expense
Exhibit No. 28 Summary of Adj ustments - Taxes Other
Than Income Taxes
Exhibit No. 29 Summary of Adj ustments - Income Taxes
551 OBENCHAIN
Idaho Power Company
Exhibit No. 30 Jurisdictional Separation Study
Idaho Revenue Requirement
Exhibit No. 31 Development of Jurisdictional
Allocation Factors
Please describe Exhibit No. 21.
Exhibi t No. 21 consists of two pages and
identifies the development of the adjusted total electric
system rate base and the development of net income for
the 12 months ending December 31, 2003.The 2003 test
year values contained in column 1 of Exhibi t No. 21 are
the unadj usted test year amounts. The adj ustments
proposed by the Company for purposes of developing the
2003 adjusted total electric system combined rate base
and net income for this proceeding are shown in columns
through 5 of Exhibi t No. 21.The unadj usted test year
information and adjustments, except as otherwise noted
were provided to me by Ms. Smith.The total system
adjusted test year rate base, expenses and revenues are
summari zed in column 6 of Exhibi t No. 21.
Page 1 of Exhibit No. 21 summarizes the development
of rate base components for the 12 months ending December
, 2003. The total combined rate base prior to
adjustments is $1,752 511 220 as seen on line 24 in
column 1 on page 1 of Exhibit No. 21.The total combined
rate base is reduced to $1 673,283,777 , after all test
552 OBENCHAIN
Idaho Power Company
year adjustments have been included , and can be seen on
line 24 in column 6 on page 1 of Exhibit No. 21.
Page 2 of Exhibit No. 21 presents the development of
the total system net income for the 12 months ending
December 31 , 2003.Operating revenues are summarized on
ine 31 in columns 1 through Total operating expenses
are summarized on line 42 in columns 1 through The
resulting net income is summarized on line 46 in columns
1 through 6.Net income increases from the test year
level of $65 895,300 to $81 433,150 after all ratemaking
adjustments have been included.
Please describe the total test year 2003 rate
base , expenses and revenues found in column 1 of Exhibit
No. 21.
Total test year amounts , before adj ustment , are
presented in column 1 of Exhibit No. 21.Wi th the
exception of test year firm operating revenues and test
year power supply expenses , the amounts in column 1 were
provided to me by Ms. Smi th.Firm operating revenues,
line 29 , are calculated utilizing (1) 2003 normalized
test year sales provided by the Company's Power Supply
Planning department , and (2) the current base rates.The
test year values for the Company s power supply accounts
(Surplus Sales Revenues - Account 447 , Fuel - Accounts
501 and 547 , Market Purchases - Account 555.1 andPurchases from Qualifying Facilities
553 OBENCHAIN
Idaho Power Company
Account 555.2) are the account balances from the most
recent PCA filing provided to me by Mr. Said. A summary
of these accounts is presented by FERC Account on lines
48 through 55 on page 2 , of Exhibit No. 21.
Why have the 2003 test period rate base
revenues , and expenses of the Company been adjusted?
Test year information is adjusted to reflect
known changes to the test year data for determining the
Company I S rates. In this way, rates will reflect the most
current cost information available at the time those
rates become effective.
Please explain what types of ratemaking
adjustments are made for the development of the Idaho
jurisdictional revenue requirement?
Ratemaking adj ustments are generally one of
three types.First, normalizing adjustments are made to
those items that are influenced by weather.Mr. Said
discusses the normalization of the Company's Net Power
Supply Expenses in his testimony in this proceeding.
Normalizing adjustments are shown in column 2 of Exhibit
No. 21.
Second , annualizing adjustments are made to reflect
changes that occur wi thin the test year , but need to be
incorporated for the full year on an ongoing basis.
Annualizing adjustments are shown in column 3 of Exhibit
554 OBENCHAIN
Idaho Power Company
No. 21.
Third , known and measurable adjustments proposed in
this filing reflect changes that will occur after
December 31 , 2003 , but prior to or coincident with the
effective date of the new rates.Known and measurable
adjustments are shown in column 4 , Exhibit No. 21.
Please discuss the annualizing adjustments to
the rate base components summarized in column 3 of page 1
of Exhibit No. 21.
The first annualizing adjustment in column 3 on
page 1 of Exhibit No. 21 is an increase of $6,621,907 to
production plant in service investment , line 9 , for the
rewind of Bridger Uni t No.The second is an increase
of $13 157 482 to transmission plant in service , line 10
for the Brownlee-Oxbow transmission line.The last is an
increase of $1 709 301 to Accumulated Provision for
Depreciation to capture plant at the end of 2003.The
above adj ustments were provided to me by Ms. Smith.
Please discuss the known and measurable
adjustments to rate base presented in column 4 on page 1
of Exhibit No. 21?
The first is an increase of $18 388 690 line
, to transmission plant in service investment for
upgrades to the Brownlee-Oxbow transmission line and the
Star , Valli vue , Midrose and Goshen (345 capacitor bank)
555 OBENCHAIN
Idaho Power Company
transmission stations.The investment amounts were
provided to me by Ms. Smi th.The second is an increase
of $3,211 822 to the accumulated provision for
depreciation reserve associated with one-half of the
annualized depreciation expense adjustment that was also
provided to me by Ms. Smi th.The last known and
measurable adjustment is a reduction of $2 076 923 to
IERCO subsidiary rate base associated with the
revaluation of prior year contingent tax reserves and a
true-up of deferred tax related to prior years.This
adj ustment was provided to me by the Company's Tax
Department.
Have you included any other adjustments to rate
base other than the annualizing and known and measurable
adjustments?
Yes , other adj ustments to rate base are
presented in column 5 on page 1 of Exhibi t No. 21.
Please describe the other adj ustments shown in
column 5 on page 1 of Exhibit No. 21.
The three adj ustments shown in column 5 on page
1 of Exhibit No. 21 are:
A reduction to production plant of $1 577 314
to reverse the amount booked in 2003 for Asset
Retirement Obligation (ARO) provided to me
Ms. Smith.
556 OBENCHAIN
Idaho Power Company
An increase of $106,204 452 to Accumulated
Deferred Depreciation to reverse amounts booked
in 2003 associated with ARO, as provided by Ms.
Smith.
A reduction of $2 615 452 to Fuel
Inventory to reflect current operating criteria
that result in the required coal inventory of
140 000 000 and 30 000 tons at Bridger
Valmy and Boardman, respectively. The fuel
inventory adj ustment was provided by Mr. Said.
Please recap the net effect of the annualizing,
known and measurable, and other adjustments to rate base.
After the annualizing, known and measurable,
and other adjustments are included , the adjusted total
electric system combined rate base for the 12 months
ending December 31, 2003, as shown on line 24 in column 7
of page 1 of Exhibit No. 21 , is $1 673,283 777.This
amount is $79 227 443 less than the unadjusted number in
column 1.
Please describe page 2 of Exhibit No. 21.
Page 2 of Exhibit No. 21 shows the development
of the adj usted total electric system net income for the
12 months ending December 31 , 2003.
Please describe the Company's normalizing
adjustments to the net income components shown in column
557 OBENCHAIN
Idaho Power Company
2 on page 2 of Exhibit No. 21.
The normalizing adjustments in column 2 on page
2 of Exhibit No. 21 consist of the following two
adjustments:
An increase to Operating Revenues in the amount
of $14 562 765 reflects the increased level of
opportunity sales associated with multiple
historical water conditions provided and
discussed by Mr. Said in his testimony in this
proceeding.
A reduction to Operation and Maintenance
Expense in the amount of $42 122 055 reflects
the decreased fuel and purchase power expenses
associated with multiple historical water
conditions as quantified and discussed by
Mr. Said in his testimony in this proceeding.
Please explain the Company I s annualizing
adjustments to the statement of income in column 3 on
page 2 of Exhibit No. 21.
The annualizing adjustments to the income
component shown in column 3 on page 2 of Exhibit No. 21
are made to reflect changes to expenses and revenues,
occurring within the test year that should be included
for a full year.
558 OBENCHAIN
Idaho Power Company
Were there any annualizing adjustments to the
operating revenues of the Company?
Yes.A reduction of $72,871 was made to other
operating revenues to reflect changes to facility charge
revenue as provided and discussed by Ms. Brilz in her
testimony in this proceeding.
Please describe the annualizing adjustments
made to the operating expenses of the Company.
The annualizing adjustments to the Company'
operating expenses were provided to me by Ms. Smith and
consist of the following three adjustments presented in
column 3 on page 2 of Exhibit No. 21:
An increase of $3,256 361 to Operation and
Maintenance Expenses (O&M), which consists of:
(1) an increase to specific O&M expense
accounts to reflect an annualized Payroll
adj ustment of $2 913,244;(2) an increase to
Property and Liability Insurance of $389 417;
and (3) a reduction to Account 908 , Customer
Assistance, of $46,300 related to the
expiration of DSM amortization in Oregon.This
last adj ustment has no impact on the Idaho
jurisdictional revenue requirement.
An increase to Depreciation Expense , Account
403, of $3 418 600 , which reflects the 2003
559 OBENCHAIN
Idaho Power Company
annualized depreciation.
An increase of $120 655 to Taxes Other Than
Income Taxes to reflect the property tax impact
of the annualized plant additions.
Please explain the known and measurable
adjustments to the statement of income presented in
column 4 on page 2 of Exhibit No. 21.
The known and measurable adj ustments to the
statement of income components reflect the following:
An increase of $8 930,300 to Firm Sales
Revenues resulting from an increase to the
level of Opportunity Sales - Account 447
provided by Mr. Said.
An increase of $346 171 to Other Operating
Revenues resulting from a change to Pole
Attachment Revenues - Account 456 reflecting
2004 Cableone contract revenues provided to me
by Ms. Smith.
An increase in Operation and Maintenance
Expenses of $18,185 548 that is composed of two
primary adjustments: the first, an increase of
269,427 in accounts 501 , 547 and 555, which
reflect the increased levels provided by Mr.
Said, and the second, an increase to Operation
and Maintenance
560 OBENCHAIN
Idaho Power Company
Expenses other than power supply expenses of
$9,916 121 provided to me by Ms. Smith.
An increase to Depreciation Expense of
$6,423 645 to reflect the additional
depreciation expense associated with the known
and measurable adjustments to electric plant in
service provided to me by Ms. Smith.
An increase to Taxes Other Than Income Taxes of
$112 171 for Property Taxes associated with the
known and measurable adj ustment to Electric
Plant In Service provided to me by Ms. Smith.
A reduction to IERCO operating income of
291 270 provided to me by the Company s Tax
Depart men t
Please explain the other adj ustments presented
in column 5 on page 2 of Exhibit No. 21.
Other system adj ustments proposed by the
Company consist of the following:
An increase to retail sales revenues of
$665 816 , which can be found on line 29 in
column 5.In addition , there were two
adjustments to other operating revenues:(1) a
reduction of $665 816 in Account 454 Facilities
Charge Revenues to reflect the
561 OBENCHAIN
Idaho Power Company
change in treatment of facilities charge
revenues paid by MICRON under its special
contract retail rate as provided to me by Ms.
Brilz , and (2) an increase to Miscellaneous
Service Revenue of $907 290 to reflect the
Company's revised Service Establishment,
Reconnection and Field Collection fees provided
to me by Ms. Drake.These two adjustments net
to the $241 474 found on line 30 in column 5 on
page 2 of Exhibit No. 21.
A reduction to Operation and Maintenance
Expenses of $475,556 reflecting the sum of
three separate components.The first component
is an increase to Idaho Rate Case Expense of
953. The second component is a decrease of
$452 125 to reflect the removal of General
Advertising Expense. The final component is a
$28 384 reduction to Memberships and
Contributions. Advertising Expense and
Memberships and Contributions have been
disallowed in past orders of this Commission
and thus have been removed from the 2003 test
year operating expenses.Ms. Smi th provided
these adjustments.
Are there any additional adjustments to the
562 OBENCHAIN
Idaho Power Company
test year actual data that should be mentioned?
Yes.The impacts to Federal and State income
taxes paid resulting from the ratemaking adj ustments
discussed above were provided to me by the Company I s Tax
Department and are shown on lines 40 and 41 on page 2 of
Exhibit No. 21.
Please describe Exhibit No. 22.
Exhibi t No. 22 consists of 2 pages and provides
greater detail of the adjustments to the Company'
Electric Plant In Service , by FERC account , used in this
proceeding.
Please describe Exhibit No. 23.
Exhibit No. 23 consists of 2 pages and provides
greater detail of the Accumulated Provision for
Depreciation and Amortization Reserve.
Please describe Exhibit No. 24.
Exhibit No. 24 is a two-page exhibit , which
provides greater detail of other additions to or
deductions from the Company's total combined rate base.
Please describe Exhibit No.2 5.
Exhibit No. 25 is a one-page exhibit , which
summarizes by FERC Account the Company I s operating
revenues for the test period used in this proceeding.
Please describe Exhibit No.2 6.
Exhibit No. 26 is a six-page exhibit, which
563 OBENCHAIN
Idaho Power Company
provides greater detail of test year and adjusted test
year operation and maintenance expenses for the 12 -month
period ending December 31 , 2003.
Please describe Exhibit No. 27.
Exhibit No. 27 is a two-page exhibit, which
provides greater detailed information by FERC account of
Depreciation and Amortization Expenses used in this
proceeding.
Please describe Exhibit No.2 8.
Exhibit No. 28 is a one-page exhibit , which
provides detailed information regarding taxes other than
income taxes used in this proceeding.
Please describe Exhibit No.2 9.
Exhibit No. 29 is a one-page exhibit, which
provides a detailed summary of the income tax related
adjustments that result in the adjusted tax expenses on
lines 40 and 41 of page 2 of Exhibit No. 21.These
adj ustments were provided to me by the Company's Tax
Department.
Have you prepared an exhibit that sets forth
the Idaho jurisdictional revenue deficiency?
Yes.I have prepared Exhibit No. 30 titled
Jurisdictional Separation Study - Idaho Revenue
Requirement" consisting of 35 pages.
Please discuss the methodology used to
564 OBENCHAIN
Idaho Power Company
jurisdictionally separate costs in the preparation of
this study.
The cost of providing electric service is
measured through the use of test year data as adjusted
for the 12-month period ending December 31 , 2003.
In order to establish a methodology for separating
costs among jurisdictions , a three-step process is
generally used. The steps are referred to as
classification , functionalization , and allocation of
costs.In all three steps, recognition is given to the
way in which costs are incurred by relating these costs
to the way in which a utility is operated to provide
electrical service.The methodology used to separate
costs by jurisdiction and calculate the Idaho
jurisdictional revenue requirement in the present case lS
the same methodology utilized by the Company and accepted
by the Commission in previous rate cases.
Would you please briefly explain the meaning of
classification, functionalization , and allocation?
Classification refers to the identification of
costs as being related to one of three components; demand
related, energy related or customer related.In addition
to classification , costs are functionalized; that is
identified with utility operating functions such as
generation , transmission and distribution.Indi vidual
565 OBENCHAIN 1 7
Idaho Power Company
plant items are examined and , where possible , the
associated investment costs are assigned to one or more
operating functions.Once the Company's total system
costs are classified and assigned to the appropriate
function they may be allocated among jurisdictions.
The process of allocation is merely one of
apportioning the total system cost among jurisdictions by
introducing allocation factors into the process.
allocation factor is nothing more than an array of
numbers , which specifies the jurisdictional value or
share of the total system quantity.For example, in the
case of energy related costs , the allocation factor is
annual jurisdictional energy use, adj usted for losses.
Once individual accounts have been allocated to the
various jurisdictions , it is possible to summarize these
into total utility rate base and net income by
jurisdiction.The results are stated in a summary form
to measure adequacy of revenues for the jurisdiction
under consideration.The measure of adequacy is
typically the rate of return earned on rate base , which
is compared to the requested rate of return.
How have the various functional plant and cost
items been allocated?
After classification and functionalization
allocation factors based on demand and energy use were
566 OBENCHAIN
Idaho Power Company
determined.In order to allocate demand related costs,
the average of the 12 monthly coincident peak demands was
used.The Company has used this allocation method for
jurisdictional separation purposes in all of its retail
and wholesale rate applications prepared during the past
25 years.This allocation method has been adopted by
this Commission and accepted by the Oregon Public Utility
Commission, and the Federal Energy Regulatory Commission.
The demand related allocation factors used in the study
are designated as D10 , D11, D60.The respective values
used in these demand allocation factors are shown at line
numbers 967 through 969 on page 29 of Exhibit No. 30.
What method was used to allocate general plant
and certain labor related administrative and general
expenses?
In accordance with FERC procedures, general
plant and administrative and general expenses have been
allocated in accordance with functionalized wages and
salaries.These labor related allocation factors are
shown on Table 12 of Exhibit No. 30, pages 23 through 28.
How were the energy related expenses allocated
among jurisdictions?
Energy related expenses were allocated on the
basis of normalized jurisdictional kilowatt hour sales,
adjusted for losses so as to establish energy
567 OBENCHAIN
Idaho Power Company
requirements at the generation level.The energy related
allocation factors used in the study are designated as
E10 and E100.The respective values used in these energy
allocation factors are shown on Table 13 of Exhibit No.
30, page 29 lines 972 & 973 , respectively.
What was the method by which you allocated
customer-related costs?
The principal customer-related expenses , which
require allocation , are Account 902 , Meter Reading
Expenses and Account 903, Customer Accounting and
Billing.These accounts were allocated based upon a
review of actual Company practices in reading meters and
preparing monthly bills or statements.
Please describe the derivation of the 2003
total system allocation factors used in this case.
The 2003 Jurisdictional Separation Study
utilizes 2002 data for most of the Allocation Factors
wi th some except ions:
Capacity or demand-related allocation factors
(D10, D11 , and D60) utilized 2002 Coincident
Peak information that was adj usted to reflect
known changes for 2003 , for example the
expiration of the UAMPS and Washington City
Sales for Resale contracts.
Energy-related allocation factors (E10 and
568 OBENCHAIN
Idaho Power Company
E100) are the 2003 normalized test year sales
at generation level.
The directly assigned revenue accounts were
updated to reflect 2003 test year revenues.
Finally, the direct assignment of plant
accounts 360 , 361 and 362 received specific new
treatment.
Would you please explain how the direct
assignment of accounts 360 , 361 and 362 differs in the
2003 Jurisdictional Separation Study from prior studies?
Yes.Historically Contributions In Aid of
Construction (CIAC) have been treated as a reduction to
the total investment in accounts 360, 361 and 362 prior
to any allocation of plant and related operation and
maintenance expense.Consequently, all customers
(jurisdictions) have shared in the benefits of
contributions paid by a few.
In order to pass the benefit of the CIAC to the
customers (jurisdictions) that made the contribution
accounts 360 , 361 and 362 were identified by the net
investment and by the net plus CIAC investment.The net
plus CIAC amount was then directly assigned to customers
(jurisdictions) prior to any reduction for CIAC.In this
way the customers (jurisdictions) that make the
contribution receive the full credit.
569 OBENCHAIN
Idaho Power Company
In addition , operation and maintenance expenses
resulting from investment in accounts 360 , 361 and 362
are related to the total investment and thus allocated by
the net pI us CIAC investment.
In this way the Idaho jurisdictional costs that are
passed to Ms. Brilz for input into the class
cost-of-service model will give the proper recognition to
the customers who made the contribution.
Please describe the content of Exhibit No.3 0 .
Exhibit No. 30 is the complete Jurisdictional
Separation Study detailing allocation of each component
of rate base, operating revenues and expenses by FERC
account resulting in the Idaho jurisdictional revenue
deficiency.The JSS is organized as follows:
Summary of Results
Table 1 - Electric Plant in Service
Table 2 - Accumulated Provision for
Depreciation and Amortization
Table 3 - Additions and Deductions to Rate
Base
Table 4 - Operating Revenues
Table 5 - Operation and Maintenance Expenses
Table 6 - Depreciation and Amortization
Expense
Table 7 - Taxes Other Than Income Taxes
570 OBENCHAIN
Idaho Power Company
Table 8 - Deferred Income Taxes and ITC
Table 9 - Federal Income Tax
Table 10 - State Income Tax
- -
Oregon
Table 11 - State Income Tax - Idaho and Other
Table 12 - Development of Labor Allocator
Table 13 - Summary of Allocation Factors
Table 14 - Summary of Distribution/CIAC
Allocation Factors
Table 15 - Summary of Allocation Factors-Ratios
Briefly describe the manner in which you
allocated Electric Plant In Service as shown in Table 1
of Exhibit No. 30.
Production plant has been allocated to all
jurisdictions on the basis of the average of the
monthly coincident peaks.The allocation of transmission
and distribution plant has been based on the same
methodology.
Would you describe the functional categories
used for allocation of transmission plant and
distribution substations?
A description of the functional categories used
for allocation of transmission and distribution
substations is as follows:
Transmission facilities are the facilities that
form the bulk power transmission system
571 OBENCHAIN
Idaho Power Company
together with transmission , step-up substation
facilities required to introduce the Company I
generation into the power supply system , which
include facilities rated at 500kv through 46kv.
Distribution facilities refer to lower voltage
lines and substation facilities that provide
localized service.
Direct assignments refer to facilities that are
identified as serving and paid by a specific
customer.
