20040415Volume X Part II.pdf

Please state your name and business address for
the record.
My name is Joe Leckie.My business address is
472 West Washington Street, Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
Commission (Commission) as an auditor in the Utilities
Division.
What is your educational and experience
background?
I graduated from Brigham Young Uni versi ty with
a Bachelors of Science degree in Accounting.I worked
for the accounting firm Touche Ross in its Los Angeles
office for approximately one year.I then attended law
school and graduated from the J. Rueben Clark School of
Law at Brigham Young University with a Juris Doctorate
degree.I am licensed to practice law in the State of
Montana and did so for approximately 25 years.I have
been employed by the Commission as an auditor since March
2001.I have attended the annual regulatory studies
program sponsored by the National Association of
Regulatory Utilities Commissioners (NARUC) at Mic ~igan
State University in August 2001.
Would you please summarize your testimony in
this case?
CASE NO. IPC-E- 03 -
02/20/04 1540 LECKIE, J.(Di) Staff
Yes.I will present Staff adjustments totaling
563 686 to the Company-proposed test year revenue
requirement in the following areas:
(1 )Idaho Power's annualizing adj ustments for
the 2003 maj or plant additions in the last trimester of
the year should not be allowed.This reduces revenue
requirement by $1 953,644.
(2 )Idaho Power I s known and measurable
adj ustment for 2004 maj or plant additions through May
2004 should be averaged using the 13-month average rate
base methodology.This reduces revenue requirement by
625 579.
(3 )Idaho Power capitalized improvements to
Brownlee-Woodhead Park in the amount of $7 525 237.
is Staff I s position that these improvements should not be
included in rate base for this rate case, but rather
deferred with other relicensing costs for Hells Canyon.
This deferral decreases revenue requirement by $866,446.
(4 )Idaho Power capitalized $654 740 for
defense of its position concerning a biological opinion
prepared and submitted to FERC by the National Marine
Fisheries Services (NMFS) in 1995.It is Staff I s
position that these costs should have been expensed in
the years incurred, and should not have been capital i zed
and included in rate base.Excluding these costs from
CASE NO. IPC-E- 03 -
02/20/04 1541 LECKIE, J.(Di) Staff
rate base reduces revenue requirement by $68 405.
(5 )Idaho Power included in rate base the cost
for a shareowners' document management system in the
amount of $106,275.It is Staff I s position that only
one-half (1/2) the cost of the document system should be
included in the rate base.This adj ustment reduces the
revenue requirement by $10,921.
(6 )Idaho Power's investment in the Bridger
Coal Company is held through its subsidiary, Idaho Energy
Resources Company (IERCO).This investment should be
reduced for equipment that is not used and useful.This
reduces revenue requirement by $38,691.
How were you able to determine the revenue
requirement effect of each of the Staff recommendations
presented in your testimony?
I identified the plant accounts that would be
changed by each adjustment , and then Staff witness
English determined the effect on revenue requirement
resulting from these adjustments.See Staff Exhibit
No. 113.
Did you review other areas that do not have an
effect on the revenue requirement?
Yes, there were other aspects of rate base that
I reviewed which did not effect the revenue requirement.
These are as follows:
CASE NO. IPC-E- 03 -
02/20/04 1542 LECKIE , J.(Di) Staff
(1 )Idaho Power I s addition to rate base of the
Danskin Power facility in the amount of $52,484 209.
Staff witness Sterling will discuss the addition of the
Danskin Power facility in greater detail in his
testimony.
(2 )Idaho Power's capitalization of additional
security costs in the amount of $728 766.
(3 )Idaho Power's adj ustment for the Prairie
Power Acquisition.
(4 )The addition of the Nez Perce settlement
in rate base.
(5 )Idaho Power's accounting treatment in this
case of its asset retirement obligation.
ANNUALIZATION OF 2003 MAJOR PLANT ADDITIONS
Please describe Idaho Power I S annualization
adj ustment for the maj or plant additions that the Company
placed into service in the last four months of 2003.
During the last trimester of 2003, Idaho Power
placed into service maj or plant additions with a total
value of $23 161 303.Idaho Power indicated in
discussions with Staff that the basis for determining
what would be a major plant addition are those projects
that will close in the last four months of 2003 and the
cost of which will equal or exceed two million dollars.
The major plant additions included the Bridger rewind
CASE NO. IPC-E- 03 -02/20/04 1543 LECKIE, J.(Di) Staff
proj ect for a total cost of $8 661,463 and the
Brownlee-Oxbow transmission line for a total cost of
CASE NO. IPC-03-
02/20/04 1544 LECKIE , J.
$14 499,840.These
(Di)
Staff
plant additions are included in the month-end Electrical
Plant in Service (EPIS) account balances for the months
when they are placed in service , and are included in the
13 -month averaging process.The annualizing adjustment
of $19 779 389 is the difference between the total costs
of the plant additions treated as if they were in service
the full 13 months and the amount of the plant additions
actually included in the average rate base calculation.
Does Staff accept this annualizing adjustment?
, Staff obj ects to this adj ustment to rate
base because the annualizing adjustment as proposed by
Idaho Power is not consistent with Commission-approved
methodology for calculating an average-year rate base.
The annualizing adjustment proposed by Idaho Power would
treat these plant additions for averaging purposes as if
they were in service for the whole 13 months and not just
a portion of the year.This adj ustment has the same
effect as if Idaho Power were using the year-end balance
for these additions to plant in determining rate base.
Why should these year-end values for major
plant additions not be included in rate base?
Because the Commission has consistently ordered
the use of an average rate base in Idaho Power's last two
rate proceedings, Case Nos. U-I006-265 and IPC-94-
In the 1984 rate case (U-I006-265) , the Commission
CASE NO. IPC-03-02/20/04 1545 LECKIE , J.(Di)
Staff
stated: "(T) he company calculated an average test-year
1984 rate base from ending monthly balances beginning
December 1983 through December 1984...Order No. 20610 at
49.In the 1994 rate case (IPC-94-5) , the Commission
again adopted a 13 -month average rate base by stating:
IPCo proposed a 1993 test year and a rate base
comprised of the average of 13 -monthly balances
for the period ending December 31 , 1993, rather
than a year-end rate base. No party obj ected
the use of a 1993 test year and an average ratebase. Accordingly, we find the use of a 1993
test year and an average rate base to be
reasonable and appropriate in this case.
Order No. 25880 at
In this present case Idaho Power again asks to
have rates determined using an average rate base.Yet if
Idaho Power is allowed to annualize these plant
addi tions , the average rate base will be skewed toward an
end-of-year rate base without reflecting any customer
benefits from the investment.This would create a
mismatch between investment and test year
expenses/benefits that the average-year rate base
methodology is designed to prevent.
Has the Commission previously addressed the
issue of the average rate base as opposed to an
end-of -year rate base?
Yes, the Commission previously addressed this
issue in a Washington Water Power Company (WWP) rate
CASE NO. IPC-03-02/20/04 1546 LECKIE, J.(Di)
Staff
case, Case No. U-I008-234, and again in a Boise Water
Corporation (BWC) rate case , Case No. U-I025-51.In the
WWP case , the Commission stated:
The average rate base provides a better
matching of revenues and expenses with
fewer chances for error or omissions.
Therefore, we find it is fair , just and
reasonable to require Water Power to utilize
an average rate base the same as every other
major utility that we regulate in Idaho.
Order No. 20267 at 10.
In Order No. 20592 issued in the 1986 Boise
Water rate case (U-I025-51) , the Company proposed to use
an average rate base only if some of the additions to
plant were included at year-end levels.The Company
maintained that the additions included at year-end levels
were non-revenue producing or expense saving.In denying
Boise Water's request to add specific additions to plant
at year-end levels , the Commission stated:
The Company I technically correct" calculation
of average rate base is an aberration. Not
only does it appear to be theoretically
incorrect, but it is impractical to administer.
In terms of cash flow all depreciableinvestments are revenue producing.
addition , the difficulty and subjectivedecision-making process in determining what
classes of property are or are not " revenueproducing" or "expense saving" presents a
quagmire into which we decline to step.
We again adopt Staff I s recommended average year
rate base.
Order No. 20592 at 12-13.
CASE NO. IPC-E- 03 -02/20/04 1547 LECKIE , J.(Di) Staff
The treatment Boise Water requested to
determine rate base is essentially the same treatment
Idaho Power is asking for in this case when it proposes
adding to rate base the annualized cost of the additions
to plant.
Has the Commission cited any other reasons for
limiting exceptions to using average-year rate base?
Yes.In both cases cited above the Commission
identified low inflation and the size of plant additions
as factors further limiting deviation from an
average-year rate base.The Commission stated that
additions must be so large as to unreasonably distort
the matching of its revenues, expenses and rate base.
Order No. 20592 at 13.
What has the inflation rate been over the last
three years?
The inflation rate , measured by the percent
change in the consumer price index, over the past three
years has averaged 1.9% (1.6% in 2001; 2.4% in 2002 , and
9% in 2003).This is relatively low compared to
historical levels.See Staff witness Carlock's Exhibit
No. 144.
Is it Staff's position that the last trimester
maj or plant additions are large enough to unreasonably
distort the matching of Idaho Power's revenues , expenses
CASE NO. IPC-E- 03 -
02/20/04 1548 LECKIE , J.(Di) Staff
and rate base?
On a cumulative basis, Staff believes the plant
CASE NO. IPC-E- 03 -
02/20/04 1549 LECKIE , J.(Di) Staff
additions do represent a significant mismatch between
Idaho Power s revenues, expenses and rate base.That is
why we propose in this case, and why the Commission has
approved in previous cases, use of an average-year rate
base.
While the Commission has identified large plant
additions as one factor to consider in allowing deviation
from average-year , it has also noted that all plant
investment has some "revenue producing" and "expense
saving" effects that are difficult if not impossible to
identify.In its deviationOrder No. 20592 at 12-13.
from average-year rate base, Idaho Power proposes only
increases in depreciation , taxes and insurance as its
adjustments to reflect the effect of these rate base
additions.Staff believes that Idaho Power has failed to
show the benefits it will receive for making these
investments; instead it has shown only the increase in
expenses.To the extent the benefits are unknown or
cannot be properly measured as has been indicated in
prior commission orders, the investment and the costs
should not be included in rates at year-end levels.
How does the annualizing adjustment proposed by
Idaho Power change the average-year rate base?
By allowing Idaho Power to add the annualizing
adjustment to the average rate base, Idaho Power has
CASE NO. IPC-03-02/20/04 1550 LECKIE, J.(Di) Staff
effectively weighted the average to reflect the plant
addi tions at the end-of -year value.To stay true to the
averaging methodology, there is no need to make any
adj ustment to the average result.The last trimester
maj or plant additions should be included in the average
rate base without distortion.
In what way does the annualizing adjustment
distort the average rate base?
It distorts the average rate base by reflecting
plant as if it were in service the entire year when in
fact the plant is only in service four (4) months or less
of the year.
Why should Idaho Power not be allowed to earn a
rate of return on these plant additions as if they were
in rate base for the entire year?
The Company's earnings should be based on test
year plant additions when they occur because Staff
believes, and the Commission has previously determined,
that an average-year rate base is a better measure for
matching rate base to test year revenues and expenses.
If additional specific plant additions are treated as
year-end rate base, as is done with the annualizing
adjustment, then the test year revenues and expenses will
not match average rate base adjusted for the year-end
additions.
CASE NO. IPC-E- 03 -02/20/04 1551 LECKIE, J.(Di) Staff
What is the best method to match the test year
revenues and expenses to the rate base in this case?
The best way to match the rate base and
revenues and expenses is to allow Idaho Power a true
13 -month average rate base without allowing any
annualizing adjustment.
What other changes to Idaho Power's adjustments
would be necessary if the Commission accepted Staff'
recommendation and denied the annualizing adjustments?
Idaho Power has increased its test year
expenses for this annualizing adjustment through an
increase to annual depreciation expense by $498,427
property tax expense by $120,654 , annual insurance
expense by 834 and accumulated depreciation by
$249,214.Each of these respective expense amounts
increased Idaho Power would need to be reduced to
reflect the appropriate test year expense.The
accumulated depreciation amount would also need to be
reduced by $249 214.
2004 MAJOR PLANT ADDITIONS KNOWN AND MEASUREABLE
ADJUSTMENTS
Please describe Idaho Power s known and
measurable adjustment for the 2004 major plant additions.
Idaho Power evaluated current construction
CASE NO. IPC-E- 03 -
02/20/04 1552 LECKIE, J.(Di) Staff
proj ects in 2004 and determined that there were some
maj or plant proj ects that would close before the end
May 2004.Idaho Power determined that "major " projects
would
CASE NO. IPC-E- 03 -02/20/04 1553 LECKIE, J.(Di) llaStaff
be those with a cost of approximately $2 000,000 or more.
These proj ects included upgrades to the Brownlee-Oxbow
transmission line and the Star , Vallivue , Midrose and
Goshen transmission stations.Idaho Power's proposed
adjustment is an increase to rate base of $18,388,690.
As part of the known and measurable adj ustment, Idaho
Power also includes increases in test year expenses of
$447,375 for depreciation , $112 171 for property taxes,
and $8,199 for insurance.Additionally, accumulated
depreciation is increased by $223 688.
Is there any legal basis for including this
known and measurable adjustment in rate base?
Idaho Code ~61-502A prohibits granting a return
on construction work in progress in rate base with the
exception of short-term construction work in progress.
The statute states as follows:
Except upon its finding of an extreme
emergency, the commission is hereby prohibited
in any order issued after the effective date(February 29,1984) of this act from setting
rates for any utility that grants a return onconstruction work in progress (except short
term construction work in progress) or property
held for future use and which is not currently
used and useful in providing utility service.
As used in this section , short-term
construction work in progress means
construction work that has begun and will be
completed in not more than twelve (12) months.
Except as authorized by this section, any rates
granting a return on construction work inprogress (except short-term construction work
in progress)
CASE NO. IPC-E- 03 -
02/20/04 1554 LECKIE , J.(Di)
Staff
or property held for future use are hereby
declared to be unj ust, unreasonable, unfairunlawful and illegal. When construction work
in progress is excluded from the rate base,
the commission must allow a just, fair and
reasonable allowance for funds used during
construction or similar account to be
accumulated, computed in accordance with
generally accepted accounting principles.
From the information provided by Idaho Power
the 2004 major plant additions meet the definition of
short-term construction work in progress because the
proj ects will have begun and be completed wi thin the
twelve (12) month period
Why is Staff questioning this adj ustment?
The problem with this adjustment is not whether
it could be included in rate base, because the statute
clearly allows its inclusion.Instead , it is a question
of how the cost of these projects should be included in
computing the 13 -month average rate base.I daho Code
~61-502A does not discuss how short-term construction
work in progress will be included to set rates.The
Commission has repeatedly stressed the importance of
matching additions to rate base with revenues and
expenses associated with those plant additions.The
additions must also be known and measurable.I f the
total amount of the plant additions is added to the
average rate base, it will be as if they were in service
through out the entire
CASE NO. IPC-E- 03 -02/20/04 1555 LECKIE, J.(Di) Staff
months of the average.The plant additions were not in
service during any of the test year and therefore the
revenues and expenses for the test year only reflect
Idaho Power I s business acti vi ty as if the plant were not
in service.This treatment is not fair to the
ratepayers.
One possible solution is to make all known and
measurable adjustments to revenues and expenses for these
additions.When plant investments are made , revenues
and/ or expenses al so change; some expenses increase
(i.e., depreciation , insurance, and taxes) but other
expenses decline (i. e., maintenance or power supply) .
Revenues often increase from transactions such as energy
sales to customers, off -system sales, transmission
revenues (firm or non-firm), or ancillary services.
Staff has been unable to identify any attempt by Idaho
Power in its testimony or exhibits to quantify customer
benefits that result from these additions to plant.
Another possible solution is to include the
dollar amount of the additional plant in the 13-month
averaging process as an addition to the last month'
total before dividing by thirteen (13).This would treat
the plant additions as if they were in service at the end
of the year , and then include them in the averaging
calculation for the average rate base.The average rate
CASE NO. IPC-E- 03 -02/20/04 1556 LECKIE , J.(Di)
Staff
base would reflect these additions to Idaho Power'
plant,
CASE NO. IPC-E- 03 -02/20/04 1557 LECKIE , J. (Di) 14aStaff
and the revenues and expenses would more closely match
the rate base.Adding plant completed after the end of
the test year as if it were in service the entire period
is directly contrary to the average rate base
methodology.The average rate base methodology includes
plant added during the test year in rate base only for
the period of the year it was actually in service.
Has the Commission examined this issue in any
previous cases?
To Staff I s knowledge , the Commission has never
ruled that the short-term construction work in progress
should be included in the sum of the months before being
divided by the number of months when an average rate base
is used.This issue does not appear to have ever been
addressed by the Commission.However, the rationale used
by the Commission in the 1986 Boise Water Corporation
rate case (U-I025-51) cited in the annualizing adjustment
discussion above would apply.The Commission has adopted
the general axiom that the average rate base provides a
better matching of revenues and expenses and necessitates
fewer adj ustments, thereby reducing the chances for error
or omission.See also Washington Water Power Company
rate case U-I008-234 , Order No. 20267 at I f the
short-term construction work in progress is reflected for
the full year and not included in the average, it skews
CASE NO. IPC-E- 03 -02/20/04 1558 LECKIE, J.(Di) Staff
the matching between the average rate base and the
revenues and expenses.Including short-term construction
work in progress in the average rate base rather than for
the full year decreases the chance that known and
measurable adjustments to revenues and expenses will be
missed.
Does Staff have a recommendation for the
treatment of the short-term construction work in
progress?
Yes, Staff recommends that the closing balances
for the projects be included in the December 2003 plant
balance in the 13 -month average rate base.This would
treat the plant additions as if they were included into
the rate base average as of the end of December 2003.
Would this treatment address any other
potential problems?
Yes.When a true average rate base is utilized
that includes the closing cost balances for short-term
construction work in progress in the sum of the monthly
totals for the averaging process , Idaho Power has no
incentive to delay the closing of proj ects beyond the
ending month of the average rate base period.A delay
would allow the plant to be included at the end-of-year
value instead of average rate base value.It is
unreasonable and unfair to the ratepayers to have some
CASE NO. IPC-E- 03 -
02/20/04 1559 LECKIE , J.(Di) Staff
plant costs at average rate base values and some at
end-of-year rate base values.
CASE NO. IPC-03-
02/20/04 1560 LECKIE , J.(Di) 16aStaff
If the 2004 major plant additions are included
in the average rate base calculation before dividing by
13 as proposed by Staff , what would the adjustment be?
The known and measurable adj ustment to rate
base would be decreased by $16,974 175.See Staff
Exhibit No. 114.The following known and measurable
adjustments to expense accounts would remain the same:
depreciation in the amount of $447,375, property taxes in
the amount of $112 , 17L , and insurance expense in the
amount of $8 199.Accumulated depreciation would
increase by $223,688 to $447 375.
If the Commission accepts Idaho Power'
proposal to include 2004 major plant additions as if in
service for the full year as a known and measurable
adj ustment , does Staff have recommendations specific to
this methodology?
Yes , the accumulated depreciation should
reflect a whole year of depreciation and should be the
same amount as the depreciation expense in the first year
that the plant is included in rate base.