How have you allocated the Accumulated
Provision for Depreciation and Amortization of Other
Utility Plant shown on Table 2 of Exhibit No. 30?
Accumulated Provision for Depreciation has been
allocated among jurisdictions as shown on Table 2 of
Exhibit No. 30.The accumulated totals for each type of
production plant and for each primary plant account in
other functional groups are allocated on the basis of the
related plant account as allocated in Table
Amortization of Other Utility Plant has been
functionalized and then allocated on the basis of the
related plant items as allocated in Table
Please describe Table 3 of Exhibit No.3 0 .
Table 3 details the allocation of all other
572 OBENCHAIN
Idaho Power Company
additions to or deductions from rate base.Deductions
from rate base include Customer Advances for Construction
which have been directly assigned to the customers
(jurisdictions) and Accumulated Deferred Income Taxes
which are allocated by plant.Additions consist of
Materials and Supplies which have been functionalized and
allocated by the respective plant allocators; Fuel
Inventory which has been allocated on the basis of
energy; components of IERCO , the Company's fuel
subsidiary which are allocated on the basis of energy;
and the Investment in Conservation are all Idaho programs
and directly assigned to the Idaho jurisdiction.
Working Cash Allowance has been excluded from rate
base in accordance with the Commission I s previous orders.
All rate base items , with the exception of
Accumulated Deferred Income Taxes and the Investment in
Conservation Programs, reflect the average of 13 monthly
balances.
Please describe Table 4 of Exhibit No.3 0 .
Table 4 indicates adjusted Firm Operating
Revenues for each jurisdiction for the 12 months ending
December 31, 2003. Opportunity Sales represent non firm
energy sales to other utilities, the revenues from which
are credited to each jurisdiction in proportion to its
generation-level energy usage.
573 OBENCHAIN
Idaho Power Company
Other Operating Revenues are either allocated among
jurisdictions in a manner which offsets related
allocations of rate base, or, where a particular revenue
item may be identified with a specific jurisdiction , it
is directly assigned to the appropriate jurisdiction.
Briefly describe the methods by which O&M
expenses were allocated.
The allocation of each O&M expense is detailed
on Table 5 of Exhibit No. 30.In general , the basis for
each allocation may be readily interpreted from the
exhibi t, due to the fact that in most cases either
demands, those identified by a source code beginning with
a "D" prefix; energy use, those identified by a source
code beginning with an "E" prefix; or related plant,
those identified by a line number source code; serve as a
basis for the allocation.Customer-weighted allocation
factors,"CW", which recognize differences in customer
requirements, have been used in the allocation of certain
expense accounts.
In what manner are supervision and engineering
expenses treated throughout the allocation of O&M
expenses?
For the applicable expense account in each
functional group, the labor component is separately
allocated in accordance with the detail provided on pages
574 OBENCHAIN
Idaho Power Company
25 through 28 of Table 12 of Exhibit No. 30.The total
of allocated labor in each functional group becomes the
basis for the allocation of Supervision and Engineering
Expense.Total allocated labor expense serves the
additional purpose of allocating employee pensions and
other labor related taxes and expenses.Table 12 of
Exhibi t No.3 0 details the development of all the labor
related allocation factors used in this study.
Please describe Table 6 of Exhibit No.3 0 .
The allocation of Depreciation Expense and
Amortization of Limited Term Plant is set forth on Table
These expenses have been identified by type of
production plant or by primary plant account for other
functional plant groups.Allocation is then accomplished
on the basis of the related plant account as previously
allocated.
Please describe Table 7 of Exhibit No.3 0, and
the allocation of Taxes Other Than Income Taxes.
Taxes Other Than Income Taxes are treated
individually and are allocated in a manner consistent
with the bases by which the respective taxes are
assessed.
Please describe Table 8 of Exhibit No.3 0 .
The expenses shown on Table 8 consist of
Deferred Income Taxes and the Investment Tax Credit
575 OBENCHAIN
Idaho Power Company
Adj ustment .Both have been functionalized and allocated
on the basis of total allocated plant.Also summarized
576 OBENCHAIN 27a
Idaho Power Company
Table 8 are State and Federal Income Tax liabilities.
The income taxes shown on Table 8 as well as Tables 9, 10
and 11 were obtained from the Company I s Tax Department.
Please describe how you allocated Federal and
State Income Taxes shown on Tables 8, 9 , 10 and 11 of
Exhibit No. 30.
Total income taxes have not been allocated, per
see Instead, the respective tax bases have been
developed and taxes have been calculated directly for
each jurisdiction.Operating income before taxes
represents adjusted operating revenues less all adjusted
operating expenses treated heretofore with the exception
of deferred income taxes and investment tax credits.
Adj usted long term and other interest expenses are
allocated on total plant in order to develop net
operating income before taxes.From that point forward,
addi tions to or deductions from the respective tax bases
are allocated to each jurisdiction by net income before
taxes.In this manner , taxable income for each
jurisdiction is developed , and the appropriate tax rate
is applied.Final tax amounts result after the
allocation of adjustments and tax credits. All details
relating to the calculation of Federal , Oregon , Idaho and
Other state income taxes are found on Tables 9, 10 and
11.
577 OBENCHAIN
Idaho Power Company
Please describe Tables 12, 13, 14 and 15 of
Exhibit No. 30.
578 OBENCHAIN 28a
Idaho Power Company
Tables 12, 13, 14 and 15 of Exhibit No.3 0
contain a list of the allocation factors used in the
Jurisdictional Separation Study. Tables 12 , 13 , 14 and 15
of Exhibit No.3 0 contain the principal allocation
factors used in the study and the respective
jurisdictional values for each allocation factor.Table
14 of Exhibit No. 30 presents the ratios of the principal
allocation factors included in Table 13.
Please describe the development of the Idaho
Jurisdictional revenue deficiency.
The summary of results is presented on pages 1
and 2 of Exhibit No. 30.The development of the Idaho
jurisdictional revenue deficiency is presented in the
column entitled "Idaho IPUC" on page 1 of Exhibit No. 30.
As can be seen from this exhibit the Idaho net income of
$76,855,594 on line 24 results in a return on rate base
of 4.967 percent on line 25.Under the rate of return of
334 percent provided to me by Mr. Gribble, the
Company I s Idaho jurisdictional net income should be
$128,963,944 on line 30.This results in an earnings
deficiency of $52 108 350 on line 31.
What net -to-gross or incremental income tax
factor did you use in developing the Idaho jurisdictional
revenue deficiency?
As indicated on line 33 on page 1 of Exhibit
579 OBENCHAIN
Idaho Power Company
No. 30 , I used a composite incremental tax multiplier of
642 provided to me by the tax department, which
represents the use of the Federal effective tax rate of
32.795 percent, an Idaho effective tax rate of 5.
percent , an Oregon effective tax rate of 0.4 percent and
an Other state effective tax rate of 0.1 percent for
purposes of determining the Company I s Idaho
jurisdictional revenue.
What is the resulting Idaho jurisdictional
revenue deficiency?
The results of the Jurisdictional Separation
Study as shown on line 34 on page 1 of Exhibit No. 30,
indicate a total revenue deficiency of $85 561,910 for
the Idaho Retail Jurisdiction.This represents a
required 17.68 percent increase in normalized Idaho
jurisdictional revenues.
Please describe Exhibit No. 31.
Exhibit No. 31 is a six-page exhibit, which
provides a summary of allocation factors used in this
proceeding.
Does this conclude your testimony?
Yes, it does.
580 OBENCHAIN
Idaho Power Company
(The following proceedings were had in open
hearing.
MR. KLINE:And then Mr. Obenchain is
available for cross.
COMMISSIONER SMITH:Okay.Shall we start
wi th Ms. Nordstrom?
CROSS-EXAMINATION
BY MS. NORDSTROM:
Good afternoon.
Good afternoon.
Just a point clarification on your
testimony on page 30, there at the very end
Yes.
- - you talk about the composite incremental
tax multiplier.Is it correct to say that Idaho Power I
application used a composite incremental tax multiplier of
642 based on a federal effective tax rate of 32.795,
and an Idaho effective tax rate of 5. 9?
Correct.
MR. KLINE:Is your mic on, Phil?
THE WITNESS:I believe so.
MR. KLINE:Better get it closer.
couldn I t even hear you.
CSB REPORTING
Wilder, Idaho
581 OBENCHAIN (X)
Idaho Power Company83676
THE WITNESS:How s that?
BY MS. NORDSTROM:
that was an answer the affirmative?
Yes.
Okay.Thank you.
MS. NORDSTROM:With that clarification
Staff does not have any further questions.
COMMISSIONER SMITH:Mr. Budge.
MR. BUDGE:Thank you.I apologize , I
probably won't be quite that brief.
CROSS-EXAMINATION
BY MR. BUDGE:
Mr. Obenchain , you did the jurisdictional
separation study for the company; is that correct?
That I S correct.
And can you explain differences that exist
between the load in Oregon with that of Idaho, generally?
Can you be more specific?
Well , if there s a load growth in Oregon of
a magnitude that we're having in Idaho, and if so what
types of customers are experiencing growth in Oregon?
m probably not the correct person to
testify towards load-growth questions.
CSB REPORTING
Wilder , Idaho
582 OBENCHAIN (X)
Idaho Power Company83676
Okay.In your Exhibit 31, which is a
jurisdictional separation study, did you use the same
CSB REPORTING
Wilder, Idaho
demand and energy data that Mrs. Brilz did in her cost of
Exhibi t 31 or Exhibi t 30?
I thought it was Exhibit 31.Your
service study?
jurisdiction separation study.
That I s Exhibit 30.
30?Was it the same demand andExcuse me.
energy data Mrs. Brilz used in her cost of service study?
I used the same demand and energy at the
jurisdictional level.Ms. Brilz breaks it down and uses
class information.
And did you use the same normal i zed energy
values that Mrs. Brilz used and Mr. Said used?
, again, I used the same load information
that Mr. Said uses, and the same sales
- -
that are derived
from the same sales information for the jurisdiction.
And you used normalized energy for purposes
Correct.
And that was the same as the other Company
witnesses, Mrs. Brilz and Mr. Said, did , I believe?
That I S correct.
By using normalized energy, isn I t it true
of your study?
583 OBENCHAIN (X)
Idaho Power Company83676
that the revenue over the 2003 test year is greatly
reduced because you had fewer sales on a normalized basis
than on an actual basis?
I I m not aware that no.
The load growth during the test year that
would not be reflected in the normalized numbers?
Well , the normalization is not - - does not
- -
is not a reflection of load growth.Normalization is
for weather not load growth.
Did you , or any of the Company witnesses,
normalize the 2003 demands?
We don I t weather-normalize demands.
Is it true that as you reflect back , if you
know , on what happened in 2003 was that not an extremely
hot year that the irrigation load and the air conditioning
load would have been very high compared to normal?
You probably need to get more into these
with Mr. Said.I I m probably not the correct witness to
talk loads.
Mr. Said would be the one?
Or Ms. Brilz when you start to talk load
information.
When you used your demand values for
purposes of your study, were those numbers found in the
FERC Form I?
CSB REPORTING
Wilder , Idaho
584 OBENCHAIN (X)
Idaho Power Company83676
No, they are not.
Pardon?They re not?
No.
What was the source of those numbers that
you used for your study?
The demand - - the demand allocators are
generated wi thin the Company using coincident peak data.
And they, for this test year, they were derived utilizing
the 2002 coincident peak information updated for known
changes, as I said in my testimony.
And were the Idaho jurisdiction demand
val ues derived in the same fashion?
Yes.
On page 19,bel ieve,your testimony,
on lines 1 through 8 , you indicate that you used and have
been using this 12CP method for allocating costs between
the jurisdictions for some 25 years.My question is, do
you believe that this is a good allocation method or are
you suggesting it simply because it is what has been used
for the 25-year period?
I believe it I S a good method for allocating
production costs , yes.And actually for all plant costs;
production, demand - - production , transmission and
distribution costs.
If there are capacity shortfalls as Mrs.
CSB REPORTING
Wilder , Idaho
585 OBENCHAIN (X)
Idaho Power Company83676
Brilz suggests , and cost responsibilities should be
allocated in order to reflect those cost responsibilities
then shouldn t that cost responsibility be reflected on a
system basis as opposed to just on a jurisdictional basis?
Can you repeat that, please?
My question was , if there are capacity
shortfalls and if cost responsibility should be allocated
in order to reflect those cost responsibilities, which is
what I understood Mrs. Brilz had testified to, then
shouldn't that cost responsibility be reflected on a
system basis as well as on a jurisdictional basis?
I I m sorry, but I really don't understand
your quest ion, so
Let me go at it a little different.If --
let me ask you this.Under the 12CP method that you used
for your jurisdiction separation study, you say at the
time the January monthly peak would have been used as a
part of your study to allocate costs to Idaho; correct?
January would have been one of the months you looked at?
The way - - the way the peak demand
allocation factor is calculated is we use an average of
twelve coincident peaks.So you take the coincident peak
in January, which is that jurisdiction I s peak at the time
of the system peak for the January month.And you add
that to each month , and then the average.And so it I S
CSB REPORTING
Wilder , Idaho
586 OBENCHAIN (X)
Idaho Power Company83676
it I s the annual -- it I s just one number.
So the month - - the numbers for the months
of January were
CSB REPORTING
Wilder , Idaho
Go into the calculation.
- -
part of the calculation of your study?
Yes.
Okay.And the same could be said with the
numbers for the month of February?
Yes.
that matter.
how this works.
Correct?And all other twelve months for
I 1 m just trying to make sure I understand
All months are in the calculation.
So if the customer uses electricity at the
time of the January system peak , or the February system
peak , this adds to Idaho I s cost responsibility for
purposes of your jurisdictional allocation study; correct?
They get a share of the system costs.
But that particular customer would not get
charged any costs in the Company's cost -of - service study
presented by Mrs. Brilz for the customer classes because
there's a zero responsibility assigned in January and
February; is that correct?
You would have to ask Ms. Brilz that
question.
587 OBENCHAIN (X)
Idaho Power Company83676
It I S my understanding that there's been
considerable increases in the company I s distribution plant
CSB REPORTING
Wilder, Idaho
since the last case.
I believe there s been considerable
increase in all plants since the last rate case.
Was that yes?
Yes.
Okay.And do you use a 12CP method to
allocate these distribution costs between the
Yes.
jurisdictions?
They're not allocated -- excuse me,
they re not directly assigned to use the 12CP method to
Some distribution plant is directly
allocate
assigned.It depends on - - there are some customers that
have directly assigned plant both in the distribution
category.
So those get directly assigned to whichever
jurisdiction that incurs them?
Yes.
Why is that direct assignment used as
opposed to the 12CP method when we come to distribution
There was some contracts that were done
costs?
588 OBENCHAIN (X)
Idaho Power Company83676
for
- -
there was some BPA transmission contracts that
were done.
MR. KLINE:Phil, for the reporter'
benefit, wait until Mr. Budge has finished his question
before you start answering it.
THE WITNESS:m sorry.
MR. KLINE:It I S pretty tough for her to
cover both of them.
THE WITNESS:m sorry.
BY MR. BUDGE:
Let me repeat that.Could you just explain
the reason why the Company chooses to directly assign
distribution costs as opposed to using the 12CP method?
There are only a couple of contracts that
there are specific facilities that were built for specific
customers for BPA transmission that the facilities are
directly assigned.
Can you explain , when we look at the
accounts 366 and 367 , which is underground conduit and
underground conductors , would you accept subj ect to check
that that account reflects an increase of almost 300
percent since the 1993 rate case?
MR. KLINE:m going to object.I think
that's more properly answered by Ms. Brilz , isn't it?
THE WITNESS:Probably.
CSB REPORTING
Wilder, Idaho
OBENCHAIN (X)
Idaho Power Company
589
83676
BY MR. BUDGE:
MR. BUDGE:I'll direct that to her.
Is that a matter that should be taken up
Yes.
Well , you're the one that did the
That's correct.
- -
allocation study.And that's what I'
When you look at the numbers on
- -
for the
- -
of the Company
CSB REPORTING
Wilder , Idaho
Uh-huh.
- - they reflect that you're using, they
reflect that these two accounts, 366 and 367 which is
underground condui t and underground conductors, have gone
up considerably now as to what they were in 1993; correct?
Will you accept that subj ect to check?
Subj ect to check.
m just simply asking you, are you able to
identify what has caused that considerable growth in those
particular expense accounts?
No.
That should be directed to Ms. Brilz?
Yes.
Let me get back to this final question.
with Mrs. Brilz?
jurisdiction --
referring to.
590 OBENCHAIN (X)
Idaho Power Company83676
Would it be correct for me to say that by not using an
allocation method, but by using direct assignment, you
were not allocating costs to customers that are not
responsible for these increased costs, just as a matter of
general theory?
Which costs are you
. . .
When we're talking about the directed
the direct assignment of distribution plant as opposed to
using allocation costs?
On the examples that I was pointing to
earlier for BPA?
Yes.
I f you direct
MR. BUDGE:I have no further questions.
COMMISSIONER SMITH:Thank you, Mr. Budge.
Mr. Richardson.
MR . RI CHARDSON :No questions.
COMMISSIONER SMITH:Mr. Ward.
MR. WARD:I do have some , Madame Chair
and I have - - I'm still struggling with my pagination
problem.By the way, when I - - we got it not from
- -
got Mrs.
- -
Ms.Nordstrom'message,but we didn't
download from the Staff,didn I think it was
problem
- -
from the PUC.But we got the same way.
COMM I S S I ONER SMITH:Apparently.
CSB REPORTING
Wilder , Idaho
591 OBENCHAIN (X)
Idaho Power Company83676
MR. WARD:And also when I tried to
download the corrected version at noon , I can I t get it to
load.
COMMISSIONER SMITH:Well, if you need
further help, I I m sure we can get you the corrected copy.
MR. WARD:Okay.I I m going to struggle
along with it.
CROSS-EXAMINATION
BY MR. WARD:
Mr. Obenchain , I take it that -- that in
producing the various adjustments to rate base and net
income that you have discussed in your testimony and that
are included in your exhibits, that the idea was to try to
give an accurate representation of the relationship
between income and expenses during the test year.
I think that I s fair.
Now , if you turn to Exhibit 21, two pages
there, you have the columns that are listed one through
six.The first column , of course, is the unadjusted
numbers, the second column is normalizing adjustments , and
so on.Do you see those?
Yes, I do.
Now , when I turn over to page 2 under
CSB REPORTING
Wilder, Idaho
592 OBENCHAIN (X)
Idaho Power Company83676
annualizing adjustments , the very first item , I see that
there appears to be zero adjustment to operating revenues
for annualization; is that correct?
That's correct.
And then , of course, there's some other
adjustments in the other columns that you discussed in
your testimony.Now, I believe you were in the hearing
room earlier when Ms. Smith testified about the
annualization of expenses and rate base?
I was.
If you do not analyze revenues don't you
create a mismatch between rate base and expenses on one
hand , and revenues on another?
I don't believe so, no.
Were you here when Mr. Keen testified that
Idaho Power I s continuing to experience load growth this
morning?
Yes, I was.
If you had load growth at two-and-a-half to
three percent a year , all other things being equal,
doesn't that suggest you I re going to have revenue growth
in an equivalent amount?
All other things being equal that does.
And again, turning back to Exhibit 21 , I
see your total operating revenues there in line 31 are
CSB REPORTING
Wilder , Idaho
593 OBENCHAIN (X)
Idaho Power Company83676
listed as 589 million dollars.Now , that I s a system
number; is it not?
These are system numbers.
And the Idaho jurisdiction would be 90 plus
percent of that; correct?
About 95 percent.
Okay.Now , if, just to round it off, if we
take 550 million as the Idaho share, if I add
two-and-half percent
- -
or let I s make it easier.If I
add 3 percent for load growth and revenue growth to that
number , that I s a significant increase in income; is it
not?
It may be, but I think that the confusion
or the problem we're having is the premise of the
question.And that is , the annualization adj ustment that
we I re making here, we I re not annualizing all expenses to
the test year.We I re only annualizing a few expenses to
the test year.All the rest of the test year expense
levels are calculated through the test year for each
month.All the revenues through the test year are also
calculated throughout the test year.So those are
matched.
The annualizing adjustment is just for a
couple of specific items.We make many adj ustments to the
test year both revenue and expenses.I f you wanted to
CSB REPORTING
Wilder , Idaho
594 OBENCHAIN (X)
Idaho Power Company83676
match adjustments , you could look on a couple other
columns and look at normalizing adjustments and see that
we have a normalizing adjustment of 14.5 million in
revenues and a negative one of 42.So you don I t
necessarily match up adjustments to adjustments.You
match up the items that you re adjusting.Or - - so the
premise that you have to match up an annualizing amount
with an annualizing amount isn I t quite correct.
So I think the point that should be made is
we made certain annualizing and known and measurable
adjustments that we I ve always made before this Commission
for certain items that are appropriate to make to a test
year.And that I s all we've done.And they're items that
are going to be in effect when these rates go into effect.
Isn't it true that you have annualized the
entirety of rate base?
No, that is not true at all.We've only
annualized a couple of items.
That annualization amounts to 18 million
dollars in rate base; does it not?
The annualization adjustment was -- yes,
million.