BROWNLEE - WOODHEAD PARK
What is Staff I s proposed adjustment for the
Brownlee-Woodhead Park?
Staff recommends that the cost of the park
improvements be deferred at this time and reviewed with
CASE NO. IPC-E- 03 -02/20/04 1561 LECKIE , J.(Di) Staff
the relicensing costs for the Hells Canyon Complex.The
total cost of the park improvements is $7 525,237, and
depreciation has accumulated in the amount of $853,653.
Annual depreciation expense for this proj ect in 2003 was
$144 485.
Why does Staff think the cost should be
deferred and reviewed in conjunction with all the Hells
Canyon Complex relicensing costs in the future?
This park was developed under the terms of the
original FERC license approved in 1955 and Exhibit R
(recreational use) approved in 1974.As requi red by the
terms of the original and amended license, Idaho Power
was responsible for providing recreational opportunities
and developing a recreational plan.As a condition of
FERC I S approval of Idaho Power's plan , Idaho Power was
obligated:
...
to cooperate with Federal , State, and
local agencies in providing for optimum
public recreational development and useat the proj ect, and reservation of lands
for such development and use as may be
needed in the future.
Order Approving Exhibit R, 51 F.C. 1327, 1974 WL 11874
, April 16, 1974,(NO. PROJ. 1971).
After the initial development of Woodhead Park
Idaho Power in conjunction with the Idaho Department of
Parks and Recreation determined in 1991 that Woodhead
CASE NO. IPC-E- 03 -
02/20/04
LECKIE, J.(Di)
Staff
1562
Park needed to be expanded and improved.Idaho Power
developed a plan to expand the park to its current status
and
CASE NO. IPC-E- 03 -
02/20/04 1563 LECKIE, J.(Di) 18aStaff
submitted that plan to FERC for approval and an amended
license.In its application for FERC approval dated
November 7 , 1990, Idaho Power stated, "This expansion
will significantly enhance recreational opportunities at
the proj ect , well in advance of the proj ect relicensing
Staff Exhibit No. 115, page 3.process. "The
relicensing process was a consideration when Idaho Power
filed this Application.The plan submitted was a major
reconstruction and enhancement to the existing facility,
expanding the park from 17.5 acres to 65 acres.
Idaho Power acknowledged that " (U) pgrading and
enhancing Woodhead Park will help meet recreational use
demands for the vicinity for many years to come and will
give the recreationalist a higher quality experience.
(See Idaho Power I s Protection , Mitigation and Enhancement
Proposal for Woodhead Park; Staff Exhibit No. 115, page
18. )It is reasonable to conclude that Idaho Power is
hopeful that these additional improvements will
facilitate a smoother relicensing process.
What was Idaho Power's preliminary original
cost estimate for the construction of the park I
reconstruction and enhancements?
Idaho Power originally estimated the cost to be
between $4 and $5 million.(See Idaho Power'
Protection , Mitigation and Enhancement Proposal for
CASE NO. IPC-E- 03 -
02/20/04
1564 LECKIE , J.(Di) Staff
Woodhead Park; Staff Exhibit No. 115, page 20.
Is Idaho Power depreciating the park
improvements?
Idaho Power is depreciating the enhancements to
the park in the current amount of $144 485 per year.
this rate , the park will be fully depreciated in
approximately 50 years.The 331 Structures and
Improvements Account where these items are booked has a
life of 100 years.At the end of 2003, Idaho Power has
accumulated depreciation on the park in the amount of
$853 653.
At this rate of depreciation, will the park I
enhancements be completely depreciated at the termination
date of the current license?
No.The current license expires July 31, 2005.
At the time of the license expiration, only approximately
15% of the total cost of the proj ect will have been
depreciated.
Why does Staff think that the cost of the park
should be deferred and included with the relicensing
proj ect costs?
The extent of the park reconstruction and
enhancements were meant to exceed the life of the current
license term.In Idaho Power I s Depreciation Case
IPC-03-7, Idaho Power filed its case linking
CASE NO. IPC-03-02/20/04 1565 LECKIE, J.(Di) Staff
depreciation rates for hydro assets to the license
period. Staff did not agree with the linkage but this
Idaho Power position supports the rationale that Idaho
Power invested the cost of $7,525,237 for long-term
improvements to the recreational facility that survive
beyond the current license life with the expectation that
the improvements would benefit the relicensing process.
Does the use of the park generate revenues?
Yes, Idaho Power reported annual revenues in
2003 in the amount of $137 236.
What are the expenses for the operation of the
park?
In 2003, Idaho Power reported operating
expenses in the amount of $46 751 and maintenance
expenses in the amount of $141 642.The total expenses
during 2003 for the park were $188,393, producing a
deficit.
Are the ratepayers being asked in this rate
case to pay the cost of this deficit?
Yes, in the amount of $51,157 plus the annual
depreciation in the amount of $144,485.Staff believes
it is reasonable for customers to pay the depreciation
expense in rates but believes the Company should
investigate raising park fees to cover annual operating
expenses.
CASE NO. IPC-E- 03 -
02/20/04 1566 LECKIE , J.(Di) Staff
BIOLOGICAL OPINION
Please explain the nature of the biological
opinion prepared for the Hells Canyon Complex and what
Staff recommends regarding inclusion of these costs into
rate base?
According to Idaho Power , this expenditure was
the total cost Idaho Power expended to defend itself from
a biological opinion prepared and submitted to FERC by
the National Marine Fisheries Services (NMFS).In March
1995, NMFS prepared and submitted to FERC a biological
report that concluded Idaho Power I s Hells Canyon Complex
operation practices would impact Endangered Species Act
species.Idaho Power opposed NMFS' s conclusions and
defended its operational practices.The costs reported
by Idaho Power for its defense in this matter totaled
$654 740; most of these costs were attorney fees incurred
in 2000 and 2001.Idaho Power has capitalized this
amount and included it in its proposed rate base.
Staff obj ects to the inclusion of this amount
on the basis that these costs are an expense and should
be booked as an expense.There is no indication that
these costs will benefit some future period , nor is there
any authorization from the Commission that would allow
these expenses to be deferred.Because the expendi ture
of these costs related to an immediate challenge to its
CASE NO. IPC-03-02/20/04 1567 LECKIE , J.(Di) Staff
mode of operation in the Hells Canyon Complex on or
before 2001
CASE NO. IPC-E- 03 -02/20/04 1568 LECKIE , J.(Di) 22aStaff
the benefits of this expense do not carry beyond Idaho
Power I S defense in that one matter.Without some benefit
that would extend into the test year and beyond, it is
not reasonable for Idaho Power to capitalize these
expenses and include them in rate base.
What is the effect on rate base if these costs
are not allowed?
Idaho Power has included $654 740 in its
proposed rate base amount.This amount has not been
depreciated and there is no accumulated depreciation in
Account 108.Therefore, the total book value of $654 740
for the biological opinion should be removed from rate
base.
SHAREOWNERS I DOCUMENT MANAGEMENT SYSTEM
What is the adjustment Staff proposes for Idaho
Power's addition to rate base for a project entitled
Shareowners I Document Management System?"
Idaho Power is seeking to add $106,275 to rate
base for the total cost of a "Shareowners I Document
Management System.Because IDACORP is the only entity
wi th enough shareowners to require a shareowners
document management system (Idaho Power Company s only
shareholder is IDACORP) , the benefits of this asset flow
mostly to IDACORP.Therefore, it is not reasonable to
assign all of the cost of this system to the ratepayers.
CASE NO. IPC-E- 03 -
02/20/04
1569 LECKIE, J.(Di)
Staff
Staff is recommending that the cost of this system be
shared equally between the ratepayers and the
shareowners .This is the same treatment as that used to
allocate Board of Directors I fees.(See Idaho Power'
Response to IPUC Audit Request # 30; Staff Exhibit No.
116. )
Idaho Power closed the work order on this
project in 2000 and booked accumulated depreciation on
this asset though December 31, 2003, in the amount of
$33,332.The net book value of the asset is $72 943.
One-half of the original cost, or $53 137, should be
removed from Idaho Power's proposed rate base.
Additionally, the full depreciation booked on Idaho
Power's books should remain with Idaho Power as
accumulated depreciation.
Are there other adj ustments that should be made
if one-half of the net book value of this asset is
excluded from Idaho Power's proposed rate base?
Idaho Power has determined that the annual
depreciation for this asset in 2003 is $14 949 and has
included this amount in its annual depreciation expense.
Staff has recalculated the annual depreciation expense
for this asset over the remaining life of five (5) years
in the amount of $14,589.Idaho Power I s annual
depreciation expense should be reduced by $7 295 for
CASE NO. IPC-03 -02/20/04 1570 LECKIE, J.(Di) Staff
IDACORP I S one-half share of the depreciated expense.
IERCO INVESTMENT
What is Idaho Power I S involvement and interest
in the IERCO investment?
The IERCO investment represents Idaho Power I
one-third interest in the Bridger Coal Mine.The Bridger
Coal Mine is jointly owned with PacifiCorp, which owns
the other two-thirds interest.The IERCO account balance
represents Idaho Power I s net investment in the one
balance.
Please explain the adjustment Staff proposes to
Idaho Power I S IERCO investment.
Staff is proposing that the Company's interest
in the IERCO investment be reduced by $280,937.
October 2003, Staff conducted an audit of the property in
service records at the Bridger Coal Mine.That audit
consisted of verifying and comparing a sampling of the
personal property on the books of the Bridger Coal Mine
with the property on site and in service.During the
course of that property in service audit , Staff found
specific assets that were not used and useful at the time
of the audi t .
This adjustment represents the plant in service
and accumulated depreciation (or net book value) of
specific assets as of November 30 , 2003 , divided by
CASE NO. IPC-03-02/20/04 1571 LECKIE, J.(Di) Staff
one-third to represent Idaho Power I s share of net book
value.