To which we add another 13 million in known
measurable adj ustments; correct?
Correct.
CSB REPORTING
Wilder , Idaho
595 OBENCHAIN (X)
Idaho Power Company83676
are they not?
Those are fairly significant adj ustments,
Yes, they are.
And obviously, you don t have any known and
measurable adj ustments to revenue.
No, we do not.But none of those
adjustments to rate base are revenue-producing
CSB REPORTING
Wilder , Idaho
Well, that I s not your area of testimony; is
Maybe not.
If
- -
why would it be obj ectionable, Mr.
Obenchain , to match solely normalized revenue against test
year expenses without adj ustment?
Because you I re not including all of the
expenses that the company s going to face when those rates
And isn I t it also true that if you do that
you I re not including the actual revenues the Company'
going to receive when those rates go into effect?
Maybe or maybe not.I don I t know if you
adjustments.
it?
go into place.
know that.
MR. WARD:That's all I have.
COMMISSIONER SMITH:Thank you.
Mr. Gollomp.
596 OBENCHAIN (X)
Idaho Power Company83676
Commissioners?
MR . GOLLOMP:No quest ions.
COMMISSIONER SMITH:Mr. Purdy.
BY MR. KLINE:
MR. PURDY:I have none.Thank you.
COMMISSIONER SMITH:Mr. Eddie.
MR . EDD IE:None.Thank you.
COMMISSIONER SMITH:How about from the
Do you have redirect?
MR. KLINE:One question.
REDIRECT EXAMINATION
Mr. Obenchain , in your rebuttal testimony,
you will address the issues of the annualizing adjustments
CSB REPORTING
Wilder , Idaho
and the known and measurable adjustments; do you not?
Yes, I do.
Okay.So do you know something about them?
Yes, I do.
MR. KLINE:Okay, that I s all I have.
COMMISSIONER SMITH:Thank you very much.
THE WITNESS:Thank you.
(The witness left the stand.
COMMISSIONER SMITH:Mr. Kline.
MR. KLINE:Our next witness is Mr.
597 OBENCHAIN (Di)
Idaho Power Company83676
Prescot t .And Mr. Prescott is a rebuttal witness.So if
you've got your testimony separated into rebuttal and
direct , you need to go get the other book , as I just did.
COMMISSIONER SMITH:Go ahead.
PAUL PRESCOTT
produced as a witness at the instance of Idaho Power
CSB REPORTING
Wilder, Idaho
Company, having been first duly sworn, was examined and
testified as follows:
DIRECT EXAMINATION
Are you ready?
m ready.
Please state your name for the record.
John P. Prescot t .
Mr. Prescott, what is your position at
Idaho Power Company?
m the Vice-President of Power Supply.
Mr. Prescott, have you previously filed
pages of rebuttal testimony and one exhibit, Exhibit 69,
in this proceeding?
Yes , I did.
Mr. Prescott, do you have any corrections
BY MR.KLINE:
598 PRESCOTT (Di)
Idaho Power Company83676
that you need make to your rebuttal testimony?
do not.
were to ask you the same questions
that are contained in your rebuttal testimony today, would
your answers be the same?
They woul d .
MR. KLINE:Madame Chairman , I would
request that Mr. Prescott's rebuttal testimony be spread
on the record as if read and that Exhibit 69 be marked for
identification.
COMMISSIONER SMITH:Without objection, we
will spread the prefiled testimony of Mr. Prescott upon
the record as if read and identify Exhibit 69.
(The following prefiled rebuttal testimony
of Mr. Paul Prescott is spread upon the record.
CSB REPORTING
Wilder , Idaho
599 PRESCOTT (Di)
Idaho Power Company83676
Please state your name and business address.
My name is John P. Prescott and my business
address is 1221 West Idaho Street, Boise, Idaho 83702.
What is your position at Idaho Power Company?
I am the Vice President of Power Supply.
What is your educational background?
I graduated from Idaho State University in
pocatellb, Idaho in 1981 receiving a BS Degree in General
Engineering.In 1987, I received an MS Degree in
Electrical Engineering from the Uni versi ty of Idaho in
Moscow Idaho.I have done postgraduate work towards a
PhD in Mechanical Engineering and Energy Studies at the
Uni versi ty of Wales in Cardiff , UK.I successfully
completed the Advanced Management Program at the Harvard
Business School in 2003.I am currently licensed as a
Registered Professional Engineer in the states of Idaho
Wyoming, California, Nevada , Oregon, Washington , Montana
and Utah.
Please outline your professional experience.
I began my career at the Company in 1982 as a
communications engineer. I advanced through several
engineering and management positions in the areas of
power system operations and substation management.
directed the Company s R&D program focusing on
alternative energy systems from 1991 to 1994.In 1995 I
600 PRESCOTT, Di-Reb
Idaho Power Company
became the President of Stellar Dynamics, a wholly owned
subsidiary of the Company
601 PRESCOTT , Di - Reb 1a
Idaho Power Company
doing power control system engineering.I returned to
the Company in 1999 when I was selected to be the Vice
President of Generation.As my responsibilities
expanded , I was named the Vice President of Power Supply
in 2001.
What are your duties as the Vice President of
Power Supply?
In this role I am responsible for the safe,
reliable and cost effective supply of electricity to the
customers of the Company. This involves the operation and
maintenance of 17 hydroelectric proj ects, the Danskin
peaking plant and the Bennett Mountain peaking plant,
which is currently under construction.I al so manage the
Company I S interest in three coal fired generation plants
in Wyoming, Nevada and Oregon.I direct the Company I
efforts in resource planning, load forecasting, fuel
management , water management, transmission adequacy,
power market transactions, resource optimization and
hydro plant relicensing and compliance.
What topics will your testimony cover?
I will address the proposal that the Industrial
Customers of Idaho Power make through the testimony of
Dr. Reading that the Company should have canceled the
Danskin Power Plant in 2001 and his recommendation that
the Commission now remove the Danskin Power Plant fromrate base. I will also provide additional
602 PRESCOTT, Di-Reb
Idaho Power Company
information regarding Idaho Power I s cloud seeding program
and correct erroneous information the Commission Staff
apparently relied on to support its recommendation that
the Commission (1) exclude the Company's investment in
Woodhead Park from rate base and (2) exclude investment
the Company incurred in defense of its Federal Energy
Regulatory Commission (" FERC") Hells Canyon license
relating to the Biological Opinion.
DANSKIN
Please generally describe the Danskin Power
Plant.
The Danskin Power Plant consists of two
identical 45 MW Siemens-Westinghouse W251B12A natural
gas-fired combustion turbines and the associated
swi tchyard.The 12 -acre facility, constructed during the
summer of 2001 , is located northwest of Mountain Home
Idaho.In generally accepted industry parlance , the
Danskin Plant is referred to as a peaking facility.
such , the Danskin plant is primarily used to meet extreme
load conditions, which for Idaho Power Company usually
occur during the later afternoon or evening hours in mid
summer.
Idaho Power identified the near-term need for
peaking facilities in its 2000 Integrated Resource Plan
IRP"
).
In the 2000 IRP Idaho Power announced that the
Company would issue a Request For Proposals for a peaking
603 PRESCOTT, Di -Reb
Idaho Power Company
'.""
"'t
facility as a part of its 2000 IRP Near-Term Action Plan.
In July of 2001 in Order No. 28773 , in Case No.
IPC-01-, the Commission issued a Certificate of
Public Convenience and Necessity to Idaho Power for the
Danskin Power Plant.
What is a peaking facility?
The generally accepted attributes of a peaking
facility include relatively low capital (fixed) costs and
relatively high dispatch (variable) costs.It is also
generally assumed in the industry that a peaking facility
will operate at a relatively low capacity factor.
Figure 1 depicts a typical load duration curve.
peaking facility operates in the extreme upper left hand
portion of the curve.As indicated in Figure 1 , a
peaking facility is needed to meet demand for only a few
hours in a year.
Figure 1. Typical Load Duration Curve
Intermediate & Base Load Plants
Peaker
------------------------
Hours in Year 8760
604 PRESCOTT , Di-Reb
Idaho Power Company
What is meant by the term capacity factor?
For a power plant, the capacity factor is the
ratio of the plant's actual generation to the generation
that the plant could have produced if it had operated at
its rated capacity for the number of hours in the period
under consideration.
Are there any guidelines or general rules of
thumb as to capacity factors typically associated with a
peaking plant?
Yes , the Electric Power Research Institute'
("EPRI ") Technical Assessment Guide Volume 1: Electricity
Supply - 1993 provides this type of information.The
Technical Assessment Guide indicates that the capacity
factor for a peaking plant ranges between 1% and 20%
with a nominal value of 10%.The Technical Assessment
Guide explains that although the nominal value represents
a lifetime levelized value, actual capacity factors for
peaking plants may vary widely depending on a variety of
conditions.
What was Danskin' s capacity factor in 2002 and
2003?
Based on a capac i ty of 90 MW, Danskin I s
capacity factor in 2002 was 5.7% and in 2003 its capacity
factor was 5.5%.
Why is Idaho Power building peaking facilities?
605 PRESCOTT , Di-Reb
Idaho Power Company
Historically Idaho Power relied on its hydro
plants to supply peaking needs.As peak loads grew the
hydro system was no longer able to meet all of those
needs.
By 2000 it became apparent that the population
growth in the Idaho Power Company service territory and
the fact that most new residences and commercial building
were being equipped with air conditioning were leading to
increased energy consumption during the hot days of
summer.The increase in air conditioning load, combined
wi th Southern Idaho's strong irrigation load led to a
pronounced summer peak , and these conditions continue
today.Addi tionally, the interstate transmission system
that Idaho Power had historically used to import power in
times of critical need was being used to capacity.
became apparent that Idaho Power would need to construct
additional generation facilities within the Idaho Power
control area and near its load if Idaho Power was going
to continue to meet its growing summer load.Idaho Power
Company reiterated the need for peaking resources in the
2002 Integrated Resource Plan , and issued a Request for
Proposals for additional peaking resources in February
2003.Presently, TR2 (formerly Mountain View Power) is
constructing a 162 MW peaking facility for Idaho Power
Company, also in Mountain Home, known as the Bennett
606 PRESCOTT , Di -Reb
I daho Power Company
Mountain Power Plant.Preliminary analysis suggests that
additional peaking resources may well be one component of
the 2004 Integrated Resource Plan that will be filed in
the summer of 2004.
Has the Company kept the Commission and the
public advised of its need to construct peaking
generation facilities?
Yes.The Idaho Commission accepted both the
2000 and 2002 Integrated Resource Plans in which Idaho
Power Company identified simple-cycle natural gas-fired
combustion turbines as the most cost-effective generation
to meet the summer peak.The Commission has also granted
Idaho Power Certificates of Public Convenience and
Necessity for both the Danskin Plant as well as the
Bennett Mountain Plant that is currently under
construction.Both the IRPs and the Certificate cases
were public processes with significant opportunity for
public comment.
Please describe the summer peak conditions that
the Danskin Power Plant is designed to address.
Idaho Power Company experienced its all-time
system peak of 2963 MW during record heat in July 2002.
In July 2003, the system peak was 2944.The summer peak
may well exceed 3000 MW this summer.The summer peaks
are very short in duration.In 2003 there were only
607 PRESCOTT , Di-Reb
Idaho Power Company
seven hours where the system load was 2900 MW or greater.
In 2002 there
608 PRESCOTT , Di-Reb 7a
Idaho Power Company
were only nine hours where the load was 2900 MW or
greater.
The winter peaks are far different.During the 2002
- 2003 winter , the maximum system load never even reached
2000 MW.During this past winter , the maximum system
peak was just under 2200 MW.
What is the daily duration of the summer system
peak?
The daily peaks are often quite short.For
example, on the peak day last summer, there were three
hours where the load exceeded 2900 MW and eight hours
where the load was 2800 MW or greater.The minimum load
on that day was just under 1900 MW.
The peak load on that day was over 2900 MW and
the minimum load was under 1900 MW.Are you saying that
there is a difference of over 1000 MW between the daily
peak and the daily minimum?
Yes.In fact, the difference was nearly 1100
MW.The peak of 2944 MW was 1.55 times the minimum load
of 1894 MW.The Idaho Power load varies considerably
over the course of a summer day.
How does Idaho Power operate Danskin during the
summer peak condi t ions?
It is important to understand that Danskin is
Idaho Power's resource of last resort.Idaho Power only
609 PRESCOTT , Di-Reb
Idaho Power Company
operates Danskin when it can be economically dispatched
into
610 PRESCOTT , Di-Reb 8a
Idaho Power Company
the market, or when operation is deemed necessary to
support system reliability, or when there are no other
options to serve load.Typically, Idaho Power Company
first meets load with its own low-cost resources
including the hydro system and its partial ownership in
three coal-fired plants.Second , Idaho Power will use
the transmission system and purchase additional energy
from the wholesale markets.Third , Idaho Power uses its
load-control programs such as the pilot AC program and
the pilot irrigation program.Fourth, Idaho Power uses
its natural gas-fired peaking resources including Danskin
and in 2005, Bennett Mountain to meet load.In this
phase Idaho Power may also work with large industrial and
other customers to see if cost-effective curtailments can
be arranged.Finally, if all of this fails, Idaho Power
may be required to pursue the load-curtailment program on
file with the Commission to involuntarily shut off
customers to stabilize the system.The Danskin Power
Plant only operates when all of the other resources
generation , transmission , and in the future, expanded
load-control programs, are operating at capacity.
In both the 2000 and 2002 IRP's, Idaho Power Company
identified simple-cycle natural gas-fired combustion
turbines as the most cost-effective generation to meet
the summer peak.Even though the fuel cost can be high
611 PRESCOTT , Di-Reb
Idaho Power Company
the fact that the turbines are only operated during a few
hours
612 PRESCOTT , Di-Reb 9a
Idaho Power Company
of the year and the fact that the capital costs are
relatively low , and the fact that Idaho Power uses the
facilities during the times of critical summer peak or
winter peaks, for reliability or those times when it can
be economically dispatched into the market, makes plants
such as the Danskin Plant a very prudent choice.
You said that Danskin was the II resource of last
resort II , what does that mean?
The resource of last resort means that Idaho
Power Company operates Danskin when there is no
transmission available or when market prices are so high
that market purchases are unattractive.The Company'
transmission constraints are real.Power may be
available at the mid-Columbia market , but Idaho Power
Company may have no way to get the power into our system.
In the summer the transmission lines from the Northwest,
Montana and Nevada are often operating at full capacity
and there is no more space available for imports into the
Idaho Power Control Area to serve peak loads.The
Company may, at times , be able to import additional power
from the eastern side of its system.However , from a
planning perspective, the Company does not like to rely
on purchases from the east for several reasons.The
first concern is the actual availability of supply on the
east. There is not much of a market on the eastern side
of Idaho Power I s system. Second, if power is
613 PRESCOTT , Di-Reb
Idaho Power Company
available on the eastern side of the system, it is
typically higher in price than northwest markets.The
third reason that Idaho Power does not like to rely on
purchasing from the eastern side of the system is because
of PacifiCorp' s two-thirds ownership in the Jim Bridger
Plant.If a Jim Bridger unit trips, PacifiCorp will be
looking to replace twice as much supply as Idaho Power
will, potentially leading to shortages on the eastern
side of the system.
Could Idaho Power improve the transmission
system?
Transmission improvements are possible,
al though transmission construction can be very costly and
rights-of-way difficult and time consuming to obtain.
spi te of these problems, Idaho Power is currently
pursuing certain transmission upgrades that could provide
some additional import capability in the next several
years.
Can Idaho Power Company meet the summer peak
load with load-control programs?
The load control programs certainly look
promising, but the programs are only part of the
solution.During summer peak conditions, a properly
sized residential AC unit may be on constantly during the
peak hours.The residential AC program cycles
614 PRESCOTT , Di-Reb
Idaho Power Company
residential air conditioners so that the compressors are
on half the time and off half of the time - the program
lowers the AC peak demand of the
615 PRESCOTT , Di - Reb 11a
Idaho Power Company
house by half.In ballpark figures, if Idaho Power
Company adds 10,000 new residential per year , Idaho Power
Company would have to enroll 20,000 residential customers
in the AC load control program to offset the AC load from
the 10 000 new customers.Load control programs are
expected to become a valuable part of the portfolio, but
Idaho Power will still need the Danskin Power Plant to
reliably meet peak loads.
Does Idaho Power Company operate the Danskin
Plant to profit from off-system sales?
The Danskin Power Plant was built to supply
native load.However , like any generating resource,
Idaho Power has the option to run the Danskin Plant
during times when the energy from the plant is surplus
and can be sold at a profit.In those cases , the bulk of
the profits would be returned to the Idaho Power
customers through the annual Power Cost Adj ustment .
Dr. Reading I s testimony focuses on the high
costs of the Danskin Power Plant.How do you explain
those costs in terms of the decision to build and operate
Danskin?
First , no one should be surprised that the per
MWh cost of a peaking plant is greater than a base load
plant.Second , as the Commission noted in Order No.
28733 when it issued the Certificate of Public
616 PRESCOTT , Di-Reb
Idaho Power Company
Convenience and Necessity for Danskin, the standard for
evaluating the decision to proceed with Danskin must be
viewed in the
617 PRESCOTT , Di -Reb 12a
Idaho Power Company
context of the facts known at that time.When the
decision to build Danskin was made the market price of
power was high.In February of 2001 Mid-Columbia forward
prices for August through December 2001 were $350
$415/MWh for heavy load hours, and $275 to $300/MWh for
ight load hours.Therefore, Danskin was considered
valuable for its peaking attributes and for its II in the
money" status which would have served to lower power
supply costs to the retail customer.Gi ven these forward
prices , Danskin would have likely operated at full load
for the remainder of 2001.In fact, given gas and power
prices in the winter of 2001 , Danskin's operation could
have reduced net power supply costs to Idaho Power'
customers by about $15 million dollars per month.Given
these market conditions and Idaho Power I s potential
exposure , a down payment on the turbines was made in
early February 2001 and the purchase was completed by
mid-March 2001. The market subsequently changed but the
proj ect was continued based on the need for a true
peaking resource.
Dr. Reading is critical of the Company
estimates of the number of hours Danskin will operate.
Is this criticism valid?
No.The decision to build Danskin was driven
by the fact that the Company has an obligation to serve
618 PRESCOTT , Di -Reb
Idaho Power Company
its customers even if inbound transmission constraints
blocked
619 PRESCOTT , Di-Reb 13a
Idaho Power Company
access to the open market during peak times.Therefore
the decision to build and operate Danskin was a low cost
option to maintain continuity of service and reliability
during those peak times when inbound transmission was
unavailable.In other words the attributes of a peaker
made Danskin a cost effective solution to the problem
i. e. a resource that has a relatively low capital cost,
relatively high operating costs and a low capacity factor
are desirous qualities.Dr Reading's comment
asking ratepayers to assume the costs of a plant that
will sit idle most of the time II is misleading when
considered in the context of the definition of a peaker.
The operation of a fire truck is an analogous example to
a peaker.It sits idle most of the time but has a
specific purpose of being ready to respond to infrequent
but critical situations.
Dr. Reading testifies that the Company should
have cancelled the Danskin Power Plant in the summer of
2001.Would it have been prudent for the Company to
cease construction of the proj ect after power prices
dropped in the summer of 2001?
There are several reasons why it would not have
been prudent or reasonable for Idaho Power to cease
Danskin construction as Dr. Reading now recommends.
First, Dr. Reading simply glosses over the fact that at
620 PRESCOTT , Di-Reb
Idaho Power Company
the time wholesale prices dropped in the summer of 2001
there was
621 PRESCOTT , Di -Reb 14a
Idaho Power Company
still tremendous uncertainty in the Western electricity
markets.While looking backward from today shows that
wholesale prices began decreasing in June of 2001, the
forward prices at that point were still abnormally high.
And forward price predictions were all the information
that was available in June of 2001.Additionally, there
was considerable uncertainty as to how long the
FERC- imposed price caps would remain in place and what
affect their removal might have on market prices.
Second , when one considers the extremely adverse water
conditions that existed in the fall of 2001 , canceling a
generation resource in the face of a very uncertain
wholesale market and transmission constraints would have
been very risky.In short , without the benefit of Dr.
Reading's 20/20 hindsight , I believe it would have been
extremely imprudent to abandon Danskin in midstream as
Dr. Reading urges.
In addition to the operating risk of
cancellation, would there have been financial
ramifications of cancellation in mid-stream?
Of course.By the end of June 2001 Idaho Power
had already incurred approximately $33.5 million in costs
associated with the Danskin Power Plant.That amount
represents approximately 65 percent of the total cost of
the proj ect In addition, cancellation would have
622 PRESCOTT , Di -Reb
Idaho Power Company
obligated the Company to pay substantial cancellation
charges to various
623 PRESCOTT , Di-Reb 15a
Idaho Power Company
contractors.Considering the uncertainty in water
conditions and the wholesale power markets at the time,
and considering the fact that approximately two-thirds of
total project costs had been incurred, plus the
additional costs that would be incurred to terminate the
proj ect, Dr. Reading's suggestion that the Company should
have cancelled the project and then requested recovery of
the costs from customers is patently unreasonable.
What would be the consequences of the Danskin
Power Plant being excluded from ratebase and removed from
service as suggested by Dr. Reading?
I am not qualified to address the ratemaking
and legal ramifications of such a decision.Mr. Gale and
Mr. Ripley will address those issues.I can say that as
the officer in charge of resource adequacy for Idaho
Power , that going into the summer of 2002 without
Danskin , the Company would have significantly increased
the risk of breaching its NERC reserve requirements and
significantly increased the risk of service curtailment.
In fact, during the 2003 peak summer season , even with
Danskin running at full output , the Company was unable to
maintain its desired reserve margins during some heavy
load hours, meaning that a single system contingency
would have required service curtailments.
Q. Are there other system benefits Danskin
provides besides meeting peak load demand?
624 PRESCOTT , Di -Reb
Idaho Power Company
Yes.Having a generating resource providing
vol tage support close to the load center of the Treasure
Valley helps to prevent a phenomenon known as voltage
collapse.This happens during periods of peak customer
demand when load is being served by generators remote to
the load center since the reactive power necessary to
maintain voltage is difficult to transmit over long
transmission lines.
Danskin also provides emergency reliability for the
system in the case of unplanned outages.
On page 5 of Dr. Reading's testimony, at lines
19 and 20 Dr. Reading states that the variable costs of
power produced from Danskin has varied between 60.2 cents
per kWh in 2001 and 29.7 cents per kWh in 2002.This
seems qui te high.Please comment on this?
I believe Dr. Reading inadvertently included
Danskin I s fixed costs in those calculations.In general
Danskin's variable costs of production can be
approximated by multiplying the delivered fuel cost in
$/MMBtu by the plant heat rate of approximately
MMBtu/MWh., for $4/MMBtu gas , the variable cost of
operating Danskin would be $48/MWh or 4.8 cents per kWh.
In reality, we would add several $/MWh for variable O&M
costs , but this approximation is close.
Did Danskin operate effectively to carry
625 PRESCOTT , Di-Reb
Idaho Power Company
customer loads during the peak summer months in 2002 and
2003?
Yes.During July of 2002 Danskinl s units
operated a total of 481 hours and during July of 2003
Danskin was operated a total of 567 hours.
Did Idaho Power depend on Danskin to serve its
peak loads during the summers of 2002 and 2003?
Absol utely.In fact, if the Danskin plant had
not been in-service and on-line during those peak months,
Idaho Power might not have been able to meet its
customers peak loads.
What is your future expectation for the
operation of Danskin?
Danskin will continue to dispatch to meet peak
loads and for reliability during the summer of 2004 and
beyond.While it is true that with the addition of the
new Bennett Mountain CT Danskin may dispatch less, it
will still dispatch during peak times when transmission
constraints are encountered, especially as peak load
grows over time.Summer peak load is growing on the
order of 80 to 85 MW per year as illustrated in Figure 2
below.
626 PRESCOTT , Di-Reb
Idaho Power Company
Figure 2. Forecasted Firm Summer Peak
Forecasted Firm Summer Peak
(megawatts)
~lii1l..-
000
------
M1I
;JAOO
UIlo
3..11)J..~
2800
----------
b6.JlJL-
-----
VJ..lJ..O
----
LB1i.ll.-
,1 600
--------------- - -----
2015198019851~'1I 1995 2000 2005 2010
Preliminary 2004 Integrated Resource Plan results
indicate that peak hour transmission deficits from the
Pacific Northwest continue to grow.Even wi th Danskin
and Bennett Mountain plants in operation, the projected
peak hour transmission deficits from the Pacific
Northwest reach 510 MW in 2010, and continue to grow in
subsequent years.Given the proj ected peak hour
transmission deficits, it is anticipated that the 2004
IRP will show a need for even more peaking resources
located inside of the Company I s control area near the
load.
WOODHEAD PARK
Staff Witness Leckie recommends that the
Commission defer the Company s $7,525,237 investment in
improvements made to Woodhead Park and include that
627 PRESCOTT , Di -Reb
Idaho Power Company
amount in Hells Canyon Complex relicensing costs for
recovery in the future.Recognizing that Idaho Power
wi tness Gale will address the ratemaking aspects of Mr.
Leckie I S recommendation , can you briefly explain why
Idaho Power invested in a substantial renovation of
Woodhead Park?
Mr. Leckie correctly notes that as a condition
of the Company's existing license, the FERC requires that
Idaho Power optimize and provide adequate recreational
opportunities for the public.Thus , Idaho Power must
adapt to changing needs for recreational and other
facilities on an ongoing basis throughout the license
period.
Crappie angling and harvest on Brownlee Reservoir
peaked in the late 1980 I S resulting in much more regional
attention (via newspaper articles, word-of -mouth , etc.
and more demand on the Company's recreational facilities
in Hells Canyon.In 1989, the Idaho Department of Fish
and Game reported that Brownlee Reservoir was the most
popular fishing pond in the state.It was estimated to
have had 851 749 hours of angling effort , as compared to
400 000 hours at the next most popular , Cascade
Reservoir.Fishing and associated camping was the most
popular recreational activity in the Hells Canyon Complex
(HCC) .
628 PRESCOTT , Di-Reb
Idaho Power Company
Woodhead Park is Idaho Power I s only park on Brownlee
629 PRESCOTT , Di-Reb 20a
Idaho Power Company
Reservoir.It was the least developed of all Idaho Power
camping facilities in the HCC.Woodhead Park was built
in the 1950's and not designed for large RVs, campers,
boats and trailers that were in use by the 1980 I
1990 the amount, type and needs of users had far
surpassed the facility's physical and functional
capabilities.Because of this situation , the park was
very congested , especially on weekends and holidays.The
Company received expressions of concern from the public
and special user groups (bass clubs , etc).
Immediate modern upgrades were needed.In order to
meet public expectations , upgraded facility requirements
incl uded:a dependable and more consistent potable water
supply; a wider and longer boat ramp with docking system
and adequate parking for trailers and vehicles; restrooms
to replace the existing pit toilets (all other parks had
restrooms with showers); a fish cleaning station instead
of using garbage cans; and upgraded electrical hookups.
Also, new federal regulations, i., the Americans
With Disabilities Act required changes to accommodate the
physically handicapped.Original Woodhead Park
facilities were not compliant.
Woodhead Park reconstruction was completed in 1996.
All features and facilities are utilized by the public.
Are the improvements at Woodhead Park
630 PRESCOTT , Di-Reb
Idaho Power Company
extensively used by the public?
Yes.In 2001 , usage statistics fee use
envelopes indicate 28 042 people camped at Woodhead Park.
This figure does not include day-use, which is mostly
associated with the boat ramp and fish cleaning
facilities.
Mr. Leckie argues that the investment in
Woodhead Park improvements should be deferred because
is tied to relicensing of Hells Canyon Complex.Did
upgrading Woodhead Park help reduce the potential demands
and costs associated with relicensing?
While the primary motivation for the
improvements was compliance with the existing FERC
license, in addition to meeting usage demands at the
time, there is no question that a significant benefit of
rebuilding the facility prior to relicensing was to
demonstrate responsiveness to public needs and moderate
requests for additional facilities at Woodhead Park
during the relicensing process.Idaho Power believes the
Memorandum of Understanding with Idaho Department of
Parks and Recreation (" IDPR") achieved this obj ective , as
IDPR did not request additional facilities other than
what was mutually agreed upon and proposed in the Final
License Application for the new HCC license.
Q. Mr. Leckie notes that the rate-based costs of
the Woodhead Park project are greater than originally
631 PRESCOTT , Di-Reb
Idaho Power Company
estimated in the Revised Exhibit R filed with the FERC in
November of 1990.Explain why the actual costs to
renovate Woodhead Park are greater than the costs
estimated in the Company's November 1990 FERC filing.
The anticipated costs noted in the revised
Exhibit R , $4 to $5 million , were based on preliminary
concept designs and estimated construction costs.The
pre-bid estimate, based on final design, was $6 million.
Bidding for the work was very competitive, with minimal
difference between the three lowest bidders.The
post-bid estimate of $6. 8 million included Idaho Power
overheads , interest during construction and adjustment
for a pre-bid estimate error in quantity of paving.
Because of low streamflow conditions in 1992 , Idaho Power
negotiated a contract modification and deferred for a
year most of the planned 1992 and 1993 construction
acti vi ties to minimize drought -year costs.The deferral
contributed to final costs exceeding earlier estimates.
Why is the Woodhead Park improvement investment
being depreciated over a period longer than the existing
license?
Though existing license obligations , as noted
previously, caused Idaho Power to upgrade Woodhead Park
the improvements have a useful life extending beyond the
license period.Idaho Power routinely makes prudent
632 PRESCOTT, Di-Reb
Idaho Power Company
reinvestments in its facilities based on the "going
concern" assumption.It is assumed that Idaho Power will
continue operating into the future and new licenses will
be issued to support that operation.Consequently,
capi tal investments depreciate over their useful life,
regardless of the license period in which they were made.
Capitalized costs incurred in obtaining a new license are
the exception and their depreciation period matches the
license period.
Does the Staff recommendation to exclude
Woodhead Park investment comply with standard regulatory
accounting practices?
I know that the term "used and useful II has a
specific meaning in regulatory practice.Speaking as an
engineer, there is no question that the Woodhead Park
improvements are complete , used and useful.In keeping
wi th the regulatory compact, it seems to me that prudent
investments that are currently used and useful should be
included in rate base.Excluding the investment from
rate base until HCC relicensing costs are addressed
ignores the fact that the improvements were done to meet
current license requirements, meet current public needs,
and are fully used and useful now.
Mr. Leckie recommends that the Company
investigate increasing user fees at Woodhead Park. Why
not raise the park fees to cover annual operation and
633 PRESCOTT , Di -Reb
Idaho Power Company
maintenance expenditures?
The FERC allows licensees to charge reasonable
fees to help defray the cost of operation and maintenance
of park facilities.Idaho Power sets fees based on rates
at comparable facilities and the public I s willingness to
pay.The Company reassesses its user fee structure
periodically and will increase fees consistent with the
above-described criteria.
Are there any other concerns you have wi
Staff's recommendation on Woodhead Park investment?
I believe that at a time when we are working
hard to build needed public support for relicensing the
Hells Canyon Complex , it is counterproductive to
discourage investment in visible , desirable and
appropriate improvements in recreation facilities in
Hells Canyon.
BIOLOGICAL OPINION
Staff Witness Leckie recommends that the
Commission remove $654 740 from the Company's rate base
attributable to capitalized expenses the Company incurred
in defending against a Sierra Club lawsuit relating to a
National Marine Fisheries "Biological Opinion. Is Mr.
Leckie's characterization of the facts surrounding the
biological opinion issue correct?
A. It is not entirely correct; however , I canunderstand how Mr. Leckie could misinterpret the facts
634 PRESCOTT , Di-Reb
Idaho Power Company
surrounding the expenditure of costs for this matter
because the facts are complex and his review was
apparently limited to a brief summary of the facts
provided by the Company in response to a Staff audit
request.Nevertheless , to fully understand this matter
some additional explanation is needed.
In the early 1990' s the National Marine Fisheries
Service ("NMFS ", now referred to as "NOAA Fisheries II or
"NOAA") listed several stocks of anadromous fish that
inhabit the lower Snake and Columbia Rivers under the
Endangered Species Act ("ESA"The Snake River sockeye
listed as endangered in 1991 and spring/summer and fall
chinook as threatened in 1992. Since those ESA listings
the Pacific Northwest has been engaged in a conflict over
the sustainable use of the natural resources that
influence the listed species , including the water
resources of the State of Idaho. Idaho Power finds itself
in the middle of this controversy largely because it owns
and operates 14 hydroelectric plants on the Snake River
that are situated geographically between the upper Snake
River Bureau of Reclamation (BoR) storage reservoirs and
the four lower Snake River Federal dams that many
consider to have brought the region's anadromous fish
resources to the brink of extinction. The largest of the
Company's facilities , and the one closest to the habitat
635 PRESCOTT , Di-Reb I daho Power Company
of the listed species, is the Hells Canyon Complex.
In March 1997 , the Sierra Club Legal Defense Fund,
on behalf of several environmental groups, sent a "notice
of intent to sue II for violation of the ESA to FERC and
NMFS threatening to file suit pursuant to ~ 11 (g) of the
ESA if FERC did not initiate consultation with NMFS
regarding the effect of ongoing operations of the HCC on
ESA listed anadromous fish. Thus began a long and complex
legal and technical battle over the alleged effect of
operations at the HCC on the listed species.
Why was this action of such great concern to
Idaho Power?
The environmental groups were attempting
through this action to force the FERC to reopen the
Company I S existing license for the HCC, and impose
operational changes to address alleged effects on the
listed species.Many of the changes supported by the
environmental groups would significantly reduce
operational flexibility and potentially impose millions
of dollars in additional operational costs and were not
supported by scientific research.These costs would have
begun in the year imposed and continue each year
throughout the remaining term of the existing Hells
Canyon Complex license and until a new license is issued.
The operational changes and associated costs , if imposed,would likely also continue into and
636 PRESCOTT, Di-Reb
Idaho Power Company
through the term of the new license.
Why did Idaho Power Company capitalize the
costs associated with defending the Hells Canyon Complex
license and its operational flexibility in this
Biological Opinion matter?
As noted previously, the intent of the
environmental groups' lawsuit was to force FERC to reopen
the current Hells Canyon Complex license and incorporate
restrictive modifications.Idaho Power s successful
defense of the integrity of the current license prevented
negative impacts to revenues and expenses in the test
year as well as years into the future.The multi-year
benefit was one factor for capitalizing the costs.
The Company's interpretation of CFR 18 Electric
Plant Instruction 3.8 and CFR 18 Electric Plant
Instruction 3.15 support the selected accounting
treatment.The Company also considered the accounting
treatment the Commission approved for the Nez Perce
settlement case, which is factually similar and cites the
same CFR provisions, as providing guidance and precedent
for the capitalization decision in this case.
What is the depreciation schedule for the
investment?
Costs to defend the operating integrity of the
license benefit the remaining life of the existing Hells
637 PRESCOTT , Di-Reb
Idaho Power Company
Canyon Complex license.The benefit will likely extend
into the period of annual licenses issued until the
relicensing process is complete and a new multi-year
license is issued.It is difficult to estimate how long
the relicensing process will take , but a conservative
estimate is three years beyond expiration of the current
license.Therefore , a depreciation period of 52 months
(March 2004 through June 2008) is being used for the
investment.The start of the depreciation was delayed
due to a misunderstanding regarding the Biological
Opinion I s costs and their link to HCC relicensing.Based
on this schedule , monthly depreciation expense is
$12 591; annual depreciation is $151,092.
Do you have any final thoughts on this issue?
It seems clear to me that this investment will
have a long-term positive effect on the Hells Canyon
Proj ect and should be included in the Company s rate
base.
CLOUD SEEDING
Staff Witness Hessing testified that additional
information is needed for the Staff and Commission to
adequately assess the reasonableness of including
expenses associated with the Company s ongoing cloud
seeding program in test year expenses.Could you please
address the Company's ongoing cloud seeding program?
638 PRESCOTT , Di-Reb
Idaho Power Company
Yes , I can.In his testimony Mr. Hessing poses
four questions relating to cloud seeding.In my
639 PRESCOTT , Di-Reb 29a
Idaho Power Company
response I will initially respond to Mr. Hessing'
characterization that cloud seeding is experimental and
somewhat controversial , and then I will answer his four
questions in the order posed.
On page 24 of his testimony Mr. Hessing states
that "Given the experimental and somewhat controversial
nature of cloud seeding programs Is cloud seeding
experimental?
There is no question that cloud seeding is
somewhat controversial and experimentation is ongoing.
However , cloud seeding has gone beyond the experimental
stage.Experimentation continues in the field of weather
modification , but the field is no more II experimental"
than say, an experimental aircraft.It works, but there
is room for improvement.While admittedly there is
controversy, the World Meteorological Organization , the
American Meteorological Society, the Weather Modification
Association, and the American Society of Civil Engineers
all acknowledge or have published statements indicating a
properly conducted cloud seeding proj ect can produce
significant results.
Idaho Power s interest in cloud seeding is to
augment snow pack , and ultimately hydroelectric
generation.Due to the interest in snow, the proj ect
focuses on wintertime cloud seeding.Idaho Power
640 PRESCOTT , Di-Reb
Idaho Power Company
recognizes that to be effective , a cloud seeding proj ect
must be properly conducted.Idaho Powe r ha s and is
making significant efforts to ensure that the project is
properly conducted to assure the anticipated benefits.
Mr. Hessing's first question is:What
acti vi ties constituted the cloud seeding program in past
years, including the test year , and what are the
Company's cloud seeding plans for upcoming years?Please
answer this question.
Idaho Power began investigating whether or not
cloud seeding might be a beneficial tool in the early
1990 I By 1995, there was enough positive evidence to
convince the Company to make a focused investigation as
to the "meteorological receptiveness" of the Payette
River Basin to cloud seeding efforts.In conj unction
with the Desert Research Institute (II DRI "), an adj unct of
the University of Nevada , the weather and climatology of
the area were investigated.That inquiry provided the
impetus for what can be considered the seeding program
in past years.
A contract was awarded to Atmospherics Incorporated
(AI, Fresno , CA) for an operational cloud seeding effort
on the Payette River Basin during the winter of 1996-97.
The winter got off to an extremely warm and wet start.
Therefore , the effort was suspended in December 1996.
641 PRESCOTT , Di-Reb
Idaho Power Company
Following the suspension of operations in 1996 , the
Company continued to evaluate cloud seeding.The
evaluation addressed two general areas of interest.
First , the Company kept abreast of existing and new cloud
seeding proj ects , research and developments.Second , the
evaluation focused on assessing the rewards and/or risks
to shareowners that result from funding a proj ect with
the purpose of reducing power supply costs with no clear
regulatory mechanism to equitably share the proj ect costs
and benefits between shareowners and customers.
Following several years of evaluation and discussions
wi th Commission Staff regarding proj ect cost, rewards and
risks , the Company committed to an in-house project in
2002.
In 2002 the Company hired a full-time meteorologist,
experienced in wintertime cloud seeding.Working wi th
consul tant who had been active in researching and
designing the proj ect, an operational program was again
initiated in late January of 2003.Seeding began on
February 1 and continued , when opportunities arose , until
April 15 , 2003.During that time, an aircraft specially
modified for cloud seeding and contracted from Weather
Modification , Inc.(WMI) of Fargo, ND flew for 22.3 hours
and seeded for 15.4 hours , releasing 23,207 grams of
seeding material silver iodide, AgI).A network of six
642 PRESCOTT , Di-Reb
Idaho Power Company
ground-based generators operated for 514.5 hours and
released an additional 10 288 grams of AgI.
643 PRESCOTT, Di -Reb 32a
Idaho Power Company
During the operational period , fifty-five weather
balloons were released within the watershed for
operational and research uses under a contract with
Technical and Business Systems , Inc. of Santa Rosa, CA.
Given favorable meteorological conditions, the plan
calls for an in-depth evaluation phase over the current
and the next winter seasons.A specially modified
aircraft , again acquired through a contract with WMI
releases both a tagged seeding agent (mixed AgI and
cesium iodide (CsI) and an inert tracer that has indium
(In) as the key ingredient.A second aircraft , available
for approximately two weeks and modified for cloud
physics research, will take samples of the aerosol and
particle size spectra , measure in-cloud moisture content,
and several other parameters to refine seeding procedures
and the formulae used for the seeding material.Weather
balloons will again be released from within the
watershed.Unlike last season , this task has been
assumed by the proj ect personnel , rather than undertaken
as a contracted service.The ground - based uni t s, again
consisting of six locations, each have two generators,
one releasing AgI, the second, the In tracer.This
combination will allow for sophisticated analyses of the
trace chemistry and help identify the relative impact and
merit of the two delivery methods (ground and aircraft)
644 PRESCOTT, Di-Reb
Idaho Power Company
Detailed density analysis of the snow samples will
provide
645 PRESCOTT , Di-Reb 33a
Idaho Power Company
an indication of proj ect yield and effectiveness.
Posi ti ve results from this investigation , being conducted
by DRI, are expected to support an on-going proj ect.
Negati ve results for the aircraft or ground based
component that cannot be adequately explained will likely
lead to cancellation of that piece of the program.
The DRI has initiated work this winter to evaluate
the proj ect using trace chemistry.Two sampl ing
expeditions have been completed so far and samples from
the first expedition have been analyzed.Preliminary
results from the first expedition show that the snow pack
at three sites in the basin contain layers containing
significant amounts of silver.These layers are also
enriched in silver relative to the rest of the snow pack
suggesting some contribution from silver iodide.
Estimates of the deposition dates of the enriched layers
are consistent with the records of silver iodide releases
from the ground and aircraft silver iodide generators.
The first expedition took place prior to releases of
cesium and indium and found an extremely low background
for these elements (at the parts per quadrillion to parts
per trill ion level), which means that the determination
of the tracers will be unambiguous.Additional
information regarding the preliminary results can be
found in Exhibit 69 to my testimony.
646 PRESCOTT, Di-Reb
Idaho Power Company
Mr. Hessing's second question is:What
criteria will the Company use to determine the level of
cloud seeding activity and expenditures necessary in any
given year?Please answer this question.