CASE NO. IPC-E-03-
02/20/04 1572 LECKIE , J. (Di) 25aStaff
The total book value for the mine as of November 30
2003, is $842 810.This represents a combination of
111 232 in plant with $3,268,421 in accumulated
depreciation.(See Staff Exhibit No. 117.
What specific assets did Staff find that were
not used and useful?
The following assets were not being used in the
mining operation:The dragline #100 and the bulk lube
system , dragline monitoring, and inergin fire system for
the dragline #100; two (2) 62 yard buckets, #163 and
#164; a Hitachi shovel , #202; a lowboy tractor , #791; and
a 1995 Ford Truck , #1792.
What caused Staff to believe the property was
not used and useful?
The dragline was sitting idle on mine property
and mine employees indicated to Staff that the dragline
was for sale.The two buckets were also sitting idle on
the mine property and mine employees indicated to Staff
that the buckets were not being used anymore.When
asked mine employees informed Staff that the Hitachi
shovel was retired.The Lowboy tractor and the 1995 Ford
Anfo Truck were in the mine'junk yard" area used to
store damaged, non-functioning, and obsolete equipment
and materials.
Q. Are there any other Staff adjustments related
to this plant in service adjustment?
CASE NO. IPC-E- 03 -
02/20/04
1573 LECKIE , J.(Di)
Staff
Yes, the mining company is currently expensing
annual depreciation for these assets in the amount of
$400,661.Idaho Power records one-third of this annual
depreciation expense as an element of its annual
expenses. If the assets are deemed to be not used and
useful and therefore subtracted from the Company's IERCO
investment , the annual depreciation on these assets in
the amount of $133,554 should also be excluded from the
Company I S annual expenses.
DANSKIN POWER FACILITY
You indicated that Staff also reviewed the rate
base costs for the construction of the Danskin Power
facility.What were the results of Staff's review?
Idaho Power is asking that the total
construction costs of the Danskin Power Facility in the
amount of $52 484 209 be included in its rate base.
review of work orders indicates that this amount was
properly booked and should not be adj usted.Staff
witness Sterling further discusses Danskin Power Facility
in his testimony.
SECURITY COSTS
Staff also reviewed Idaho Power's request to
include its additional security costs.Does Staff have a
recommendation concerning those costs?
Idaho Power is asking for additional security
CASE NO. IPC-E- 03 -
02/20/04 1574 LECKIE , J.(Di) Staff
costs in the amount of $728,766 to be an addition to rate
base.These costs were incurred by Idaho Power for
increased security at the Company's facilities following
the September 11 , 2001 terrorist attacks.The Commi s s ion
approved the deferral of extraordinary security costs in
its Order No. 28975.It appears that these costs are an
appropriate and reasonable addition to rate base, and
therefore Staff has no objection to their inclusion in
rate base.
PRAIRIE POWER ACQUISITION AND NEZ PERCE SETTLEMENT
Did you look at any other adj ustments and
additions to the rate base?
Yes, I reviewed the Prairie Power Acquisition
adjustment and the Nez Perce Settlement additions to rate
base.Idaho Power purchased Prairie Power in 1992.
part of that purchase, rate base was reduced by $422 264
for unamortized credits.The Nez Perce settlement was
reviewed and approved by the Commission in 1996.
appears that each adjustment is being properly treated
and accounted for , and is an appropriate and reasonable
adjustment to rate base.
IDAHO POWER I S ASSET RETIREMENT OBLIGATION (ARO)
Did Staff review Idaho Power I s asset retirement
obI iga t ion?
Yes , Staff reviewed Idaho Power's treatment of
CASE NO. IPC-E- 03 -
02/20/04 1575 LECKIE, J.(Di) Staff
its asset retirement obligation (ARO) in this rate case
application.In doing this I relied upon the work of
fellow Staff auditor Patricia Harms, who worked
specifically on the accounting treatment of the ARO in
Case No. IPC-03-1 and its presentation in Idaho Power'
books.
What is the asset retirement obligation?
Under Statement of Financial Accounting
Standards 143, entitled "Accounting for Asset Retirement
Obligations"(SFAF 143), entities are required to
recogni ze and account for certain AROs in a manner
different from the way that Idaho Power and other public
utilities have traditionally recognized and accounted for
such costs.Under the accounting method historically
used by Idaho Power, the reasonable cost of removing a
tangible long-lived asset at retirement is included in
the calculation of depreciation rates and recovered over
the useful life of the asset.This is the method used
for ratemaking purposes.
However , under SFAS 143, if a legally
enforceable ARO as defined by the Statement is deemed to
exist, an entity must separately account and report the
liability for the ARO (ARO Liability) on its books.This
recognizes the entire cost of removal up-front while in
ratemaking the cost of removal is included in
CASE NO. IPC-E- 03 -02/20/04 1576 LECKIE, J.(Di) Staff
depreciation expense over the life of the asset.Under
SFAS 143, at the same time the ARO Liability is recorded,
a corresponding and equivalent asset is also recorded on
the entity I s books as part of the cost of the associated
tangible asset.The ARO Asset is then depreciated over
the life of the associated tangible asset.As part of
implementing SFAS 143, Idaho Power eliminated all removal
costs from accumulated depreciation.
What adj ustments associated with SFAS 143 did
Idaho Power make to its books for the rate case?
Idaho Power adjusted its financial statements
by reducing plant in service (Account 101) by $1 577 314
and increasing Accumulated Depreciation (Account 108) by
$106,204,710.The $1 577 314 reduction to the plant
account reverses the 13 -month average of the amount it
posted to Account 101 for the ARO Asset.The
$106,204 710 increase in accumulated depreciation
reverses the 13 -month average of the removal costs that
Idaho Power eliminated from accumulated depreciation
($107 236,162) and the accumulated depreciation
($1 031,452) on the ARO Asset.Both the plant and
accumulated depreciation adjustments are necessary to
appropriately reflect rate base for ratemaking purposes.
Does Staff agree with Idaho Power that this is
the appropriate method to adj ust for ARO?
CASE NO. IPC-03-02/20/04 1577 LECKIE , J.(Di) Staff
Yes, it does.
Does this conclude your direct testimony in
this proceeding?
Yes , it does.
CASE NO. IPC-03-02/20/04 1578 LECKIE , J. (Di) Staff
open hearing.
(The following proceedings were had in
MS. NORDSTROM:With that, I'll tender
this witness for cross-examination.
BY MR. KLINE:
COMMISSIONER SMITH:Mr. Eddi e .
MR. EDDIE:No questions.Thank you.
COMMISSIONER SMITH:Mr. Purdy.
MR. PURDY:No questions.
MR . GOLLOMP:No questions.
MR. WARD:No questions.
MR. MILLER:No questions.
MR. RICHARDSON:No questions.
COMMISSIONER SMITH:Mr. Kline.
MR. KLINE:Thank you, Madam Chairman.
CROSS-EXAMINATION
Good morning, Mr. Leckie.
Good morning.
In this case, the Staff is recommending
that the Commission disallow a couple of annualizing
adjustments for projects completed during the 2003 test
year; is that correct?
That's correct.
CSB REPORTING
Wilder , Idaho
1579 LECKIE (X)Staff83676
And the two proj ects, large proj ects, are
the Bridger unit No.3 rewind proj ect and the
CSB REPORTING
Wilder, Idaho
Brownlee-Oxbow No.2 230 kV transmission line proj ect; is
That I S a general description of those two
You'right.Those proj ects make up a
that correct?
lot of things and for purposes of our
- -
my questions and
your answers , if you would kind of use those terms as
shorthand for the proj ects, I'd appreciate it.
Okay.
For the Bridger unit No.3 rewind , the
cost of that proj ect was 23,200,000, correct,
approximately, approximately $23 million?
m sorry, for the Bridger rewind?
Yes, the Bridger rewind.
I don't believe so.
What number do you have?
8 million --
How much?
661,463.
All right , and then the Brownlee-Oxbow
transmission line project at 14.5 million?
That's correct.
Okay, I transposed some numbers.
maj or proj ects.
1580 LECKIE (X)Staff83676
Mr. Leckie, both of those two proj ects are currently used
and useful , are they not?
Yes.
And they re both providing service to
customers as we speak; is that correct?
I don I t have any reason to believe they I
not.
All right, and they are both being
depreciated for ratemaking purposes, are they not?
Yes.
Now, as I understand the basis for the
Staff's recommendation for disallowance of these two
annualizing adjustments is that they create a mismatch
between revenues and expense; is that a general summary
of the Staff's position on those two adj ustments?
Yes.
And both Mr. Reading or, I'm sorry, both
Mr. Gale and Mr. Obenchain have filed rebuttal testimony
in this case addressing this issue.Have you read that
rebuttal testimony?
Yes.
And after reading that testimony, are you
still convinced that there is a mismatch between revenue
and expenses between these two proj ects?
Yes, I am.
CSB REPORTING
Wilder, Idaho
LECKIE (X)Staff1581
83676
I had to try.In order to understand the
Staff's position, I I d like to talk in some degree of
specifics with respect to at least one of the projects,
the Bridger No.3 rewind proj ect, and the Bridger
project, coal-fired generating project, over in western
Wyoming was built in the early 1970' s; is that your
general understanding?
Yes.
So it's 30 plus years old?
That's right.
And the rewind proj ect that we I re talking
about here, as you ve indicated, is kind of a series of
different things that were done at Bridger, but
essentially, it was a rebuild of the Bridger unit No.
generator along with some other associated equipment; is
that your understanding?
As I understand it, there was the actual
rewind --
Right.
- - which is about 2 million.There was
replacing of the unit controls for another approximately
2 million.There was spent liquor ponds for
approximately 2 million and a submerged dragline for
about 2 million.