The level of seeding activity will vary with
the weather of the given season.During dry years , fewer
opportunities will arise (fewer storm systems), but they
will need to be worked for whatever benefit can be
gained.Expenditures might be somewhat lower during
these years , but the reduction is not expected to be
significant because of the extra effort involved in
seeding any and all storm systems.During wet years,
initial activity will be high because of more frequent
opportunities , but at the same time, it becomes more
likely that the proj ect' s suspension criteria will be met
or exceeded, leading to a secession of activity.Hence,
there would be higher costs early in the season and a
significant reduction later.During a normal winter
operations would be expected to be at or near the
budgeted level.In summary, costs should remain
relatively steady once the proj ect is through the startup
and evaluation phases.
Mr. Hessing I s third question is:How does the
Company evaluate whether cloud seeding works and that the
benefits exceed the costs?Please answer this question.
647 PRESCOTT, Di-Reb I daho Power Company
The evaluation phase of the Proj ect calls for a
sophisticated trace chemistry and snow density analysis,
648 PRESCOTT, Di-Reb 35a
Idaho Power Company
as outlined above.These analyses will allow Idaho Power
to evaluate the relative effectiveness of the two
delivery systems and differentiate between snow that
would have fallen naturally and that which resulted due
to seeding.The differences will allow a quantitative
evaluation of how much snow was produced during each
seeding event and over the course of the season.A copy
of preliminary results from the trace chemistry analysis
performed by the Desert Research Institute is attached as
Exhibit 69.
Under the original project plan, no evaluation of
effectiveness was intended during the first, start-up
year.However , pending the results of the trace
chemistry analysis , a preliminary, target/control
statistical analysis was conducted by Idaho Power
personnel not involved in seeding decisions.(This
analysis was indirectly confirmed by a similar analysis
of seeding acti vi ty on the adj acent Boise River watershed
by North American Weather Consultants) .The results
indicate that the seeding activity during the winter of
2002-03 resulted in a 13-19 percent increase in
precipitation in the Payette River Basin during the time
frame of active seeding.The most likely yield is 15-
percent.That would equate to approximately 110 000
acre-feet of water that would subsequently produce 55,000
649 PRESCOTT, Di-Reb
Idaho Power Company
MWh of electricity at Idaho Power's Hells Canyon Complex.
Using the average market price of electricity for
650 PRESCOTT , Di-Reb 36a
Idaho Power Company
2003 , the value of that power would be on the order of
$1.7 million , giving a benefit/cost ratio of -5: 1 for
the startup phase and a relatively brief period of
seeding operations.Once the costs associated with the
evaluation phase (note that costs associated with
assessment were not incurred during 2003 test year) are
removed from the budget , assuming a conservative ten
percent increase in precipitation yields a benefit/cost
ratio of -4: 1 given hydrologic conditions of 80 to 120
percent of normal precipitation.
Mr. Hessing's last question is:What would be
the effect on the Company's cloud seeding program if the
Commission denied recovery of the costs requested in this
case?Please answer this question.
Idaho Power believes that a properly operated
cloud seeding program will be a cost effective means of
increasing generation at existing hydroelectric
facilities.Conservative proj ections for a fully
implemented proj ect indicate a benefit cost of -4: 1, and
that the cloud seeding proj ect will provide on average
80,000 MWh of generation per year.Initial indications
as discussed above are that the proj ect provided a
positive benefit the first year , even with a shortened
operating period and expenses associated with startup and
implementation.And, as set out in Exhibit 69,
651 PRESCOTT, Di-Reb
Idaho Power Company
indications are that the project is having a positive
benefit on snow pack the second year as well.Efforts
are currently underway to assess the effectiveness of the
proj ect using trace chemistry and airborne cloud physics
analysis.Resul ts from the assessment are expected to
demonstrate the effectiveness of the proj ect , and provide
information useful to further refine the proj ect
configuration and operations.However , even wi th a very
attractive benefit cost ratio , without the ability to
recover costs on an ongoing basis, it is 1 ikely that
Idaho Power would not continue to pursue cloud seeding as
a water management tool and as a means of offsetting the
need to acquire additional generation.
Does this conclude your direct rebuttal
testimony?
Yes.
652 PRESCOTT, Di-Reb
Idaho Power Company
(The following proceedings were had in open
hearing. )
MR. KLINE:With that, Mr. Prescott is
available for cross.
COMMISSIONER SMITH:Mr. Eddie.
MR. EDDIE:No questions.
COMMISSIONER SMITH:Mr. Purdy.
MR. PURDY:I have none.
COMMISSIONER SMITH:Mr. Gollomp.
MR . GOLLOMP:No questions , ma' am.
COMMISSIONER SMITH:Mr. Ward, do you want
to wait until last?
MR. WARD:No.I have a working copy of
this testimony now.I can confidently cite page numbers.
CROSS-EXAMINATION
BY MR.WARD:
just have few Mr.Prescott.I f you
go to page lines 23 through 24.
Okay.
There you're report ing on Danskin' s
capacity factor in 2002 and 2003.My question is, do we
know how much of that percentage capacity factor was
attributable to native load?
CSB REPORTING
Wilder, Idaho
653 PRESCOTT (X)
Idaho Power Company83676
I don I t have the exact amount.It I s
certainly the majority of it.
Okay.But you don't - - do you have a feel
for how much it might have been operated for off-system
sales or opportunity sales?
No.When off-system sales are made, it'
not tied to a resource , it's a system sale.
I understand that.But you didn't -- in
short, you didn't investigate that issue?
I did not.
Okay.One other area.If you'd go to page
13 of your testimony.
Okay.
m looking at lines 3 through 9 and there
you're talking about the late 2001 period in which we
experienced extremely high prices.Do you see that
testimony?
I do.
And I take it the thrust of that testimony
is that with these sorts of prices staring the Company in
the face Danskin made sense to build.It was
economically sensible.
That was one of the reasons for it, yes.
And here's what I don't understand.I f you
thought - - presumably the Company thought there was a
CSB REPORTING
Wilder , Idaho
654 PRESCOTT (X)
Idaho Power Company83676
considerable risk or high probability that those sorts of
prices would continue forward for some period of time; is
that true?
Looking at the forward curves, yes.
But if you thought that , why wouldn't you
build a combined-cycle plant instead, which would maximize
your ability to make use of it for off-system opportunity
sales?
The concern at the time we made the
decision to go with Danskin was one of a peaking need
during the summer , possibly the winter.
I understand.But the peaking need that
you foresaw was relatively limited in terms of capacity
factor , but the motivating factor was really the prices
that you would have to pay for very short periods of time;
correct?
Again , as I said earlier , it was partially
that , and reliability.
I understand reliability concerns, of
course.But again , what am I missing?It seems to me
that the - - if you thought you were looking at prices like
this in the future you would build a plant that would not
only meet your peaking needs , but would also be available
for off - system sales at these sorts of prices which
suggests a combined-cycle plant; does it not?
CSB REPORTING
Wilder , Idaho
655 PRESCOTT (X)
Idaho Power Company83676
I can only speak to the need of Idaho Power
Company and its native load.And again , it was a peaking
requirement that we needed at the time.
I don't want to incur the Chair's wrath by
pressing on this repeatedly, but it seems to me , Mr.
Prescott, maybe you don't understand my question and I'
asking it badly.
All I'm asking is if I were in the
situation the Company was in then , looking at very
expensive market prices by anybody's definition , it seems
to me that the logical conclusion would be , yes, we have a
peaking need, but I also want to be able to maximize my
opportuni ty sales.
And my question is , doesn t that suggest
you would build a higher efficiency combined-cycle plant
like the Bennett plant , rather than the Danskin plant?
don't understand why the Company made that decision.
Well , first of all , the Bennett Mountain
Power proj ect is not a combined cycle proj ect .It is a
peaker as well.And a peaker is much less expensive to
built than a combined cycle project.So you re risking
more capital dollars to go combined cycle.
MR. WARD:That's all I have.
COMMISSIONER SMITH:Thank you.
Mr. Richardson.
CSB REPORTING
Wilder , Idaho
656 PRESCOTT (X)
Idaho Power Company83676
MR. RICHARDSON:Thank you , Madame
Chairman.
Just as a point of reference, Dr. Reading
has an exhibit in his direct testimony that answers the
question that the amount that Danskin is run for native
load versus off -system sales.So that's available in the
record.I'll get the exhibit number for it.It's in Dr.
Reading's exhibits.
CROSS-EXAMINATION
BY MR. RI CHARDSON :
Mr. Prescott , you testified that in 2003
there were only seven hours where the system peak was 2900
megawatts or higher; correct?That would be page 7 , lines
24 and 2 5 .
Okay.Yes.
And you also testified that there were only
nine hours in 2002 where the system peak was above 2000
2900 megawatts; correct?
Yes.
Now , isn't it true that your power supply
model shows Danskin will run only an average of ten hours
a year?
Which model are you referring to?
CSB REPORTING
Wilder , Idaho
657 PRESCOTT (X)
I daho Power Company83676
m referring to Mr. Said I s exhibit , No. 33
page 1 , line 12.
I donl t have that.I - - that model is Mr.
-- is involved with Mr. Said.I don't run that model,
so --
m just asking you if the Idaho Power
Company supply cost model shows that Danskin will run only
an average of ten hours a year?The reference is page 1
of Exhibit No. 33 at line 12.It shows Danskin running a
total of 804 megawatt hours per year.And since Danskin
is a 90 megawatt plant, if you divide 90 into 804 , you get
about ten hours.
Okay.
So do you actually believe that that power
supply model is accurate in predicting that Danskin' s only
going to run ten hours on average?
I can't speak to the accuracy of the model.
I do know that we plan to run Danskin beyond the ten hours
for 2004.
Did you read Mr. Sterling's testimony?
Yes, I did.
And do you recall he talks about accepting
the Company's normalized power supply costs proposed by
Idaho Power because they appear to be conservative?
Yes , I remember reading that.
CSB REPORTING
Wilder , Idaho
658 PRESCOTT (X)
Idaho Power Company83676
Is it possible , then , if the power supply
model is not accurately replicating the system that we
might be setting rates based on a model that isn I t valid?
I can't speak to the validity of the model.
You testified that the Danskin plant is a
resource of last resort; correct?
Yes.
And that's at page 10 of your testimony.
And by a resource of last resort, does that mean it's sort
of like an insurance policy for when there's no
transmission available , or when market prices are so high
that market purchases are unattractive?
In the parlance of dispatching utility
resources, it would be the last resource to dispatch , is
wha t that means.
When the Commission issued its Order
approving the Certificate of Public Convenience and
Necessi ty for Danskin it stated, and I quote, for
immediate future Idaho Power indicates that it intends to
operate the station 5140 hours per year; i.e., up to the
limit allowed by its air quality permit, end quote.
Do you think operating the unit at its maximum allowable
time that I s allowed by law is really a last resort unit?
In that scenario it was dispatching for
economic reasons.
CSB REPORTING
Wilder , Idaho
659 PRESCOTT (X)
Idaho Power Company83676
And Danskin hasn't been needed to run a
full 5000 hours a year as it was initially billed to this
Commission , has it?
year; correct?
That's correct.
In fact , it only runs about 500 hours a
I believe it ran 580 some hours in 2003.
Significantly below what the Commission
thought was going to run when granted you your
certificate convenience;correct?
was below what we estimated would
CSB REPORTING
Wilder , Idaho
You don't think 586 is significantly below
run.
5140?
Yes, it is.
Did the Company conduct an analysis of
making transmission improvements as an al ternati ve to
building CT peakers?
Yes.
And when you say that Danskin is the
Company's resource of last resort, that you operate it
when you've exhausted all other resources available to the
Company?
Generating resources, yes.
Now , on page 11 of your testimony, you
660 PRESCOTT (X)
Idaho Power Company83676
mention load control as an option to meeting summer peak;
correct?
Yes.
Now, the only load control option you
discussed in your testimony is an air conditioning
CSB REPORTING
Wilder, Idaho
recycling program
- -
air conditioner cycling program;
Yes.
correct?
And at the top of page 12 of your
testimony, you seem to dismiss this load control option as
not viable because you have to enroll so many new
participants.
intent in discussing that issue?
Is that a fair characterization of your
It is not.
Why do you - - what's the purpose of that
portion of your testimony?
The purpose was to indicate that our peak
demand is growing and that DSM is a part of meeting that
But you have to do additional work and
provide resources other than just load control because of
the growth of the peak load.
So you re actually implementing that air
peak demand.
conditioner cycling program at the rate of 10,000, 20 000
new residential customers?
m not familiar with the program directly.
661 PRESCOTT (X)
Idaho Power Company83676
But, no , it I S in the pilot phase right now.It I s
expanding into this air conditioning season , I do know
that.
Other than this pilot air conditioning
cycling program , you didn I t mention any other load control
potential to meet your peaking problems in the Treasure
Valley in your testimony.Did you ever , did you actively
consider an industrial load control program instead of
bui Iding Danskin?
Yes.Several things were investigated and
I believe that there was an another committee that
believe Ms. Brilz is involved in , to look at the different
demand side management options.And , yes, that was
considered.
So what was the result of that
consideration?
You'd have to check with Ms. Brilz on that.
So when you mention load control programs
you re only able to speak to the air conditioning load
control program?
It's the one I'm most familiar with.
What other load control programs did you
have in mind on page 11 , line 17 when you were answering
the question on load control programs that you considered
meet summer peak?
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Idaho Power Company83676
Irrigation.
So you have just the air conditioning
cycling, industrial , and irrigation?
Those are the ones I considered here not
just - - there's others that have been looked at by the
Company.
And those are the ones considered as
alternatives to Danskin?
Yes.
And I take it, obviously, since you built
Danskin , you rej ected all the other load control options?
No.That I S not correct.
Well , my question was , did you consider
those load control options as an al ternati ve to building
Danskin?
Now , Danskin' s obviously built, so I take
it that that means that you concluded that those load
control options would not have obviated the need to build
Danskin.
When we made the decision to build Danskin
we also implemented some load control programs including
an energy buyback from some of our large customers and the
irrigation customers as well.So they were implemented.
When you state that load control programs
are expected to become a viable part of the portfolio, can
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663 PRESCOTT (X)
Idaho Power Company83676
you tell me when that expectation is going to come to
fruition?
The process that we're using to implement
load control is through the integrated resource plan
, and
the energy efficiency advisory committee.So it's hoped
that the integrated resource plan that will be filed with
this Commission in June of this year , will have a
significant amount of load control in it , identified.
On page 12 , line 5, you say load control
programs are expected to become viable.So you didn'
have any time frame in mind for when that was going to
happen when you said that.The use of the word expected
to me implies some degree of certainty.
Again , it was based on the IRP process and
what we've learned to date in that IRP process with
customer input.
And the IRP process is a two-year process;
is it not?
It's a document that's filed every two
years with a ten year forward look.
And was the IRP process the process you
were going through to implement load control programs when
you looked at them as alternatives to Danskin?Were you
relying on the IRP process at that time as well?
At the time the decision was made to build
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Wilder , Idaho
664 PRESCOTT (X)
Idaho Power Company83676
Danskin we had the year 2000 IRP in process.
active IRP.
Tha t was the
And yes, it did envision some direct control.
But it didn't envision load control as on
the magnitude or the scale of the Danskin plant.
That I S correct.
And so you were relying on an IRP load
control program that couldn't have been an al ternati ve to
Danskin even if you wanted it to.
It was part of the solution.
Isn't it true that Idaho Power shareholders
would prefer that the Company see plants like Danskin
built and rate based , than load control programs?
There - - I believe that there is an
obligation on our part to investigate the least-cost
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Wilder , Idaho
option to the customers.
And you think Danskin was a least cost
option?
At the time of the information we had, yes.
Are you familiar with the Company'
time-of -use pricing filing with this Commission?
, I am not.
Okay.
MR. RICHARDSON:Madame Chairman , I 1
handing out a document that I'd like to see marked as
Exhibit 216.
665 PRESCOTT (X)
Idaho Power Company83676
(Industrial Customers of Idaho Power
Exhibit No. 216 was marked for identification.
BY MR. RI CHARDSON :
So are you totally unfamiliar with the
Company's investigation of the time-of -using pricing for
the residential class?
I do know that there was a study prepared.
So I guess you didn't consider time-of -use
pricing for the residential class as possibly an option to
Danskin?
Again , it wasn't my sole decision.I think
it involved other areas of the Company including the
Energy Efficiency Advisory Group.
Right.And you're in charge of power
supply for the Company.
Yes.
And so you're not aware of the magnitude of
the time-of-use pricing implications for power supply that
residential mandatory time of use could potentially bring
to the Company's load?
The way that works is that that part of the
Company under Ms. Brilz looks at those options and then
presents them into the IRP process.
MR. RICHARDSON:Madame Chairman , Exhibit
No. 216 is identified as Residential-Time-of-Use Pricing
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666 PRESCOTT (X)
Idaho Power Company83676
Viability Study report to the Idaho Public Utilities
Commission.And I suppose you could take official notice
of this if you wanted to, but I took the liberty of
marking it as an exhibi t .
BY MR. RICHARDSON:
And Mr. Prescott, have you ever seen this
document?
I have not.
Okay.Well , let's assume , since it is
filed with the Staff of the Commission by Idaho Power
that this document is what it purports to be.
Would you turn to page
MR. KLINE:Madame Chairman , I'm going to
object to this line of cross-examination.On three
separate occasions the witness has said he's not familiar
wi th time -of -use pricing.He's never seen this document.
And now we're going to have cross-examination of this
witness on this document, recognizing that Ms. Brilz , who
is a witness in this case, is familiar with this document.
COMMISSIONER SMITH:Mr. Richardson.
MR . RI CHARDSON :Madame Chairman, first
all , I'm not proposing to cross-examine this witness on
this document.There is information in this document
that's highly relevant to the Company I S commitment to
load-control programs as it relates to meeting peak load
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667 PRESCOTT (X)
Idaho Power Company83676
in the valley.
Mr. Prescott is in change of power supply
for this Company.And meeting peak load in this valley is
critically important , it I s ostensibly what caused the
Company to build Danskin in the first place.And I just
want to get in the record evidence that Idaho Power
produced and filed in a different docket addressing
load-control options that might be relevant to a) the cost
of Danskin and b) the need for Danskin.
So I won't cross-examine him on anything in
the document , I'm just going to point out factual
information in the document and then ask him the
concluding question relative to Danskin.
MR. KLINE:m not sure I see a big
distinction between pointing out factual items in the
document and cross-examining the witness on what's in the
document.I think that's a distinction without a
difference.
And so again , I renew my objection.
MR. RICHARDSON:I note, Madame Chairman
m not going to ask him anything about what I s in the
document other than to identify it.
MR. KLINE:To what?
MR. RI CHARDSON :To identify it.
MR. KLINE:Identify the document?He just
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668 PRESCOTT (X)
Idaho Power Company83676
testified he's never seen it.
COMMISSIONER SMITH:Mr. Kline, I think Il
going to allow Mr. Richardson to ask the witness, you
know , if information that might be in here was something
he considered in his analysis of the issues that he
testified to.And if he goes too far , then you just
remind him.
MR. RICHARDSON:Thank you, Madame
Cha i rman .
BY MR. RI CHARDSON :
Mr. Prescott, would you turn to page 14 of
Exhibit 216?
Okay.
The second full paragraph on that page
speaks to - - would you read for us the first two sentences
of the second full paragraph?
Yes.Critical peak time-of-use pricing has
the potential to produce substantial benefits.
implemented on a mandatory basis.Such a pricing strategy
could produce peak load reductions on high cost days of
nearly 200 megawatts.
Thank you.
MR. RICHARDSON:So I just have to complete
the round here , Madame Chairman.This is the exhibit I'd
like marked as Exhibit 217.
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Wilder, Idaho
669 PRESCOTT (X)
Idaho Power Company83676
(Industrial Customers of Idaho Power
Exhibit No. 217 was marked for identification.
MR. RICHARDSON:And this is a letter
addressed to the Idaho Public Utilities Commission by Mr.
Barton Kline of Idaho Power Company, re case No.
IPC-E- 02 -12.And it's a cover letter which is a cover
letter for a report which is the Automated Meter Reading
Report, Idaho Power Company, May 2003.
BY MR. RICHARDSON:
Do you have that document, Exhibit No. 217
in front of you , Mr. Prescott?
I don't see a number on it , but , yes.
Well , I'm asking that it be marked as
Exhibit No. 217.
Okay.
And it's the document I just identified as
the May 9 letter from Mr. Kline.
Yes.
Okay.If you take that document and open
to the attached attachment.The cover letter is three
pages, the attachment is attached to it.On page 5 of the
attachment , which is Idaho Power Company's report on
automatic meter reading for the residential class, the
bottom of page 5 is a paragraph headed 2003 analysis
resul ts.Would you read that first sentence?
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Yes.The total initial capital cost for
identified four-year implementation of an AMR system is
CSB REPORTING
Wilder, Idaho
proj ected to be 86.5 million dollars.
So for 86.5 million dollars Idaho Power
could have acquired 200 megawatts of peak load reduction.
And bear with me, the math for that would come out to
about $432 a kilowatt.And have you done the math on what
Danskin comes out to on a per kilowatt basis?
Yes.
And how much is that?
It's approximately $538.
Okay.So this 200 megawatts is
significantly cheaper than Danskin; correct?
There is other considerations here and this
document, as I read it , came out in 2003.So I would
expect that the findings here would be included in the
Again , the process I explained a couple of
The $538 per kilowatt , does that include
2004 IRP.
times.
fuel?
No.
Does that include transmission costs?
Yes.
Does it include line losses?
No.
671 PRESCOTT (X)
Idaho Power Company83676
Does it include something I can't read that
my expert wrote
- -
volatility.Okay.
How many canal drops with generation
potentially exist in the Treasure Valley?
I don't know.
Has the Company ever done a comprehensive
analysis of the cogeneration and small power production
potential available to it in the Treasure Valley?
Not that I'm aware of.
Since Danskin-like plants appear to be the
Company's next resource for serving the Treasure Valley,
do you think it would be a good idea to increase the
avoided cost rates paid to QF I s to locate in the Treasure
Valley over and above the Company's system-wide avoided
cost rate?
Well , I disagree with the first part of
that question.The Danskin proj ect and Bennet t Mountain
are meant to serve the peak load.
Could you answer the last part of the
question for me?Do you think it would be a good idea to
attract resources to the Treasure Valley to have an adder
if you will , to the avoided cost rate for new QF resources
that locate in the Treasure Valley?
Not for the identified peaking needs.
There wasn't a preface to that question.
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Idaho Power Company83676
It was just a flat -out question.
I believe right now we have some of the
highest QF rates in the West.
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Wilder , Idaho
So I take it that's a no?
I believe they're adequate for development.
So I take it your answer is no?
No.
On page 15 you state that by June of 2001
forward prices for electricity were still high.And by
that I assume you mean that forward prices were still
enough to make Danskin in the money; correct?
Line 4.
What line are you reading?
There I S no specific line reference here.
Okay.Repeat the question again.
You state that by June of 2001 forward
prices for electricity were still high.And by that
assume you mean that forward prices were still high enough
to make Danskin in the money, or to keep Danskin in the
money?
The reference there was just an indication
that the prices were abnormally high for that period of
time as a forward price.
Well , they had
Meaning --
673 PRESCOTT (X)
Idaho Power Company83676
Are you f ini shed?
Yes.
Okay.Good.You stated they were
decreasing in June but they were still high.So did that
- -
did you conduct a new analysis of forward prices at
that time because of the fact they were decreasing?
We have ongoing ability to look at forward
prices.We don't do those on demand.We continue to look
at the forward prices.
The economic ramifications of wholesale
power prices in the $300 to $350 range , the economic
ramifications to that on the economy over the long term
would have been devastating, don't you think?
Yes.
And do you think that it was reasonable to
plan long term on the assumption that those types of
prices were going to be the norm?
Plan for what?
Danskin , for one.
As a peaker , yes.
So it was reasonable for you to plan new
resources on the assumption that prices were going to be
$300 a megawatt hour long term?
As I stated earlier , that was not the only
reason that the decision was made to build Danskin.
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674 PRESCOTT (X)
Idaho Power Company83676
At the bottom of page 15 you begin your
discussion of the cost of abandoning Danskin.You
mentioned that by June you had already spent 65 percent of
the cost on Danskin.But you do admit , don't you, that
the generators themselves could have been resold?
Yes.
And the generators represent probably a
significant portion of the cost of Danskin.
Tha t 's true.
And at that time there was probably a
robust market for just generators?
I don't know.
Well , with utilities planning to have $300
power going forward long term , you would assume there
would be a robust market for generators.
Yes.
Was there an analysis or detailed cost
study analysis done on abandoning Danskin at that time?
, because of the reliability concerns of
getting into the transmission reliability margin and the
capacity benefit margin on transmission.
You quote Dr. Reading, Dr. Reading I
estimates of what it would cost to run the Danskin plant
in 2001 and 2002 on a per kilowatt hour basis.And then
you say that he , quote, inadvertently included Danskin' s
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675 PRESCOTT (X)
Idaho Power Company83676
fixed costs in those calculations.And that's at page 17
line 16, if you need a reference.
I see.
Didn't Dr. Reading actually state that he
recognized that it would make sense to run the plant from
the Company's perspective once the fixed costs were sunk?
That's how a unit dispatch is , is based on
the variable cost, yes.
And Dr. Reading actually made that point in
his testimony; correct?
He did mention the sunk costs.
And didn't Dr. Reading also state that from
the rate payer's perspective , since they are being asked
to pay for both the fixed and the variable costs of the
plant in their rates , that both need to be considered by
this Commission in determining the prudence and
reasonableness of this investment?
The request before the Commission is for
the capital costs to be rate based.The variable costs
are covered through the PCA.
But they all end up out of the rate payers'
pocket; correct?
The PCA costs are , I believe, split 90/10.
You state at page 18 that were Danskin not
in service in the summers of 2002 and 2003 that Idaho
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676 PRESCOTT (X)
Idaho Power Company83676
Power might not have been able to meet its customers peak
load.
Don't you think that for about 50 million
dollars the Company could have bought some load
curtailment in those summers , especially since we're only
talking about a few hours a year?
Perhaps.
Did you read the Commission's Order
granting a certificate of public convenience and necessity
to Idaho Power for Danskin?
Yes, I did.
And do you recall the Commission stating
that li the Company needs to provide the Commission with
more information.What other al ternati ves were
considered?What was the Company's forecasted need?
Do you recall that phrase in the Commission's Orders?
I do.
And the Company never provided that
information to the Commission , did it?
That's correct.
The Commission still doesn't have what it
asked for , relative to the al ternati ves to Danskin and the
Company's forecasted needs.
Don't you think it would be justified in
denying rate making treatment, at least until you respond
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677 PRESCOTT (X)
Idaho Power Company83676
to the Commission I s requests?
No.I believe that we've responded through
my testimony and others.
MR. RICHARDSON:That's all I have, Madame
Chairman.Thank you.
COMMISSIONER SMITH:Thank you , Mr.
Richardson.
Mr. Budge, do you have quest ions?
MR. BUDGE:Thank you.Just a couple , if I
may.
CROSS-EXAMINATION
BY MR. BUDGE:
Mr. Prescott , would you turn to page 6 of
your testimony, please?
Okay.
Beginning at the top there on line 2 , you
state that historically, Idaho Power relied on its hydro
plants to supply peaking needs.And you go on in the next
paragraph and state that by 2000 through population
growth , new residences, commercial buildings, air
conditioning load had increased and you could no longer
meet that peak from hydro.
When you say in line 2 that historically,
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Idaho Power Company83676
Idaho Power relied on hydro to meet peak, what period are
you talking about?Before 2000 or some time prior to
that?
Before 2000.
Before 2000.And when, down on 1 ine 11
you refer to the term strong irrigation load.You say,
starting on line 10 , that the increase in air conditioning
load combined with Southern Idaho's strong irrigation load
led to a pronounced summer peak.
Is it accurate to say that there has been
no increase in the irrigation load since the last rate
case in 1993?
That I S not my area.
When you say strong irrigation load , what
are you referring to?
The existing irrigation load that's out
there, that happens to be coincident.
You weren't trying to imply or characterize
the existing load as being greater or less than what it
was historically at the time of the last rate case?
Not with my statement here , no.
If you would , please turn to page 8 , line
, and you make the statement there , quote , the daily
peaks or often quite short.
When you say quite short, generally or
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679 PRESCOTT (X)
Idaho Power Company83676
approximately what do you mean by quite short?Are we
talking minutes, or seconds, or hours?
If you continue to read the testimony there
it says three hours typically, where the loads exceed the
2900.So the duration, to give it some reference over
2900 , would be three hours in a day.
Those would be the time periods you
referred to when you say quite short?
Yes.
And what do you attribute that to, the fact
that the peak is of relatively short duration?
Again, I'm not a load expert, but I believe
it's the combined effect of air conditioning coming on all
at once, and irrigation pumping.
To your knowledge, do the irrigation pumps
basically turn on and stay on , or do they go on and off
during the day, if you know?
I don't know.
But insofar as the irrigation load
excuse me , the air conditioning load of a commercial
business , would it be accurate to say that they generally
turn on sometime during the business day, and off sometime
the end of the business day?
suspect that'true.
Would you suspect the same would be true
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680 PRESCOTT (X)
Idaho Power Company83676
wi th respect to residential load?It would be somewhat of
an on and off load for air conditioning purposes?
Yes.Different time frame , but yes.
So would you expect, if my assumptions are
correct , that that relatively short duration peak is also
attributable primarily to the air conditioning load as
opposed to the irrigation load?
I don I t know.I can't draw that
conclusion.
Thank you very much.
MR. BUDGE:No further questions.
COMMISSION SMITH:Does Staff have any?
How many do you have?
MS. NORDSTROM:Just a few questions.
COMMISSIONER SMITH:Okay.Ms. Nordstrom.
MS. NORDSTROM:Thank you.
CROSS-EXAMINATION
BY MS. NORDSTROM:
Starting on page 25 , you discuss costs
related to defending against the biological opinion and
the Sierra Club lawsuits related to that biological
opinion.On page 28 , on the latter half of the page , you
analogize these lawsuit defense costs to the capitalized
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681 PRESCOTT (X)
Idaho Power Company83676
costs of the Nez Perce settlement; is that correct?
Yes.
When formulating your opinion , did you
consider that the Company has expensed its Snake River
Basin adjudication legal costs that it incurred to protect
its water rights rather than capitalizing them?
That wasn't part of this analysis , no.
Thank you.Directing your attention to
page 38 in regards to cloud seeding.You testified that
the Company is unlikely to pursue cloud seeding further
without cost recovery.And thus included both expense and
capitalized costs in this application.
If the Commission were to grant fixed cost
recovery and base rates in this case, would the Company
obj ect to funding the actual variable cost portion through
the power cost adj ustment?
That's a question better asked of Mr. Said
that understands the PCA mechanism better than I do.
Thank you.
MS. NORDSTROM:No further questions.
COMMISSIONER SMITH:Do we have questions
from the Commission?
I just had one.
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EXAMINATION
BY COMMISSIONER SMITH:
Mr. Ward was trying to explore the
possibili ty of why you didn't put a combined cycle at
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Wilder, Idaho
Yes.
Danskin.
Do you recall those questions?
Yes.
And wasn't the case that Idaho Power
Company was maybe not in the business of selling power
during the time period it was considering Danskin?
Yes , Commissioner.That was not our point.
I mean , there was another sister company
under the holding company that was doing the power sales
at that time; correct?
Madame Cha i rman .
Correct.Into the market, yes.
All right.Thank you.
COMMISSIONER SMITH:Redirect?
MR. KLINE:I have two or three questions,
683 PRESCOTT (Com)
Idaho Power Company83676
REDIRECT EXAMINATION
BY MR. KLINE:
First of all , Mr. Richardson asked you a
number of questions about Danskin as a resource of last
resort.And he identified , and I believe you identified
that there were a couple of primary reasons why Danskin
would dispatch.That would be if there were transmission
constraints that made it difficult to import power from
the market.That's one of them; correct?
Yes.
And the other one is if there are really
high market prices; correct?
Yes.
Are there any other reasons why Danskin and
the ability to dispatch Danskin could be valuable for the
Company?m thinking specifically of voltage support and
those kind of things?
Absolutely.There's a phenomenon known as
voltage collapse which if you get a heavily loaded system,
usually over a peak time of the year , if you don't have
resources that you can dispatch not only megawatts but
megabars into the system , you can actually drive the
system into a blackout because of that phenomenon.Case
in point would be the Tokyo , classic example, July 23,
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684 PRESCOTT (Di)
Idaho Power Company83676
1987 where they had a full scale collapse, voltage
collapse based on the fact that they didn't have enough
resources with enough spinning megabars to support the
vol tage .
Mr. Richardson also spent some time asking
you questions about the Company s load control acti vi ties.
And looking back at 2001 , which was the time period in
which the decision to go forward with the Danskin project
was made , wasn't the Company very heavily involved in load
control proj ects at that time?
By all means.There's --
The irrigation buy-back program, you had
the Astaris program , you had
Yes.
- - purchases from Simplot.
That's correct.
It was not as if the Company was unaware of
its load control situation at the time it went ahead with
Danskin.
Yes.And that's best explained in Mr.
Sterling's testimony.
Mr. Richardson also introduced a couple of
exhibits both having to do with time _of use.And the one,
216, is dated -- which is the Residential time-Of-Use
Pricing Viability Study, is dated September 12 , 2002;
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685 PRESCOTT (Di)
Idaho Power Company83676
correct?
Yes.
And the second one, the AMR report, is
dated May of 2003; isn't that correct?
Yes.
And so as a , at the time that the decision
was made to move forward with Danskin in 2001 , neither one
of these reports had even been prepared; isn't that
correct?
That's correct.
Mr. Richardson also asked you about QF
development and QF rates.And isn't correct, Mr.
Prescott, that Idaho Power Company doesn't set QF rates,
this Commission does; isn't that right
That's my understanding.
And isn't it also true -- I'm sorry.And
Mr. Richardson also alluded to the possibility that the
Company could put a kicker on , or add additional price to
the QF rates in order to stimulate their development.But
aren't avoided cost rates supposed to be synonYmous with
the cost the Company would otherwise incur if it didn'
buy QF power?
That I S my understanding of how it works.
And so if you actually took the avoided
costs and put a kicker on it as Mr. - - or an adder as Mr.
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Idaho Power Company83676
Richardson described it , you would, in fact , be paying
more for energy from those proj ects than you could
purchase it , or generate it yourself in other resources;
isn't that right?
Yes , based on the avoided cost.
And you don't know whether that's lawful or
not?
MR. RI CHARDSON :Obj ection.It calls for a
legal opinion.
MR. KLINE:Wi thdrawn.That's all I have.
COMMISSIONER SMITH:Thank you.Thank you
Mr. Prescott.I think that brings us to the time for our
afternoon break and we'll reconvene at 3: 00.
(Brief recess.
COMMISSIONER SMITH:All right.Mr. Kline
we I re back on the record and ready for your next witness.
MR. KLINE:Thank you, Madame Chairman.
Actually, Ms. Moen is going to spread the testimony of
Mr. Said.
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687 PRESCOTT (Di)
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GREGORY W. SAID
produced as a witness at the instance of Idaho Power
Company, having been first duly sworn , was examined and
testified as follows:
BY MS. MOEN:
DIRECT EXAMINATION
Mr. Said, would you please state your full
name for the record?
Idaho Power?
Gregory W. Said.
And in what capacity are you employed by
m the Director of Revenue Requirement.
testimony in this matter?
And have you previously filed direct
I have.
written testimony that you prefiled?
Do you wish to make any corrections to the
No.
And does that testimony, that direct
testimony, include 24 pages along with Exhibits 32 to 36?
That's correct?
MS. MOEN:I request, Madame Chairman , that
the prefiled direct testimony of Gregory Said , consisting
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688 SAID (Di)
Idaho Power Company83676
of 24 pages , be spread on the record as if read in its
entirety.And that Exhibits 32 to 36 be marked for
identification.
COMMISSIONER SMITH:Without objection , it
is so ordered.
(The following prefiled direct testimony of
Mr. Gregory W. Said is spread upon the record.
CSB REPORTING
Wilder , Idaho
689 SAID (Di)
Idaho Power Company83676
Please state your name and business address.
My name is Gregory W. Said and my business
address is 1221 West Idaho Street, Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by Idaho Power Company as the
Manager of Revenue Requirement in the Pricing and
Regulatory Services Department.
Please describe your educational background.
In May of 1975 , I received a Bachelor of
Science Degree with honors from Boise State Uni versi ty.
In 1999, I attended the Public Utility Executives Course
at the University of Idaho.
Please describe your work experience with Idaho
Power Company.
I became employed by Idaho Power Company in
1980 as an analyst in the Resource Planning Department.
In 1985, the Company applied for a general revenue
requirement increase.I was the Company witness
addressing power supply expenses.
In August of 1989 , after nine years in the
Resource Planning Department, I was offered and
accepted a position in the Company I s Rate
Department.With the Company's application for a
temporary rate increase in 1992, my responsibilities
as a wi tness were expanded.While I
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Idaho Power Company
continued to be the Company witness concerning power
supply expenses , I also sponsored the Company's rate
computations and proposed tariff schedules in that case.
Because of my combined Resource Planning and Rate
Department experience, I was asked to design a Power Cost
Adjustment (PCA) which would impact customers' rates
based upon changes in the Company's net power supply
expenses.I presented my recommendations to the Idaho
Public Utilities Commission in 1992 at which time the
Commission established the PCA as an annual adjustment to
the Company's rates.I have sponsored the Company'
annual PCA adjustment in each of the years 1996 through
2003.
In 1996, I was promoted to Director of Revenue
Requirement.At year-end 2002 , I was promoted to the
senior management level of the Company.
What topics will you discuss in your testimony
in this proceeding?
I will discuss changes in loads and resources
since the Company's last general rate case and the impact
of those changes on the Company's power supply expenses.
I will sponsor the exhibits that provide the basis for
determining the Company I s normalized net power supply
expenses for ratemaking purposes.I will also discuss
how the new normalized power supply expenses impact
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Idaho Power Company
future PCA computations until the Company I s next general
rate case.
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Idaho Power Company
Please describe the change in the Company'
system loads since the last general rate case,
IPC-94-
The Company's 1993 annual normalized system
load used in the IPC-94-5 case was 14.5 million
megawatt- hours (MWh).The Company's 2003 annual
normalized system load used in this case is 14.1 million
MWh.The annual system load served today is
approximately the same as it was ten years ago.
Over the last ten years, what changes in loads
combined to result in a 2003 annual system load that is
so similar to the 1993 annual system load?
While there has been load growth within most
customer classes , the Company has also experienced load
decline in a couple of distinct areas.Ten years ago,
FMC was Idaho Power's single largest customer with a load
of 1.7 million MWh per year.FMC , which later became
known as Astaris, discontinued operation leaving only a
small residual industrial load being served as a Schedule
19 customer.Idaho Power also had some FERC
jurisdictional contract loads amounting to approximately
4 million MWh that were intended to be served by
surplus resources that existed at that time, but were
scheduled for discontinuance as the Company's state
jurisdictional loads grew to match generation capability.
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Idaho Power Company
As planned, those FERC jurisdictional contracts have
reached their conclusion.The
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1 million megawatt-hour reduction in annual system
loads have been replaced by 2.7 million MWh of load
growth wi thin other customer classes.
Has the monthly shape of the annual load
changed in the last ten years?
Yes.The FMC contract as well as the concluded
FERC contracts that existed ten years ago provided the
Company with relatively consistent monthly loads that
were somewhat flat throughout the year.The FMC load had
an interruptible component.Load growth wi thin the
various customer classes has tended to be much more
seasonal and dependent upon weather.As a resul t of the
loss of relatively flat loads and the addition of
non- interruptible seasonal loads, the Company'
Integrated Resource Plan now shows the need for summer
peaking resources (June , July, and August) and winter
peaking resources (November and December) .
Please define the term "power supply expenses
as the Company and the Commission have used the term
historically.
The Company and the Commission have used the
term "power supply expenses II to refer to the sum of fuel
expenses (FERC accounts 501 and 547) and purchased power
expenses (FERC account 555) excluding PURPA qualifying
facilities (QF) expenses minus surplus sales revenues
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Idaho Power Company
(FERC account 447) .For ratemaking purposes , QF expenses
have been quantified separately from other power supply
expenses and are treated as fixed inputs to power supply
modeling rather than variable outputs.
How would you expect power supply expenses to
be affected by the changes in loads, as you have
described, that resulted in approximately the same annual
load, but with seasonal shifts in loads and higher peak
hour requirements?
I would expect power supply expenses to rise as
a result of the seasonal and peak hour load shifts that
the Company has experienced over the last ten years.
Additional loads during the peak hours of the summer
season will need to be served by higher cost resources.
How have market prices of energy changed in the
last ten years?
Market prices for energy are generally higher
than market prices ten years ago.In the IPC-94-5 case
it was assumed that the highest monthly market price that
the Company might encounter would be $27 per MWh , which
is equivalent to 27 mills per kilowatt-hour (kWh) or 2.
cents per kWh.Ignoring the run-up in market prices that
occurred in the 2000-2001 time period , the Company has
routinely seen market prices in the $40 to $50 per MWh
price range during the last two drought years.It has
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Idaho Power Company
been quite some time since the Company and the region
experienced high water conditions , but if high water was
to occur , I would expect that market prices would be
significantly lower than the $40 to $50 per MWh range,
but not as low as the $7 to $17 per
MWh range expected to
accompany high water conditions ten years ago.
What affect on power supply expenses would you
envlsion result the upward movement the market
price for energy?
have mentioned believe that
relationship between hydro conditions and the market
price of energy still exists.When the Company and the
region have abundant water , higher cost generating plants
are not required to satisfy Company or regional loads.
The marginal resource at such times is likely a low cost
coal unit or even on occasion hydro generation.As a
result, the market price for energy will fall to the
incremental cost of the marginal resource.Conversely,
when the region is in a drought condition , as is the
current situation, higher cost coal units and gas-fired
units will be the marginal resources influencing market
prices.