Now, until rebuilding the Bridger unit
CSB REPORTING
Wilder , Idaho
LECKIE (X)
Staff
1582
83676
No.3, Idaho Power and PacifiCorp didn I t create any
addi tional capacity at the Bridger plant, did they?
mean, as a result of this work , the plant doesn't make
any more megawatt-hours than it did before; isn't that
right?
Well , I think with the rewind the
efficiency of the generator would be brought back to a
position to where it would operate at the most efficient
level and so I don't have any information that indicates
that there was a significant drop that would cause the
rewind to have to take place, but I would think that with
the rewind , it would operate at the most efficient
level.
And that most efficient level really does
nothing more than get the Bridger No.3 uni t back to
the -- well , back to a place where you would expect it
would be able to generate for purposes of the power
supply costs of the Company; wouldn't you agree?
That's right.
And in the Company's power supply model
that it uses in this case for purposes of revenue
requirement determination , the Bridger rewind was
reflected in that , was it not?
I believe it was.Mr. Hessing would be
the right one that looked at that revenue model.
CSB REPORTING
Wilder , Idaho
1583 LECKIE (X)Staff83676
So to the extent there was any additional
megawatt-hours created as a result of additional
efficiency, that would have already been reflected in the
power supply model , wouldn't you agree?
I would assume it would be there or it
should be there.
So in this particular case, this work
this rebuild work , at Bridger isn't going to produce any
additional revenue, is it?I mean, it's really just
going to simply make the proj ect more reliable and
increase the chances that it's going to be able
actually generate the levels reflected in the
Company's power supply model , would you agree with
that?
It may not increase the revenues , but it
might decrease the costs and expenses in the operation of
the old No.3 unit.
Wouldn't that be reflected in the power
supply modeling?
I don't know for sure.
If you would assume for me that it would
then you wouldn't have a mismatch between revenues and
expenses for this project , would you?
Under that assumption , yes.
And the other annualizing adjustment that
CSB REPORTING
Wilder , Idaho
1584 LECKIE (X)Staff83676
you I re recommending, that the Staff is recommending, be
excluded is the Brownlee-Oxbow No.2 230 kV transmission
line, I think we established that already; right?
Yes.That's not the only annualizing, but
that's the other maj or.
The two big ones, and wouldn't you agree
with me in that particular case , you have the same
situation , here you have the Company rebuilding, you have
the Company adding additional transmission for
reliability purposes, but not increasing the revenue
attributable to the Company, would you agree with that?
Not necessarily.
Why not?
With a new transmission line, there's the
possibili ty of additional revenues for the transmission,
the power over that new line.There is the decreased
cost for maintenance of the old power line as a result of
the new line and there's the potential capacity for
selling excess space on the line to other parties.
And if the Company was able to demonstrate
that this did not contribute to wheeling revenues , make
that assumption , and that it simply improved the
reliability of the existing system , with those two
assumptions, wouldn't you agree with me that there is no
mismatch between revenues and expenses?
CSB REPORTING
Wilder, Idaho
1585 LECKIE (X)Staff83676
No.
And again , why would you not agree with
that?
Because when you look at the test year
revenues and expenses, they reflect the operation of the
old line as opposed to the operation of the new line, and
when you then look at the test year revenue and expenses
that were unadjusted for the new transmission line , they
do not reflect or are not adjusted for the appropriate
operation of that new transmission line.
And in making your recommendation with
respect to the Brownlee transmission line and making your
recommendation that the annualizing expense be excluded,
did you make any analysis of the expense savings that
you re talking about?
We didn't have sufficient information to
do that.
And if those expense savings were
de minimis or quite small, would you agree, then , that it
would not be a mismatch?Would that reduce any mismatch
that you might see?
Well, it makes it difficult for me to look
at a $14 million investment that doesn't produce
revenues , doesn't save expenses and then say that's an
appropriate expenditure.In some way it has to either
CSB REPORTING
Wilder , Idaho
1586 LECKIE (X)Staff83676
increase the revenues of the Company or decrease the
expenses or the Company would not be prudent in making
that investment.
Well , wouldn't you agree with me that an
electric utility with a statutory obligation to provide
reliable service is sometimes going to make investments
in facilities just simply to make sure that it provides
reliable service?
Yes.
And wouldn I t that consideration be totally
separate or couldn t that determination be totally
separate and distinct from whether there's additional
revenue that's going to come from that investment?
That would be one factor.
And wouldn I t you agree with me that the
Commission should look at the individual situation and
make a determination as to whether or not this investment
is for reliability and that there isn't a revenue aspect
to the investment?
Yes.
And if the Commission were to conclude in
the case of the Brownlee transmission and the Bridger
rewind that the revenues associated with those projects
were either
- -
there was no additional revenue or that
additional revenue was de minimis , wouldn't it be fair
CSB REPORTING
Wilder, Idaho
1587 LECKIE (X)Staff83676
for the Commission to conclude that an annualizing
adjustment would be appropriate?
Well , that would be up to the Commission,
but in a previous rate case with the Boise Water Company,
they looked at that specific issue and decided not to
annual i ze .
I recall that.I guess maybe the question
is just as basic as -- is a little more basic than that,
I guess.Isn't it just patently unfair for there to be a
delay of a full return on this investment when it's being
used and useful for the full period of time when the new
rates are going to be in effect, the customers are
getting the benefit of it right now , all of those things,
I mean, I'll get to the question here in a second, I
apologize, but here you've got an asset that's being
used, it's used and useful , it's being depreciated and
it's simply not being - - the utility is not being
permitted to earn any return on that investment, isn'
that just unfair?
Well , I'm not going to characteri ze it as
unfair.What you're looking at is using an average rate
base methodology and that average rate base methodology
by the very nature of it is going to take some assets
that are put into service at the end of that average rate
base period and include them at less than the end-of-year
CSB REPORTING
Wilder , Idaho
1588 LECKIE (X)Staff83676
value.
And I can understand that when you ve got
assets that are kind of going into rate base and then
they're going out of rate base , but here you've got two
very large investments that came into rate base in the
last quarter of the test year and they're going to be in
that , in the Company's assets for the foreseeable future,
I mean , they're going to be there in 2004 , 2005 until the
next rate case and ratepayers are going to be getting the
benefit of that and because of the 13-month average rate
base convention that we use, the Company is going to be
denied a return on those very large investments and
guess my question again is , is that fair?
Well , and I guess I would not on the face
accept those as the very large investments.I mean
$8 million is large to me, but when you look at the
overall picture of what's going in and out of rate base
and the total rate base of $3 billion for the Power
Company, I think that and it's Staff's position that the
Commission hold true to the methodology of the 13 -month
average rate base.
Let's talk a little bit about the known
and measurable changes aspect of this.The Staff is also
recommending that a number of large transmission proj ects
that will be completed before the upcoming summer season
CSB REPORTING
Wilder, Idaho
1589 LECKIE (X)Staff83676
should not be included as known and measurable changes;
is that correct?
We I ve recommended that the known and
measurables not be included.
Okay, and again , just for an example, one
of these , probably the largest one, is the Goshen 345 kV
series capacitor bank; is that correct?I think that'
about $5.5 million.
That's right.
All right , and again, is the Staff'
position here that there I s a mismatch between revenues
and investment or revenues and expense?
Yes , the test year expenses and the test
year revenues do not reflect in any way the operation or
the use of that plant, new plant , into the in-service
plant of the Company.
So essentially the same argument that'
being advanced to - - with respect to the annualizing
adj ustment; is that correct?
Tha t 's correct.
And I'll use the example of the Goshen
345 kV series capacitor bank, are you aware that this
particular capacitor bank is associated with one of the
Bridger lines, one of the lines that brings power from
the Bridger power plant?
CSB REPORTING
Wilder , Idaho
1590 LECKIE (X)Staff83676
All I knew is that it was on the eastern
part of the state.
Would you accept, subj ect to verification
that the Goshen 345 series capacitor is simply a
replacement for a similar capacitor bank that I s currently
on the Bridger line today?
Yes.
All right, and that this capacitor bank
like the Bridger plant, is 30 years old and reaching the
end of its useful life, would you agree with that -- not
useful life, it's starting to get old?
The information I had from the
representatives of Idaho Power indicated that it was
scheduled to be redone and repaired and updated.
And that's going to be accomplished at the
time that the Bridger plant is down for maintenance, is
it not?
I didn't know that.
And all we're really talking about here is
replacing an existing capacitor bank with a new capacitor
bank; correct?
Yes.
And , to your knowledge, is there any
additional revenue that's going to be associated with
this new capacitor bank?
CSB REPORTING
Wilder , Idaho
1591 LECKIE (X)Staff83676
I have no information on that.
You didn't look at that?So if it's just
simply - - make this assumption , if it's simply a
replacement of a capacitor bank with a new capacitor bank
and it doesn't increase the ability of the line to carry
addi tional loads or to engage in any kind of wheeling
transactions, would you think there would be any
additional revenue associated with it?
It would be difficult , I think , to
identify specific revenues associated with that.
All right, and then the other known and
measurable adjustments all relate to additional
facilities that the Company is constructing on its, I'll
call it, backbone transmission system in the Treasure
Valley, would you agree with that , if you know?
All I know is there is a Star station
transmission and feeders , a Valli vue station transmission
and feeders and a Midrose station.
Would you accept , subj ect to verification
that these are all transmission facilities and equipment
that are being placed into service to increase the
reliability of the Company's system?
Well , and I'm trying to recall a
conversation I had in regards to these and it seemed to
me that these were being put into service to help service
CSB REPORTING
Wilder , Idaho
1592 LECKIE (X)Staff83676
the growth that were going on in these particular
areas.
So at some time in the future when growth
exceeds the capacity of the existing system, the Company
needs to have these facilities in place to accommodate
that , would you agree with that?
Yes.
And isn't this is a classic example of
building something to ensure reliability as compared to
achieving additional revenue?
Well , I'm not sure I know what you mean
when you say " a classic example.It's an example of
that.
All right.I mean , an electric utility
from time to time has to upgrade its facilities in order
to make sure that its customers continue to receive
reliable service and when it does that, if it adds some
additional capacity in anticipation of growth , that'
really not adding additional revenue today, is it?
Not today.
I'd like to spend a little time now
talking about the recommendation that Staff has made to
exclude the Company s Woodhead Park recreation facility
in Hells Canyon and the Staff's recommendation that it be
excluded from the Company's rate base and that is the
CSB REPORTING
Wilder , Idaho
1593 LECKIE (X)Staff83676
Staff's recommendation , is it not?
The recommendation is it's not to be
included in this rate case , but that it be deferred and
be considered as part of the relicensing cost when the
Hells Canyon relicensing costs come before the
Commission.
Does Staff contend that Woodhead Park is
not currently used and useful?
No.
And does the Staff contend that the
Company's investment in Woodhead was imprudent?
Not - - the reason I hesitate is that it I S
our contention that the park was built with the view of
satisfying not only the current license requirements but
also the requirements well into the future which would
include the relicensing requirements.
But the decision to go ahead and do the
park proj ect was not an imprudent decision on the part of
the Company?
No.
And does Staff contend that Woodhead Park
is not currently providing benefits under the Company'
FERC license for the Hells Canyon project?
It is meeting the obligation that the
Company has to provide recreational facilities as part of
CSB REPORTING
Wilder , Idaho
1594 LECKIE (X)
Staff83676
that current license.
And were you in the room when Idaho Power
Company vice president John Prescott testified the other
day?
Yes.
Have you read Mr. Prescott's testimony?
Yes.
And Mr. Prescott in his testimony
identifies the Woodhead Park as a proj ect that has two
primary purposes; do you recall that testimony?
No, I'm sorry.
Well , let me see if I can refresh your
memory.Mr. Prescott -- and if you come up short again
why, let me know.
Okay.
Mr. Prescott testified that the Woodhead
Park proj ect performs two things:Its primary purpose
was to satisfy the Company s current obligation under its
FERC license and its secondary benefit was to benefit the
relicensing process.Now , do you recall that
testimony?
Yes.
It I S my understanding that you are
recommending that the Company continue to depreciate the
Woodhead Park investment; is that correct?
CSB REPORTING
Wilder, Idaho
1595 LECKIE (X)Staff83676
Yes.
And again , don I t you think that's really
unfair that here is a proj ect that is used and useful
it's providing benefits to customers, heck , it's been
providing them since 1994 , for heavens sake , and it I S
being depreciated, but it's not going to be included in
rate base and the Company isn't going to earn a return on
it until the Hells Canyon licensing is completed?
It's our position that there's clearly a
part of that park capital costs that were done with the
eye towards the relicensing process and that those ought
to be captured in the relicensing deferral and considered
at that time.
But you're actually recommending 100
percent of it be deferred until the licensing process is
completed.
Yes.
So you're going to have from 1994 until
whenever the licensing process is completed of
depreciation , that's your recommendation; correct?
Yes.
But no return on the investment over that
same time period?
Well, it would earn the same interest rate
that those funds that are in the deferral earn pending
CSB REPORTING
Wilder, Idaho
1596 LECKIE (X)Staff83676
AFUDC?
Yes, and --
But not - - I I m sorry, I didn't mean to
- - pending a consideration by the
Commission of those costs.
CSB REPORTING
Wilder, Idaho
It would earn at the AFUDC rate as
compared to the overall rate of return rate?
That's right.
And, of course , there's a difference
between those two, is there not, because primarily the
Yes.
Do you know if any of the Woodhead Park
investment was included in the last test year that the
Company had , last rate case?
, I don'
MR. KLINE:That completes my examination
COMMISSIONER SMITH:Thank you, Mr. Kline.
Do you have redirect, Ms. Nordstrom?Oh,
interrupt.
m sorry, I did it again.
Does the Commission have questions?
questions from the Commission.
MS. NORDSTROM:Thank you.Mr. Leckie,
equi ty cost?
Madam Chairman.
1597 LECKIE (X)Staff83676
before I get started, I guess I wanted to address the
Exhibit No. 113.Actually, it has been filed with the
Commission.It was attached to Alden Holm I s supplemental
testimony.
COMMISSIONER SMITH:, I see.
MS. NORDSTROM:They were filed all at one
time for simplicity and some of the adjustments were
COMMISSIONER SMITH:So it appears the
Commissioners' notebooks just need to be straightened
I have to locate it.out.Thank you.
MS. NORDSTROM:Thank you.
REDIRECT EXAMINATION
BY MS. NORDSTROM:
Mr. Leckie, there's been a lot of talk
about a mismatch between expenses and revenues that are
involved in the annualizing and known and measurable
adjustments proposed by Staff.Are these mismatches easy
to identify or eliminate?
No, they're very difficult.
And in coming to your recommendation for
these adj ustments, did you review how the Commission has
treated this thorny problem in the past?
Yes.In the 1986, I think, Boise Water
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Wilder, Idaho
1598 LECKIE (Di)Staff83676
case, they called it a quagmire in terms of trying to
understand non-revenue producing or expense saving and
how that would affect the addition of plant in-service
and in that particular case, the Commission looked
specifically at the issue that is being presented by
Idaho Power in this case and that is the rate base
determined on a 13-month average with then adding
specific assets at end-of -year values and end-of -year
values is what the annualization adjustment does for the
assets or the plant in-service that the Company is asking
to annualize , and so they indicate that it's just a very
hard or those are elements that are very hard to identify
and because of that, they tried to stay true to the
averaging process.
Have there been times in the past where
the Commission has deviated from the methodology?
Yes.
And do you think that those deviations are
similar to the facts that are before the Commission in
this case today?
, and in fact, in the Commission Order
for the Boise Water case, they indicated that they would
look at annualization in kind of three circumstances:
one would be high inflation; another would be high
interest rates or , I I m sorry, high inflation , explosive
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Wilder , Idaho
1599 LECKIE (Di)Staff83676
growth; and then the last area is , they call it, very
large, discrete construction proj ects for utili ties,
electrical utili ties, and so I looked to see if any of
those three exceptions would apply to the annualization
adj ustment of the Company.We don't have explosive
growth, we don't have high inflation and so I looked to
see if it qualified as very large, discrete construction
proj ects.The Commission has in the past identified
three of those and have essentially allowed
annualization.
One was the Valmy I proj ect for $117
million.One was the Swan Falls project for $55 million,
and one was the Cascade proj ect for $23 million, and
think that those three proj ects are clearly
distinguishable from the proj ects and the plant that is
currently being considered by the Idaho Power Company for
annualization and those distinctions are that all three
of those proj ects received prior Commission approval,
they are power generating facilities, they were very
large and they were distinct and not an aggregate of
smaller proj ects and in the current proj ects, there are
no prior approvals , and I'm not indicating by any means
that there ought to have been, but there is none , they
are not power generating, they are relatively small when
you compare them to the amounts and in some of the cases,
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Wilder , Idaho
1600 LECKIE (Di)
Staff83676
it's an aggregate of the projects.They aggregate $2
million projects into 8 or 10 million.
Assuming that an analysis were to be done
regarding the mismatch between revenues and expenses and
how that would relate , in your opinion, if an investment
is for reliability, is it reasonable to expect additional
revenues or reduced expenses may result if the upgrades
are in service for a full year?
Yes, I believe so.I believe in terms of
the matching principle that you have a better opportunity
to see the matching occur when those items of plant are
in service for a full year.
In your discussion with Mr. Kline
regarding power supply costs, isn't it true that
operation and maintenance expenses are in the test year
resul ts and not adj usted solely in the power supply?
Yes.
If facilities are built for growth and
reliability, is it possible that the excess capacity
could be used for growth?
Yes , and I identified, I think , as an
example with the transmission line where there could be
additional wheeling or there could be capacity there for
other parties.
You also were asked questions on the
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Wilder , Idaho
1601 LECKIE (Di)Staff83676
13 -month average and if the 13 -month average were
adopted , didn't you also express concern that a company
may delay investment so it could be a known and
measurable for the full year rather than simply include
it in the average?
Yes, I did.In my testimony I indicated
that there may be an opportunity if known and measurables
are included in at full value and plant that is within
the 13-month average period, it is only included in at
the average that there would be an incentive for the
Power Company to delay the completion of a proj ect
outside the averaging period so that they would have the
benefit of a full value known and measurable
adjustment.
There was also some discussion regarding
the Woodhead Park improvements and what makes you think
that the park improvements are geared for relicensing
rather than just the current license?
Well, the park that was there under the
current license was substantially smaller , it had less
improvements , graveled roads , docking facilities were
substantially less.Additionally, when they built it,
they built it substantially more than the -- with an eye
and I'm looking at their plan that they prepared, well
into the future and additionally, the depreciation aspect
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Wilder, Idaho
1602 LECKIE (Di)Staff83676
of the assets would be well beyond the current
relicensing.Now , that depreciation aspect isn't in and
of itself , but it does show that the Company did this
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Wilder , Idaho
park with an eye towards the relicensing process in 2005
MS. NORDSTROM:
further questions.
Thank you.I have no
and beyond.
COMMISSIONER SMITH:Thank you, Ms.
Nordstrom and thank you, Mr. Leckie.
(The witness left the stand.
MR. STUTZMAN:Thank you, Madam Chairman.
Staff next calls Keith Hessing to the stand, please.
KEITH HESSING,
produced as a witness at the instance of the Staff
having been first duly sworn, was examined and testified
DIRECT EXAMINATION
Good morning.
as follows:
Good morning.