As a result of the supply and demand relationship,
the Company will continue to encounter higher market
prices when both the Company and the region are resource
697 SAID , DI
Idaho Power Company
deficient and conversely will encounter lower market
prices when both the Company and the region have abundant
resources.Power supply expenses are reduced by higher
valued market sales, but are increased by higher valued
market purchases.I would expect overall upward pressure
on power supply expenses as a result of an upward trend
in market prices especially when considering the seasonal
and peak period load shifts that I discussed earlier.
How have the fuel costs of the Company'
coal-fired resources changed over the last ten years?
My response to this question includes known and
measurable changes to fuel costs, which I will discuss
later in my testimony.Including known and measurable
adjustments , the fuel cost for the Bridger units has
increased at an annual average rate of 1.0 percent per
year over the last ten years from $11.51 per MWh to
$12.75 per MWh.The fuel cost for the Boardman plant has
increased at an annual average rate of 0.5 percent per
year over the last ten years from $12.59 per MWh to
$13.25 per MWh.Due to the renegotiation and replacement
of coal contracts for the Valmy plant , the fuel cost for
the Valmy units has decreased by 31 percent from $21.
per MWh in 1993 to $14.7 per MWh in the test year 2003.
Due to the changes in the fuel costs of the
Company's coal-fired resources, what effect would you
698 SAID , DI
Idaho Power Company
expect to see with regard to power supply expenses?
wi th only modest increases in the fuel costs
for Bridger and Boardman and significant decreases in the
fuel cost for Valmy, I would expect some downward
movement in the Company's power supply expenses.Lower
per unit fuel costs at Valmy will reduce the fuel expense
at Valmy when it is dispatched to serve system loads, but
also will provide for more frequent opportunities to sell
Valmy surpluses into the market.Both of these impacts
serve to reduce net power supply expenses.
Are there any resource additions that have
occurred in the last ten years that would reduce power
supply expenses?
Yes.The addition of any resource has the
effect of reducing power supply expenses.This results
because of economic dispatch principals.If additional
resources can be dispatched at costs lower than
al ternati ves , then dispatch of the new resources occurs
thus reducing power supply expenses.If the additional
resource cannot be dispatched at costs lower than
alternatives , no additional power supply expense occurs.
In the last ten years , the Company has added the Danskin
gas- fired plant , located at the Evander Andrews complex
near Mountain Home , Idaho and has also received energy
from additional PURPA QF proj ects .In 2004 , the Company
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Idaho Power Company
will acquire additional generation from the
PPL Montana
Power Purchase Agreement (PPA) and from a new QF proj ect
called the Tiber Montana LLC (Tiber) proj ect.The costs
of QF proj ects have not historically been included in
power supply expenses II and thus power supply expenses
are reduced by new QF proj ects as they reduce the need
for resources that are reflected in power supply
expenses.
Have you supervised the preparation of power
supply modeling to reflect the changes in test year
characteristics that you have described in your
testimony?
Yes.Under my supervision and at my request
two power supply simulations representative of the test
year 2003 under a variety of water conditions were
prepared.The first simulation is for the test year 2003
prior to known and measurable power supply adj ustments.
This simulation reflects the load changes, market price
changes , fuel cost changes and resource changes that have
occurred in the last ten years since the last test year
1993.The second simulation modifies the first
simulation of the test year to reflect known and
measurable power supply adjustments that I will describe
later in my testimony.As has been the case in the past,
the power supply modeling results reflect the average
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power supply expenses associated with multiple hydro
conditions that are representative of the possible
circumstances the Company might encounter.Thi s year the
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analyses include water conditions corresponding to years
1928 through 2003.The average of the expenses related
to each of the 76 water conditions represents the
normalization of power supply expenses.
Have you supervised the development of an
exhibi t showing the results of the power supply expense
normalization for test year 2003 prior to any known and
measurable power supply adjustments?
Yes. Exhibit 32 shows the results of the power
supply expense normalization prior to known and
measurable power supply adjustments.Page 1 of Exhibi
32 shows the summary results containing the 76-year
average power supply generation sources and expenses.
Pages 2 through 77 contain results for each of the 76
individual water conditions 1928 through 2003.
Please summarize the sources and disposition of
energy as shown on page 1 of Exhibit 32.
From the summary information contained on page
1 of Exhibit 32 it can be seen that for the test year
2003 , hydro generation supplies 8.8 million MWh while
thermal generation supplies 6.7 million MWh (Bridger 5.
Boardman 0., Valmy 1.3) from Company-owned generation
resources.Danskin , as a peaking plant, operates
intermi ttently, but offers significant contribution at
important times when resources and purchases are
702 SAID , DI
Idaho Power Company
inadequate to serve peak loads.Purchases of power come
from three sources:market purchases, contract purchases
other than QF and QF purchases.QF purchases are assumed
at fixed normalized levels amounting to 783,635 MWh.
Because the fixed QF purchases are fixed inputs to power
supply modeling, they are not shown on the variable
output summary, however, when combined with the market
and other contract purchases , total purchases amount to
1 million MWh.As a result , hydro generation
contributes approximately 53 percent (8.8 / 16.6) of the
generation mix , thermal generation contributes
approximately 40 percent (6.7 / 16.6) and purchases
contribute approximately 7 percent (1.1 / 16.6).Of the
over 16.6 million MWh consumed , 14.1 million MWh are
utilized for system loads while over 2.5 million MWh are
sold as surplus.
Please describe the expense and revenue
information associated with the normalized operation that
you have described as shown in Exhibit 32.
Exhibi t 32 contains variable expense and
revenue information limited to FERC accounts 501 , Fuel
(coal); 547 , Fuel (gas); 555, Purchased Power; and 447
Sales for Resale. Hydro generation has no assumed fuel
expense.Coal expenses of $89.9 million are comprised of
Bridger at $63.7 million , Valmy at $20.8 million andBoardman at $5.4 million. Gas expenses amount to $3.
703 SAID , DI
Idaho Power Company
million.Purchased power expenses not including QF
amount to $10.6 million while surplus sales amount to
$54.1 million.Al together , net power supply expenses
amount to $49.6 million (89.9 + 3.2 + 10.6 - 54.1).
How do these power supply expenses compare to
the 1993 normalized amounts approved by the Commission at
the conclusion of the IPC-E-94-5 case.
Fuel expenses (entirely coal related) for the
1993 normalized test year were $61.5 million.Purchased
power not including QF was $11.0 million and surplus
sales were at a $24.5 million level.The Company had no
gas fuel expenses in 1993.Net power supply expenses
were $48 million (61.5 + 11 - 24.5).While normalized
surplus sales revenues have increased by $29.6 million
(54.1 - 24.5), fuel costs have also increased by $31.
million (89.9 + 3.2 - 61.5).While market prices have
increased, reliance on purchases has decreased , resulting
in little change to non-QF purchased power expenses.The
net change in normalized power supply expenses before
known and measurable adjustments is only a $1.9 million
increase from 10 years ago.
Please describe the types of "known and
measurable II power supply adjustments that you recommend
in this proceeding.
I propose two types of known and measurable
704 SAID , DI
Idaho Power Company
adjustments to normalized power supply expense
computations;(1) changes in purchased power contracts
and (2) changes in fuel costs.These adj ustments have
not only a direct impact on specific expenses , but also
have indirect impacts on the Company's market purchase
expenses and market sales revenues.
Please describe your proposed changes to
purchased power contracts that will have a known and
measurable impact on the power supply expenses of the
Company.
I propose the inclusion of two power purchase
contracts that will become effective in 2004 as new rates
are implemented.The first contract , as I mentioned
earlier in my testimony, is a PURPA QF contract with
Tiber Montana LLC for the acquisition of 29 144 MWh at a
cost of $1.2 million.First deliveries of power from
Tiber are scheduled for May 2004.The second contract
also mentioned earlier in my testimony, is a PPA with PPL
Montana for the purchase of 99,360 MWh at a cost of $4.
million.The first delivery of power from PPL Montana is
scheduled for June 2004.This Commission has approved
both of these contracts.
Please describe your proposed changes to fuel
costs that will have a known and measurable impact on
power supply expenses.
705 SAID, DI
I daho Power Company
I have been informed by employees in the
Company's Power Supply Department that certain minor
known and measurable changes in coal prices will occur in
2004 as a result of contract provisions , train lease
agreements and depreciation.A change of greater
significance results from the expiration of a long-term
coal contract at Valmy.For two plants, Boardman and
Valmy the known and measurable adjustments result in
lower per unit fuel costs.Boardman fuel costs drop from
$13.66 per MWh to $13.25 per MWh. Valmy fuel will drop
from $16.2 per MWh to $14.7 per MWh.At Bridger , the
fuel cost rises slightly from $12.65 per MWh to $12.
per kWh.
Have you supervised the development of an
exhibi t showing the results of the power supply expense
normalization when the known and measurable power supply
adjustments are included?
Yes. Exhibit 33 shows the results of the power
supply expense normalization once the known and
measurable power supply adjustments have been included.
Page 1 of Exhibit 33 shows the summary output containing
the 76-year average power supply generation sources and
expenses.The following pages 2 through 77 show the
individual water conditions 1928 through 2003 output as
those water conditions would impact the test year 2003.
706 SAID , DI
Idaho Power Company
Have you supervised the development of an
exhibit to quantify the extent to which the normalized
power
707 SAID , DI 14a
Idaho Power Company
supply expenses change as a result of including the known
and measurable adjustments you have proposed?
Yes.Exhibi t 34 details the changes in both
normalized power supply expenses that exclude QF expenses
and also the change in QF expenses that result from known
and measurable adjustments.Net power supply expenses
decrease by $1.9 million as a result of changes to fuel
costs and additional power purchase contracts.
expenses increase by $1.2 million as a result of
inclusion of the Tiber contract.
How do base level PCA expenses differ from test
year power supply expenses?
Base level PCA expenses differ from test year
power supply expenses in two ways.First , base level PCA
expenses include QF expenses.Second, base level PCA
expenses are determined for an April through March time
frame rather than a calendar year.April represents the
beginning of the runoff period that provides the basis
for the PCA projection.
What are the 2003 test year normalized QF
expenses including the Tiber project?
Including the Tiber project, 2003 test year
normalized QF expenses amount to $46.4 million.
How do 2003 test year normalized QF expenses
compare to 1993 test year QF expenses?
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Idaho Power Company
The 2003 test year normalized QF expenses of
$46.4 million are $12.1 million greater than the $34.
million 1993 test year normalized QF expenses.However
the $46.4 million value is $1.2 million less than the
value used in the current PCA proj ection formula.
What is the base level of PCA expenses for test
year 2003?
As I stated earlier in my testimony, the base
level of PCA expenses is the sum of the normalized power
supply expenses and normalized QF expenses.In this
case , normalized power supply expenses amount to $47.
million and normalized QF expenses amount to $46.
million.The sum , $94.1 million , represents the new base
PCA expense level.
Have you directed the preparation of an exhibit
that shows the derivation of the appropriate new PCA
regression formula to be used for proj ecting the next
year's PCA expenses?
Yes , I directed the preparation of Exhibit 35
to show the derivation of the new PCA regression formula.
Please describe Exhibit 35.
Exhibit 35 consists of six columns at the top
of the page.Col umn one shows the number of the
observation from 1 to 75.Column 2 contains the PCA year
corresponding to each observation; observation 1 is 1928
709 SAID, DI
Idaho Power Company
observation 2 is 1929 , and so on through observation 75
which is 2002.
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Idaho Power Company
Because the PCA year is for months April through March of
the following year , there are only 75 observations
instead of the 76 conditions represented in Exhibit 33.
Column 3 contains the April through July runoff for each
of the observation years 1928 through 2002.Column 4
contains the natural logarithm of the runoff value
contained in Column Col umn 5 contains the observed
April through March annual power supply expense based
upon data from Exhibit 33 , but reflecting PCA totals
rather than calendar year totals.Finally, Column 6
contains the regression predicted value of April through
March annual power supply expenses.
To the right of the columns are summary output of
certain regression statistics (such as r-square) and
formula coefficients.
Please describe the new PCA regression formula
based upon Exhibit 35.
The basic PCA formula takes the following form:
Annual PCA expense = C1 - C2 * In (Brownlee runoff) + C3.
The values of C1 , C2 and C3 are constant with the only
variable being Brownlee runoff.The equation without C3
is used to predict net power supply expenses and is the
direct result of the regression analysis contained in
Exhibit 35.The constant C1 represents the prediction of
annual net power supply expense that would occur if there
711 SAID , DI
Idaho Power Company
was zero April through July Brownlee runoff.The value
of C1 is
712 SAID , DI 17a
Idaho Power Company
$1,140 615 325.In reality, the lowest April through
July Brownlee runoff contained in the observations is
97 million acre-feet which occurred in the 1992
observation.
Because the regression provides a linear fit of a
non-linear transformation, the value of C2 is somewhat
difficul t to explain.Observed Brownlee runoff data in
acre-feet is first transformed by the natural logarithm
function.For each unit increase in the natural
logari thm of the Brownlee runoff data the proj ection of
annual power supply expenses will be reduced by C2 , which
is $70 685 112.The average natural logarithm of
Brownlee runoff values, based upon the observations
contained in Exhibit 35 , is 15.46.This value
corresponds to a runoff of approximately 5.2 million
acre-feet (e A 15.46 = 5 178,365 million acre-feet).
With a runoff of 5.2 million acre-feet and a natural
logari thm of 15., the proj ected net power supply
expenses would be $47 823 493 ($1 140,615 325 -
$70,685 112 * 15.46).An increase of 1 to the natural
logarithm would result if the runoff was approximately
14.1 million acre-feet (In(14 076,256) equals 16.46 which
equals 15.46 + 1).With a runoff of 14 076,266 million
acre-feet , the net power supply expenses would be
$70,685 112 less than $47 823 493 making the projection
713 SAID , DI
Idaho Power Company
of power supply expenses a negative $22 861 619
($1 140 615 325 - $70,685 112 * 16.46).
The natural logarithms of observed Brownlee runoff
714 SAID , DI 18a
Idaho Power Company
ranged from 14.49 (1992 runoff) to 16.35 (1984 runoff).
The difference , 1.86 (16.35 - 14.49), multiplied by
$70 685 112 equals approximately $131.5 million, which
represents the change in proj ected power supply expenses
from the highest water case (1984) to the lowest water
case (1992).
The value of C3 is $46 413 000 , the normalized
expense for QF.Because the normalized expense for QF is
quantified separately from net power supply expenses it
is added to net power supply expenses to determined the
PCA expenses.
What is the new PCA regression equation with
values inserted for the constants?
The new PCA regression equation is:
Annual PCA expense = $1 140 615 325
- $70 685,112 * In (Brownlee runoff)
+ $46,413,000.
In the past, has the PCA regression equation
also contained a constant related to FMC, later Astaris
second block revenues?
Yes , FMC second block revenues were previously
treated as separately identified revenue that , like
surpl us sales , reduced net PCA expenses. The FMC
constant is no longer appropriate due to the cancellation
of the FMC contract.
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Idaho Power Company
How does the range in proj ected power supply
expenses from high condition to low condition resulting
from this regression equation compare to the range of
proj ected power supply expenses in the previous
regression equation?
The predictions of power supply expenses based
upon the regression observations contained in the
previous regression analysis ranged from minus $9.
million (1984) to $112.4 million (1992), a range of
$122.3 million.
Do you recommend any addi t ional PCA
computational changes with the establishment of the new
PCA regression formula?
Yes.There are three PCA computational factors
that need to be updated as a result of the current review
of power supply expenses.First , for PCA proj ection
calculations, a new normalized base PCA rate can be
determined.Second, a new Idaho jurisdictional
percentage can be determined.Third a new expense
adjustment rate to be applied to load growth or decline
can be determined.
Have you supervised the development of an
exhibit to determine the PCA computational factors you
have just mentioned?
Yes , Exhibit 36 is a one-page exhibit detailing
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Idaho Power Company
the appropriate computation of the PCA factors I have
outlined.
What is the first computation shown on Exhibit
36?
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Idaho Power Company
The first computation recaps the normalized PCA
computation that I have discussed thoroughly in my
testimony.The new normalized PCA expenses for 2003 test
year amount to $94.1 million compared to the previous
$73.1 million value for the 1993 test year.
Please discuss the normalized Base PCA rate
computation contained in Exhibit 36.
First, I would point out that in my opinion
the normalized Base PCA rate has been improperly
determined in the past.While expenses are incurred
based upon loads , they are recovered based upon sales.
Historically, the normalized Base PCA rate of 0.5238 was
determined by dividing the $73.1 million of normalized
PCA expenses by the normalized system firm load value.
My recommendation for the current computation of the
normalized Base PCA rate is that the $94.1 million
normalized PCA expenses be divided by the normalized
system sales value of 12,863 484 MWh.The resulting PCA
base rate is 0.7315 cents per kWh.
Was a similar load/sales error previously
corrected by the Commission?
Yes , PCA true-up rate computations were
originally based upon Idaho jurisdictional firm loads
rather than Idaho jurisdictional firm sales levels.
1996, the Commission corrected that error in Order No.
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Idaho Power Company
26455.
Please discuss the Idaho jurisdictional
719 SAID , DI 21aI daho Power Company
percentage computation contained in Exhibit 36.
The Idaho jurisdictional percentage is derived
by dividing the Idaho jurisdictional firm load by the
system firm load number.As I mentioned earlier in my
testimony, the Company's FERC jurisdictional contract
loads have been reduced by 1.4 million MWh while at the
same time Idaho jurisdictional loads have grown. As a
resul t , Idaho jurisdictional loads now represent 94.
percent of the Company's total load.
Please discuss the Expense Adj ustment rate to
be applied to load changes for PCA true-up computations.
When the PCA was established , the Commission
recognized that load growth would provide additional
revenue that would in part offset the corresponding
additional power supply expenses incurred to serve the
additional load.The revenues generated would be the
result of rates designed to recover the full embedded
costs of serving existing customers including generation
costs , distribution costs , transmission costs and other
costs of the Company.However , the true cost of serving
additional customers is comprised of a blend of new
marginal costs incurred to serve new customers and
reduced embedded costs when existing facilities allow for
addi tional customers at zero or low cost.The Commission
determined that rates paid by new customers would cover
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Idaho Power Company
all additional costs including $16.84 per MWh of PCA
expenses that might occur to serve additional load.The
$16.84 per MWh credit was computed by averaging the
Boardman and Valmy fuel costs.Using the same
computational method the new expense adjustment rate for
load changes is $13.98 per MWh.
Based upon your understanding of Mr. Keen I
testimony in this proceeding, do you believe the $13.
per MWh rate should be used as the new credit for load
growth?
No.Mr. Keen pointed out that whether looking
at generation, distribution , or transmission , the Company
has little ability to serve additional customers without
investment in new facilities.In my opinion , revenues
derived from additional customers served at embedded
rates will not be sufficient to recover both the
incremental costs of required new facilities and an
amount greater than the embedded cost of PCA expenses
(the PCA base rate) I believe it would be more
appropriate to have a load growth credit based upon the
normalized PCA base rate of $7.30 per MWh (7.3 mills per
kWh) .That is the portion of customers I rates that it is
contemplated will cover base PCA expenses.The remainder
of customers' rates cover the other than PCA expenses
that Mr. Keen has suggested will grow at a significant
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Idaho Power Company
pace in the coming years.
Do you have a non-computational recommendation
with regard to the PCA?
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Idaho Power Company
Yes.Mr. Gale, Ms. Brilz and I have discussed
Ms. Brilz ' recommendations in this proceeding to create
seasonal pricing that if accepted would create a seasonal
rate change on June 1 of each year.If the PCA rate
change date were to continue to occur on May 16 of each
year , customers would see two rate changes within 16
days.If Ms. Brilz I seasonal pricing recommendations are
approved, then in order to eliminate back-to-back rate
changes , I recommend that the PCA recovery period be
moved from a May 16 through May 15 period to a June 1
through May 31 time period.No other changes to PCA time
frames would be required.PCA projection and true-
computations would still be based upon an April 1 through
March 31 time frame and the Company would still file its
PCA request by April 15 each year.
Does that conclude your testimony?
Yes.
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Idaho Power Company
(The following proceedings were had in open
hearing.
MS. MOEN:Mr. Said is available for
cross-examination.
COMMISSIONER SMITH:Okay.Ms. Nordstrom.
CROSS-EXAMINATION
BY MS. NORDSTROM:
Good afternoon.
Good afternoon.
Well , not long ago I asked John Prescot t a
question about including variable cloud seeding costs in
the power cost adj ustment and whether or not the Company
had an opinion on that.He suggested that I ask you , so I
am.
With regard to the variable portion of the
costs , are you talking about the trace elements that would
be put into the air rather than the fixed costs of
stations?
Not the fixed costs that would be
capitalized, everything else.
That could be done.What we're proposing
in this case is that all of the costs of the program be
included in base rates.And that the benefits will
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Idaho Power Company83676
naturally be captured in the PCA.So if you wanted to
track the variable pieces of the program that could be
done too.
Okay.Thank you.
MS. NORDSTROM:No further questions.
COMMISSIONER SMITH:Thank you.Mr. Budge.
MR. BUDGE:Thank you.