Please state your name for the record.
BY MR. STUTZMAN:
My name is Keith Hessing.
1603 HESSING (Di)Staff83676
And how are you employed?
I I m employed by the Idaho Public Utilities
Commission as a Staff engineer.
CSB REPORTING
Wilder , Idaho
And in that capacity, did you prepare and
prefile direct testimony in this case dated February
20th , 2004?
Yes, I did.
Does that consist of approximately 25
Yes.
Did you also prepare and prefile exhibits
pages?
numbered 118 through 123?
Yes.
Do you have any changes or corrections to
your testimony or exhibits?
Yes, I have a couple of corrections on
page 8.As a result of some corrections that Mr. Holm
made to his testimony this morning, some of the numbers
here on lines 7 and 8 have changed a little bit.On 1 ine
7, the first number there should read 498 183,182 , and
the number at the end of that line should read
14,221 813 , and on line 8, the percentage now , I believe
Okay, is that all the corrections you have
to your testimony?
is 2.94.
1604 HESSING (Di)Staff83676
Yes, it is.
Wi th those changes, if I asked you the
same questions today, would your answers be the same as
contained in your prefiled testimony?
Yes, they would.
MR. STUTZMAN:Thank you , Mr. Hessing.
Madam Chairman , I ask that the prefiled testimony of
Keith Hessing be spread on the record as if read and
Exhibits 118 through 123 identified on the record.
Mr. Stutzman.
COMMISSIONER SMITH:Thank you
ordered.
If there is no objection , it is so
(The following prefiled direct testimony
of Mr. Keith Hessing is spread upon the record.
CSB REPORTING
Wilder , Idaho
1605 HESSING (Di)Staff83676
Please state your name and business address for
the record.
My name is Keith D. Hessing and my business
address is 472 West Washington Street, Boise , Idaho.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
Commission as a Public Utili ties Engineer.
What is your educational and experience
background?
I am a Registered Professional Engineer in the
State of Idaho.I received a Bachelor of Science Degree
in Civil Engineering from the Uni versi ty of Idaho in
1974.Since then , I have worked six years with the Idaho
Department of Water Resources , and two years with
Morrison-Knudsen.I have been continuously employed at
the Commission since August 1983.
As a member of the Commission Staff, my primary
areas of responsibility have been electric utility power
supply, revenue allocation and rate design.
What is the purpose of your testimony in this
proceeding?
My testimony addresses Jurisdictional
Separations, Class Cost of Service, some Power Cost
Adjustment (PCA) components and cloud seeding.
Please summarize your testimony.
CASE NO. IPC-O3 -
02/20/04 1606 HESSING, K.(Di)
Staff
I recommend that the Commission accept the
coincident peak (12CP) Jurisdictional Separation
Methodology proposed by the Company to allocate costs to
the Idaho jurisdiction.This method applied to Staff'
total Company Revenue Requirement results in an Idaho
Jurisdictional Revenue Requirement of $498,758,249, which
requires an average 3.06 percent rate increase to recover
an additional $14 796,880 revenue requirement.
Staff accepts the weighted 12 coincident peak
(WI2CP) methodology proposed by the Company for the
purpose of allocating costs to the Company's Idaho
customer classes.Staff witness David Schunke proposes
some non-cost based modifications to these cost of
service results that become Staff I s revenue allocation
proposal.
I review the Company's Power Cost Adj ustment
(PCA) calculations that change as a result of a general
rate case.Staff recommends that the Commission accept
the Company's proposed changes except for the changes to
the Expense Adj ustment Rate for Growth.The Company
proposes that the rate used to adjust actual power supply
costs to remove the costs of load growth be the embedded
cost of power supply which is 7.30 $/MWh.I propose that
these changes from normal power supply costs occur at the
marginal cost of power supply and, therefore , the
CASE NO. IPC-O3-02/20/04 1607 HESSING , K.(Di) Staff
marginal cost rate of 29.41 $/MWh should be used in the
calculation.
Finally, my testimony discusses the Company'
cloud seeding program including its effects on the PCA.
I propose that there are questions regarding the program
that remain unanswered and that need to be answered
before the Commission can decide whether or not to accept
the costs include in this case.My testimony includes
some of those questions.
JUR!SDICTIONAL SEPARATIONS
What are Jurisdictional Separations?
It is the process used to divide Idaho Power
Company's annual costs among the jurisdictions it serves.
In general the process identifies the Company I s costs as
related to the supply of energy, peak demand, or the
number of customers.The costs are then divided to the
Idaho, Oregon or Federal Energy Regulatory Commission
(FERC) Jurisdictions based on each jurisdiction I
proportional amount of each of these items.The FERC
Jurisdiction consists of wholesale sales to other
utilities.The Jurisdictional Separation process results
in the Idaho Revenue Requirement, which is the amount of
the Company's total normal annual Revenue Requirement
that is caused by Idaho ratepayers and that must be
recovered from Idaho ratepayers.
CASE NO. IPC-O3 -13
02/20/04 1608 HESSING, K.(Di) Staff
What has changed since the Company's last
general rate case that affects Jurisdictional
Separations?
Big changes have occurred in the allocation
factors.For example, the number of customers in Idaho
and on the total System grew substantially since the last
rate case, but the Idaho customer allocator only grew
about 1 percent.The story is very different for the
demand and energy allocators.Idaho's share of total
Company peak demand grew approximately 8 percent and
Idaho's share of total energy use grew approximately 9
percent.In all three cases Idaho's share of the total
has increased.Because these are the characteristics
used to divide or allocate costs among the jurisdictions,
the Idaho Jurisdiction has become a larger share of the
Company's total costs of providing service.
Please explain in more detail the changes that
have occurred in these allocators since the Company'
last general rate case.
The addition of 100,000 new customers in Idaho
did not substantially change the Idaho customer allocator
because proportional growth occurred in the Company
other jurisdictions.The growth in the relative
percentages of the energy and coincident peak demand
allocators requires more explanation.Total Company
CASE NO. IPC-O3 -
02/20/04 1609 HESSING, K.(Di)
Staff
energy consumption has declined and total Company peak
demand has not increased as fast as peak demand in Idaho.
There are a number of factors at play here.The large
increase in customers increased Idaho Peak demand and
energy requirements and Idaho Power lost its single
largest customer , FMC/Astaris.Since Idaho Power's last
general rate case , nearly all of its FERC Jurisdictional
contract sales expired as originally designed so that the
Company's resources could be fully utilized to supply its
load growth.These expired contracts practically
eliminated FERC Jurisdictional energy and peak demand.
When Idaho's share of peak demand is calculated, the
Idaho Jurisdiction becomes responsible for an additional
8 percent share of total Company demand-related costs.
When Idaho's share of total energy is calculated, Idaho
becomes responsible for an additional 9 percent of total
Company energy-related costs, not only because Idaho'
energy requirements increased but because total Company
energy requirements decreased.
Have you prepared an exhibit that shows how
these allocation factors have changed since the Company'
last general rate case?
Yes.Staff Exhibit No. 118 shows these
changes.There are several different Energy, Demand and
Customer Allocators used in the Jurisdictional
CASE NO. IPC-O3 -02/20/04 1610 HESSING, K.(Di)
Staff
Separations Study.The exhibit includes one of each for
illustrative purposes.
Why has the Company not entered into firm
contracts to sell the unused energy made available by the
expiration of the FERC jurisdictional contracts?
Doing so would reduce Idaho's peak demand and
energy allocators.However, the Company has also changed
the load and water planning criteria in its Integrated
Resource Plan.In response to high costs experienced by
the Company and its customers in 2000 and 2001 when
streamflows were low and market prices were extremely
high , the Company now plans to meet its load during low
water conditions with reduced reliance on market
purchases.This change in planning criteria, coupled
with new customer load growth , has all but eliminated
excess energy available for new firm wholesale contracts.
What happens to the uncommitted capacity that
is being held in reserve to meet above normal load and/or
below normal streamflow conditions?
In low water or high load conditions , the
reserve capacity is available to the Company and its
customers to meet load at a fixed price that will usually
be below the cost of purchasing market power.In normal
or above normal water conditions when the costs of
generating with these resources is below market price,
CASE NO. IPC-O3 -02/20/04 1611 HESSING , K.(Di)
Staff
Idaho Power will sell the power and credit the revenues
against expenses , which reduces customer rates.In this
case, these benefits are captured in the power supply
modeling process that establishes normal power supply
costs included in base rates.On a year-by-year basis,
deviations from base power supply costs are captured in
the PCA.
Does Staff agree with the Jurisdictional
Separations process used by Idaho Power Company?
Yes.The Company used the same 12CP
methodology that it has used for more than 20 years.
is appropriate for changes in Company costs and changes
in jurisdictional use characteristics to change customer
rates.However , without compelling reason , it is not
appropriate to cause additional rate changes due simply
to change in allocation methodology.In its analysis
Staff used the Company's methodology and jurisdictional
allocators with Staff's proposed accounting adjustments
to determine the Idaho Jurisdictional revenue
requirement.
What are the results of Staff's Jurisdictional
Separations process?
Staff I s cost of service results , revenue
allocation to classes and rate designs are based on a
total Idaho Jurisdiction revenue requirement initially
CASE NO. IPC-O3 -02/20/04 1612 HESSING, K.(Di) Staff
determined to be $499 161,903 which is an increase of
$15 200,534 , and results in a 3.14 percent average
increase in rates.After that initial determination
Staff auditors continued to examine specific items in the
Company's revenue requirement, which ultimately reduced
Staff's recommended Idaho Jurisdictional revenue
requirement to $498,183,182, an increase of $14 221 813,
or a 2.94 percent average rate increase.Because class
cost of service studies , revenue allocations and rate
designs involve complicated issues and analysis, it was
necessary for the Staff members working on those issues
to prepare their recommendations before the Staff
audi tors had concluded their analysis.Accordingly,
Staff testimony on revenue allocation , cost of service
and rate design are based on the initial Staff
determination of the Company's Idaho Jurisdictional
Revenue Requirement.Staff Exhibit No. 119 summarizes
the results of Staff's jurisdictional separations study.