CROS S - EXAMINATION
BY MR. BUDGE:
Mr. Said , is my understanding correct that
you and Ms. Brilz were essentially relying on the
Company's IRP , the integrated resource plan to identify
those months of the year that the Company has a capacity
deficiency?
Ms. Brilz may do that in her testimony.
For the purposes of my testimony the load information that
I used is the basis of the test year by which power supply
costs are determined for all months.
Okay.Well , if I recall correctly there
were various references in your testimony to the months
that were deficient being the summer months being June
July, and August; and the winter months , I believe, being
November and December; is that correct?
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Idaho Power Company83676
months where
IRP?
I I m sorry, I missed the first part of your
In the IRP evaluation that's correct.
And wasn't the basis for arriving at those
you have capacity deficiency the Company'
question.
Was the basis that the Company relied upon
in arriving at those capacity deficiency months, the IRP?
Yes.
And while August is a month that I s
repeatedly included by you , and I think by Mrs. Brilz , I
could not see in the IRP any mention of the month of
August being a capacity deficiency month.And I I m
wondering, can you explain why August was utilized as a
capacity deficiency month if it's not reflected in the
IRP?
I don't have an IRP with me but I believe
that if I were to look at the charts there would be some
months with August deficiency.
Maybe I could approach and provide you
mine , if I may.Handing the witness what's identified as
Idaho Power's 2002 Integrated Resource plan.If I could
Mr. Said , I think you'll see some highlighting already at
the appropriate reference.But if you look first to page
and then glance at page and also page and then
CSB REPORTING 726 SAID (X)Wilder Idaho 83676 Idaho Power Company
move to 28, you will see similar references on each of
those pages where the IRP refers to the capacity
deficiency months being June , and July, and November , and
December.And nowhere in those references is August
identified as a capacity deficiency month.
The references that you've pointed out do
specify the months that you've mentioned.
Would that be a question that I maybe
should further explore with Mrs. Bril z , if you don't have
an answer?If you have an answer to the question as to
why August was used in your power supply modeling as a
deficiency month and referred to in your testimony as such
when it I S not depicted as such in the IRP?
Well , I believe that the 2002 integrated
resource plan also had some additional information
provided as part of the Garnet al ternati ve requirement of
the Commission on the Company.And it's possible that
those August deficiencies show up in that addendum to the
2002.
Okay.Let's move in a different direction
if I might.Referring to your Exhibit 32 , if you would
please , on page And maybe you can correct me if I'
wrong, but it's my understanding that page 1 is portraying
the average price and average megawatt hour of data for
about 75 years of hydro data?
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Idaho Power Company83676
That I S correct.
And then the following pages seem to do the
same on a year-to-year basis for each of those 75 years.
Correct.The following pages show the
detail of the individual years.
So page 1 captures the average of all of
those?
That's correct.
And if we look at the month of July, just
for example, by taking that column we'd be able to
calculate which of the generation resources reflected on
the left side of page 1, what each resource costs and
develop a cost on a kilowatt hour basis per resource?
You could determine the variable dispatch
costs by taking the total costs of the resource divided by
the energy.I think that I s what you said.
Okay.And in your power supply model is it
true we have a hierarchy of resources and you dispatch
least cost first , and then move up the ladder toward the
highest cost?
That's correct.
And if we look at the left side of that
page 1 on Exhibit 32 we're referring to , I suppose your
hydro then that's listed on the top is the least cost
resource and then would Bridger be next , and Boardman
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Idaho Power Company83676
next , and then Valmy, and so on?
Yes.With the exception of purchase power.
Purchase power costs move and so they can actually
fall in
the dispatch at any point in time.
Okay.I want to make that calculation , if
we could.Let I s look at that purchase power column for
the months of July.If I were to take line 20th , line 20
that's the market cost for the purchase power in that
particular month; correct?
That's correct.That's the total dollars
spent on it.
If I took line 20 , which would reflect what
your purchase power costs, and divide it by line 17 the
market energy megawatt hours , would I arrive for that
particular month at a price for that power purchase for
the month of July?
You would get an average of the market
prices of power purchased in all of the July's of the 75
condi tions represented.
Okay.So would you accept , subj ect
check then , that dividing line 20 by line 17 on that July
column we're looking at , would reflect an average rate for
market energy purchases in July of 40.8 mils?
Yes.I would accept that subj ect to check.
Did you make that calculation or just
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Wilder , Idaho
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Idaho Power Company83676
accept it subj ect to check?
I just accept it.I assume you've done the
math correctly.
Now I would move down, if I could , to the
surplus sales which begin under line 23.And if we also
looked at the month of July and divided line 25 , which is
the revenue for surplus sales, by line 24 , the energy
megawatt hours for surplus sales, we would arrive, if
you'd accept subj ect to check, the price of 24.0 mils?
Yes.
When I look at this particular exhibit it
seems to show in the month of July the Company selling on
average more than double the amount of power it'
purchasing.In other words, if you look at line 17 would
reflect again the average during the month of July, the
Company is purchasing 46,644 megawatt hours as compared
to, be line 24 , the Company is selling 100 875 megawatt
hours in July.
Yes.That would reflect that there are
more conditions where surplus sales are being made than
there are conditions where purchases are being made in
that month.
Well , could you give an explanation why you
would be selling so much in July at a price of 24 mils
when in fact you're buying in that month at 40.8 mils?
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Wilder , Idaho
730 SAID (X)
Idaho Power Company83676
They aren't simultaneous transactions.
They're the result of averaging.So if you looked at any
one condition , you would find that in the month we were
predominantly a seller or predominantly a purchaser.What
it suggests is that there are a number of months or a
number of conditions in the 75 where we are a net
purchaser in the month and in the other conditions we're a
net seller in the month rather than those happening at the
same point in time.
What the average represents is an average
of all of those conditions rather than suggesting that
this is representative of the exact condition that would
exist.
Well , if I run the same calculation going
back - - let I s go back to page 3, which is supposed to be
the year 1929.It still shows that you're selling at a
price considerably less than what you I re purchasing at.
And it just puzzles me why the model would show that
you're willing to sell price , or willing to sell power in
July when you're typically short at a price much less than
what it costs you to purchase?
In that instance it depends on the hours
that the transactions are taking place.Typically we
would be purchasing during heavy load hours in this
condition , and probably selling in the light load hours at
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Wilder , Idaho
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Idaho Power Company83676
lower market prices.
Now have some trouble following that.
Isn'this mode 1 that the monthly model that does not
portray anything on an hourly basis?I mean, it doesn'
differentiate between the time of day the purchases are
made , aren't they just monthly averages?
No.That's incorrect.What the model does
is it looks at the hours wi thin each of the months and
does differentiate between hours.
Do you know which of these months shown of
the average , on the average on page 1 , which of the months
do you have the lowest power purchase prices?Do you know
without making a calculation?
I don'But typically April is a pretty
low cost month.
I made that calculation.Would you accept
that April , subj ect to check, is the month that you have
the lowest prices?
That's what I guessed so, yes, I'd accept
that.
Would you also accept , subj ect to check
that the normalized load for Micron in the month of July
increased about 35 thousand megawatt hours since the last
case in 1993?
I do know that the Micron load has grown in
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Idaho Power Company83676
the last ten years.
And just to enable you to check that , and I
can provide it , but without going through the delay in the
calculation the comparison I made was looking at Mrs.
Brilz Exhibit 40 on page 6 , which reflects the July energy
figure for Micron at 58 361 megawatt hours.And I took
her Exhibit 33, page 6, from the last rate case that
showed the figure for Micron at 23 900 megawatt hours.
But for purposes of our discussion we'll just assume that
in July we have an increase in the Micron load over this
time frame from the last case of about 35,000 megawatt
hours.
Let me ask you this.If Micron had not
increased by this 35,000 megawatt hours in July, would
your model have decreased power purchases by that amount
in the month of July?
In isolation , if all other loads grew and
the Micron load did not grow, we would see a dispatch that
would potentially reduce purchases in those periods or
times of deficit.And would also potentially increase
surplus sales in times when surplus existed and market
prices warranted.
Assuming that all other factors were equal
and we just took the 35 000 megawatt hours of Micron out
of the picture your model would then reduce power
CSB REPORTING 733 SAID (X)Wilder Idaho 83676 Idaho Power Company
purchases in the month of July because that was the
highest cost resource next in your stack; correct?
Tha t 's correct.
I think we identified
It's essentially correct.
- -
that cost to be 41 mills in July, was
your power purchase cost on the average.
Yes.
And are you aware of the Company s cost of
service model that sets a desired rate for Micron at 26.
mi 11 s .And that would be Exhibit 41 , page 2 , line 237.
I would accept that representation.
And is my understanding correct , then , that
this is the price that the service model would say is
Micron's cost of service?
Yes.m not aware of any customer class
that - - where the Company's proposal would be to price at
the margin.Therefore, I would expect the embedded cost
of service to be less than the embedded.
Would you also accept that the
Or the incremental , excuse me.
- - 26.14 mill desired rate for Micron is,
in fact, even lower than the power purchase cost that you
just established was the lowest for the year in the month
of April which came in at 26.4 mills?
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Wilder , Idaho
734 SAID (X)
Idaho Power Company83676
In other words, we just calculated that
April was your least cost month.And it came in at about
26.4 mills for market power purchases as compared to
Micron's rate of - - desired rate of 26.14 mills?
That sounds like a high market price for
April , but I'll accept that you did the math correct.
If in fact the Company is delivering this
market purchased power to Micron , would it be necessary to
put some additors on your actual market purchase price in
order to arrive at the cost of delivering that power to
Micron?In other words , you still have to add in losses
transmission , a share of the O&M in order to come up with
the rate.
Well , as I've already stated, we don't
serve Micron with the marginal purchase that was the
premise of your question.
I understand.
We serve them at an embedded rate which
I understand.But under my hypothetical
if in fact as we discussed earlier the load growth in
Micron was effectively served by a market purchase under
your power supply model , if Micron had not grown we would
not have made that market purchase.Okay?
Yes.
Get back to my question.Under thi s
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Idaho Power Company83676
hypothetical if in fact the market purchase power was
being utilized to meet the growth of Micron , would the
Company not have had to add in that price all of the other
usual additors for line losses , transmission , O&M , that
ordinarily take place when you decide how to price power
to a customer?
If I were to accept your premise that all
load growth be served at the marginal resource cost to
serve that additional load, then , yes , new customers would
have a higher rate than previous customers.But that'
not the way rates are set.
MR. BUDGE:I believe that's all I have.
Thank you , Mr. Said.
COMMISSIONER SMITH:Thank you, Mr. Budge.
Do you have questions, Mr.
Richardson?
MR. RICHARDSON:I do , Madame Chairman.
CROSS - EXAMINA TI ON
BY MR. RI CHARDSON:
Mr. Said, at page 4 , line 19, in response
to a question regarding changes in the company's monthly
load shape you state that, quote, as a result of the loss
of relatively flat loads and the addition of
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Idaho Power Company83676
non- interruptible seasonal loads, the Company's integrated
resource plan now shows the need for summer peaking
resources June , July, August, and winter peaking resources
November and December; correct?
Yeah.I didn I t catch your reference , but I
think that's correct.
That I S page 4 line 19.
Then on the next page , at page 5 line 10,
you state that you would expect the power supply expenses
to rise as a result of the seasonal peak hour load shifts
you have experienced over the last ten years; correct?
I think maybe we're working off of
different versions.My page 4 , line 19 is part of a
question , and
Well , would you accept that you do expect
power supply expenses to rise as a result of the seasonal
and peak load hour shifts?
Yes.I have discussion throughout my
testimony about a number of things that have changed in
the last ten years , one of which is the load shape.And
with the loss of a relatively flat load over the course of
a year being the FMC-Astaris load being replaced by loads
that are driven by, to an extent, by weather conditions
residential customers using air conditioning in the
summer , that that additional load that we would see on a
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Idaho Power Company83676
seasonal basis at higher cost periods of the year, would
resul t in an upward pressure on power supply costs.
Isn't it true that the vast majority of the
non-interruptible seasonal load growth in the last ten
years on the Company's system has been residential load?
I think a good portion of it has been
residential , yes.
And isn't it also true that the Schedule 19
class has experienced negligible change in both their size
and monthly load shape?
I don't know if I agree to negligible, but
it's probably small comparatively.
If it were true that the Schedule 19 class
has indeed been relatively flat both in terms of load
growth and monthly load shape, wouldn't it be true that
they are not responsible for the increasing summer peaking
power supply experiences?
I don I t think that the Company proposal
looks at much
- -
as much at what the new contribution of
the classes has been over time , as much as it looks at the
current contribution to the load during those periods of
time.
Thank you, Mr. Said.
MR. RICHARDSON:That's all I have , Madame
Chairman.
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738 SAID (X)
Idaho Power Company83676
COMMISSIONER SMITH:Thank you , Mr.
Richardson.
Mr. Ward.
MR. WARD:Yes, just a few.
CROSS-EXAMINATION
BY MR. WARD:
Mr. Said , to follow up some of the
discussion you had with Mr. Budge , I believe you may have
misspoke yourself.He asked whether the proposed rate for
Micron , or Micron rate was equivalent to cost of service.
Isn't it true that the Company's proposed rate is higher
than Micron's identified cost of service?
Yeah.The first part I don't think that
Mr. Budge had me testify what you thought you heard me
say.What I said in answer to Mr. Budge was that if
Micron were charged at a rate that was based on the
incremental costs to serve all of the Micron load as if it
was new, that that rate would be higher than what the
Company has proposed.
I think what you have stated , that the Company
proposes a rate for Micron that is slightly greater than
its cost of service is true.
And regarding the discussion about the
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739 SAID (X)
Idaho Power Company83676
35,000 additional megawatt hours in July, it's true, is it
not , that Micron is a very high load factor customer?
That's true.
And so those, or a similar number of
megawatt hours, will also be purchased by Micron in months
CSB REPORTING
Wilder, Idaho
that are not particularly high cost; is that true?
That's correct.
One other thing, if you know.Does this
Commission have the legal authority to assign rates to
customers based on when they come on the system?
MR. KLINE:I probably better obj ect to
MR. WARD:Then I'll probably withdraw it.
That's all I have.
COMMISSIONER SMITH:Thank you , Mr. Ward.
that question.
something.
your mic' s on?
Mr. Gollomp.
MR. GOLLOMP:No questions.
COMMISSIONER SMITH:Mr. Purdy.
MR. PURDY:Yeah , just a follow-up to
COMMISSIONER SMITH:Would you make sure
MR. PURDY:Just a follow-up to something
Mr. Richardson asked you.
740 SAID (X)
Idaho Power Company83676
CROSS -EXAMINATION
BY MR. PURDY:
Isn't it true , Mr. Said, that all customer
classes receiving electricity during a seasonal peak
contribute to a varying degree to that peak?
Yes.
All right.And there I s no difference
between a new customer and an old customer wi thin any
given class , is there?
There isn't a difference in terms of how
rates are set, no.
All other things being equal.
Yes.
All right.And doesn'the Company'
cost-of -service methodology take into account the various
customer class load factors in pricing or in terms of your
revenue allocation proposal?
I believe it does.
And isn't it also true that seasonal rates
send a price signal relative to the cost of power during
peak periods?
Yes.
And the Company is in fact proposing a
seasonal summer rate in this case; is it not?
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Idaho Power Company83676
Yes, it is.
Okay.
MR. PURDY:That's all I have.Thanks.
COMMISSIONER SMITH:Mr. Eddie.
MR. EDDIE:Just a couple of quick
questions also following up on those.
CROSS - EXAMINATION
BY MR. EDDIE:
Page 4 of your testimony you talked about
th~ dual peak nature that Idaho Power needs to serve now
both the summer peak and winter peak.I wondered if you
could compare those peaks or capacity shortages , if you
will , in terms of the relative cost of service.Are they
roughly equal in terms of how difficult or expensive it is
for the Company to serve , or is there a significant
difference between the two?
Typically the summer is more expensive to
satisfy than the winter.
And in the winter time , even under a good
power year , or a good water year , your hydro system is
going to be running at a very small fraction of its
capacity during November and December; is that true?
Well , the hydro system in terms of its
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Wilder , Idaho
742 SAID (X)
Idaho Power Company83676
capacity factor is a lower capacity factor in general for
all months of the year.Wha t you have wi th a hydro
facility is typically the ability to run at capacity for a
number of hours.So we're able to use our hydro
generation to a higher degree during peak hours than the
off -peak hours.We're able to shift the capacity factor
hour to hour on the hydro.I don't know if that's quite
what you were getting at.
Tha t 's good enough.Thank you.
MR . EDD IE:Nothing further.
COMMISSIONER SMITH:Thank you.
Are there questions from the
Commission?
EXAMINATION
BY COMMISSIONER SMITH:
I guess , Mr. Said, just so I don't have any
misconceptions.I always knew Idaho Power was a summer
peaking utility.And then it seemed for a while that the
winter peak was growing so you almost had dual peaks of
equal size; is that correct?
That has been the case.In more recent
times the winter peak has not been growing as fast as the
summer peak.
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743 SAID (Com)
Idaho Power Company83676
And that's what I wanted to ask.It seems
like now with the air conditioning load growing the summer
peak is now growing and the winter peak isn't because new
construction generally heats with gas instead of
electricity where gas is available.And so it seems like
theyl re getting farther apart again.
Tha t 's true.They're both growing, but the
winter is growing at a slower rate.
COMMISSIONER SMITH:Thank you.
Redirect.
MS. MOEN:No redirect.
COMMISSIONER SMITH:Thank you f or your
help, Mr. Said.
THE WITNESS:Thank you.
(The witness left the stand.
MR. KLINE:While Mr. Said is exiting the
wi tness box , a couple of things.One , I neglected to
request the Commission I s permission to excuse Mr.
Prescot t .Unlike my other witnesses that make that motion
for me , he neglected to do so.And he is - - could he be
excused from further participation in the proceeding?
COMMISSIONER SMITH:If there I s no
obj ection , we'll excuse Mr. Prescott from further
attendance at the proceeding.
MR. KLINE:Thank you.I'll also request
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Idaho Power Company83676
some guidance from the Commission.We have Ms. Brilz as
our next scheduled witness.My expectation is that Ms.
Brilz will take some time to complete her
cross-examination.We have a couple of other witnesses
Ms. Drake and Ms. Fullen , who we probably could put on and
I anticipate get them on and off relatively quickly, I may
be wrong, but I think that could occur.
COMMISSIONER SMITH:Mr. Kl ine , it's your
case.
MR. KLINE:Okay.
COMMISSIONER SMITH:You should call
whoever you like, and if Ms. Brilz goes over to tomorrow
we can only hope that our short-term memories will operate
to help us out.
MR. KLINE:Well , I think under the
circumstances , we'll just go ahead and start Ms. Bril z.
And we III go with the ordinary
- -
with the regular
schedule.
Wi th that , I'll call Maggie Bril
MR. PURDY:I don't know if I'd offer to
weigh in on this , but it wasn I t in my wildest imagination
that we'd get this far in one day.And frankly, I had a
considerable amount of cross for Ms. Brilz that might can
be changed or shortened in light of what some of the other
wi tnesses have said.And I probably would prefer to defer
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Wilder , Idaho
745 COLLOQUY83676
her if that -- I'd join in with the prior motion if that
would make any difference to the rest of the folks.
Because I don't think most of us anticipated it being this
far along.
MR. KLINE:I did not anticipate it that
way either.If you would promise that your
cross-examination would be shortened then , obviously, that
would be, I think, to everyone's advantage.
MR. BUDGE:I would think it would be.But
of course , you don I t know what it's going to be in the
first place.
MR. KLINE:, I don'
COMMISSIONER SMITH:That's right.Well
let'just be off the record for a second.
(Discussion off the record.
COMMISSIONER SMITH:Back on the record.
CSB REPORTING
Wilder , Idaho
746 COLLOQUY83676
MAGGIE BRILZ
produced as a witness at the instance of Idaho Power
Company, having been first duly sworn , was examined and
testified as follows:
BY MR.KLINE:
record,please?
DIRECT EXAMINATION
Could you please state your name for the
My name is Maggie Brilz.
And what is your position at Idaho Power
I am Pricing Director.
Ms. Brilz , have you previously filed direct
testimony, 83 pages of direct testimony, and Exhibits 37
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Wilder , Idaho
through 49 in this case?
Yes, I have.
And do you have any additions or
corrections that you need make to your testimony?
I have one correction.On page 46, line
Company?
, the reference to 9:00 a.m. should read 7:00 a.
please?
MR. RICHARDSON:Could you repeat that,
THE WITNESS:Yes.Page 46 , line 19 , the
747 BRILZ (Di)
Idaho Power Company83676
reference to 9:00 a.m. should read 7:00 a.
BY MR. KLINE:
wi th that correction, Ms. Bril z , if I were
to ask you the questions that are contained in your
prefiled direct testimony today, would your answers be the
same?
Yes , they would.
MR. KLINE:Madame Chairman, with that, I
would request that Ms. Brilz' s testimony be spread on the
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Wilder , Idaho
record as if read in its entirety, and that Exhibits 37
through 49 be marked for identification.
COMMISSIONER SMITH:Without objection , it
is so ordered.
Maggie Brilz is spread upon the record.
(The following prefiled direct testimony of
748 BRILZ (Di)
Idaho Power Company83676