Staff witness Schunke' s testimony provides revenue
allocation and rate design guidelines for the
Commission's consideration that accommodate the reduced
Staff revenue requirement proposal.
COST OF SERVICE
What is a cost of service study?
A cost of service study divides the Idaho
CASE NO. IPC-O3-02/20/04 1613 HESSING, K.(Di) Staff
Jurisdictional Revenue Requirement among the Company I
various customer classes based on the cost-causing
characteristics of the classes.The process is similar
to the Jurisdictional Separations process.Allocators
are developed for each customer class as percentages of
the Idaho total for energy use, contributions to monthly
coincident peak demand and numbers of customers.These
allocators are then used to distribute the total Idaho
Revenue Requirement to the various customer classes.
What class cost of service methodology did the
Company use?
The Company used substantially the same
methodology that it has used in its last two general rate
cases.The method is called the weighted 12 coincident
peak (WI2CP) method.For the allocation of production
related costs, this method weights monthly coincident
peak demands by the marginal cost of providing for those
demands and averages the results with unweighted 12CP
resul ts.In months when the Company is not expecting a
peak demand deficit , a zero weighting is applied.When
seven of the months are weighted at zero, the allocators
become the average of , what amounts to, a weighted 5CP
methodology (the remaining five months of coincident peak
demands) and an unweighted 12CP methodology.
The same method is used for the allocation of
CASE NO. IPC-O3-02/20/04 1614 HESSING, K.(Di)
Staff
transmission related costs except on the transmission
system there are nine months when the Company does not
expect peak demand deficits.Therefore, only three
weighted months are averaged with the 12CP numbers to
obtain the proposed allocation factors.The maj or energy
allocator is calculated based on monthly energy use
weighted by the monthly marginal cost of energy.It is
not averaged with other unweighted allocators.
Steam and Hydro production investment are
classified as related to demand or related to energy
based on an Idaho Jurisdictional Load Factor (the ratio
of average use to peak use) of 55.26 percent.This means
that 55.26 percent of these investments are allocated to
customer classes based on energy use and the remaining
amount is allocated based on peak demand.
What has changed since the Company's last
general rate case ten years ago that affects cost of
service?
There have been many changes.A few of the
changes are: the addition of 100 000 new customers, the
loss of the FMC/Astaris load , the change in the Company'
load and water planning criteria to a more conservative
position , the deregulation of the wholesale electric
market, and the change in the Company s load/resource
characteristics from being energy constrained to capacity
CASE NO. IPC-O3-02/20/04 1615 HESSING , K.(Di) Staff
constrained.
How might these changes affect cost of service
results?
These changes affect the Company I s underlying
costs, the energy and capacity allocators applied to each
customer class , and the marginal costs used to weight the
allocators.Virtually everything that affects cost of
service, except the basic methodology, has changed.
Please describe the cost of service analysis
performed by Staff.
Staff used the Company's W12CP methodology that
has been accepted by the Commission in past proceedings.
Staff also used the weighting factors and associated
methodology proposed by the Company in recognition that
capaci ty and energy are more costly to obtain in some
months of the year.Staff recognizes that weighted
months , some of which were weighted at zero, averaged
wi th unweighted months, creates demand allocators that
are more complex than those used in the past.Staff can
accept the use of some zero weighted months because they
are averaged with unweighted months and because they
coincide with the months where no capacity constraint is
expected.Staff Exhibit No. 120 shows the results of
Staff's Cost of Service Study.In his testimony, Staff
witness Schunke proposes a modified allocation of revenue
CASE NO. IPC-O3 -
02/20/04 1616 HESSING, K.(Di) Staff
requirement to customer classes that is not entirely
based on cost of service results.
Are unweighted and zero weighted months the
same thing?
No.If the peak demand for a month is zero
weighted, it is multiplied by zero and no value is
included in the calculation of the weighted allocator for
that month.If the peak demand for a month is
unweighted , the actual coincident peak demand is used in
the calculation of the allocator.
How many cost of service studies did Staff
perform?
Staff performed three cost of service studies.
I have already described the first one which is the study
recommended by Staff.
What was the second study performed by Staff?
The second study is a weighted 12CP study with
the weighted portion of the June allocator weighted at
zero.The resulting ratio was averaged with the
unweighted ratio to obtain the final allocators.The
resul ts of this study are shown on Staff Exhibit No. 121.
The results of this study showed a decrease in the
required increase for the irrigation class.The increase
dropped from 47.2 percent to 44.5 percent.
Please discuss Staff's third cost of service
CASE NO. IPC-O3-
02/20/04 1617 HESSING, K.(Di) Staff
study.
The third study is a traditional unweighted
12CP study.The analysis removed all marginal cost
demand and energy weightings used to calculate
allocators.Weightings were removed in the calculation
of production and transmission demand allocators and for
the calculation of the energy allocator.Staff Exhibit
No. 122 shows the results of the study.When all
weightings were removed, which is the same as setting
them at 1 , the required increase in irrigation rates
dropped again, this time to a 29.1 percent increase.
course, any time the allocation drops for one class the
other customer classes pick up the difference to produce
the revenue required to cover the Idaho jurisdictional
revenue requirement.
Why did Staff perform the second and third
studies?
The results of the Company's W12CP methodology
require a substantial increase to bring the irrigation
class to full cost of service, as might be expected with
capacity and energy allocators more heavily weighted in
summer months.Staff wanted to know how sensitive class
allocations , especially irrigation class allocations, are
to allocation factor changes.All three studies show the
irrigation class requiring an increase far above any
CASE NO. IPC-O3 -
02/20/04 1618 HESSING, K.(Di) Staff
other class.Using the Company I s methodology, as Staff
did in its first study, the irrigation class would
require an increase five times the next highest class
increase.
Please compare the effects of the unweighted
12CP methodology and the Company's W12CP methodology on
the Residential customer class.
The results of the weighted 12CP study showed a
08 percent decrease for residential customers.
Unweighted study results showed residential rates
requiring a 1.71 percent increase.Given the residential
customer's summer air conditioning load these results may
seem inconsistent.However, a more detailed review of
residential load data provides an explanation.The
winter heating load is greater than the summer air
conditioning load and January and February are zero
weighted in the weighted 12CP production allocator.
Also, all winter months are zero weighted in the weighted
12CP transmission allocator.The result is a relatively
small effect on residential cost of service regardless of
the allocator weightings used in the cost of service
study.
Why did Staff choose the Company's proposed
cost of service methodology including its allocator
weightings?
CASE NO. IPC-O3 -02/20/04 1619 HESSING, K.(Di) Staff
Staff believes that demand-related plant
investments are driven by low hydro conditions and high
loads in the critical peak months.It is the demand in
these critical months when the system is capacity
constrained that is most relevant in this analysis.
Therefore, any analysis that does not weight the critical
months more heavily than shoulder months does not
correctly reflect forward-looking demand related costs.
The Company s study gives heavier weighting to the five
cri tical months of June , July, August , November and
December.Therefore, Staff believes that the monthly
weightings are justified and that the Company's cost of
service methodology is reasonable.
THE POWER COST ADJUSTMENT (PCA) MECHANISM
What is the PCA?
In general , the PCA is a rate adjustment
mechanism that annually adjusts customer rates to recover
or refund 90 percent of above or below normal load
adjusted power supply costs.Each year the PCA is
composed of a forecast or predicted component and a true
up component.
What PCA items does your testimony discuss?
Base power supply costs are established in a
general rate case and those are discussed in Staff
witness Rick Sterling's testimony.From the process that
CASE NO. IPC-O3 -02/20/04 1620 HESSING, K.(Di) Staff
establishes base power supply costs comes the PCA
forecast, which I will discuss.I will also discuss the
load adjustment and some other components of the PCA
calculation.
How will the results of this rate case change
the PCA?
The normalized power supply costs established
in this proceeding will be included in the base rates of
each customer class.The annual proj ection or forecast
of power supply costs based on water conditions will also
change.A change in base power supply costs will cause a
recalculation of the predictive formula that relates
April through July Brownlee inflow to Net Power Supply
Costs.Each April this formula along with the National
Weather Service runoff forecast is used to proj ect net
power supply costs for the coming year.Company witness
Greg Said discusses this calculation in his direct
testimony beginning at page 16.Page 19 of his testimony
shows the Company-proposed forecast formula.Company
Exhibit No. 35 shows the input data and regression
resul ts.
Does Staff agree with the Company s calculation
of the forecast formula?
Yes.Staff has not adj usted the Company'
power supply model results in this case and proposes no
CASE NO. IPC-O3 -02/20/04 1621 HESSING, K.(Di) Staff
changes in the forecast methodology other than exclusion
of the FMC/Astaris adjustment proposed by Company witness
Said (Direct Testimony, page 19, lines 17-24).
Therefore, Staff calculates the same forecast formula as
the Company.
Does the Company propose to update other PCA
computations?
Yes.Company Exhibit No. 36 shows four PCA
computations that Company witness Said proposes to
update.He updates "Normalized PCA Expenses" which is
normalized power supply expense from the Aurora model
plus normalized CSPP costs.The new number is
$94 101,100 per year.
The Company updates the "Normalized Base PCA
Rate " which is normalized PCA expenses divided by
normalized system firm sales.The new rate is .7315
C::/kWh.
Idaho Power also updates the " Idaho
Jurisdictional Percentage" which is used to allocate
abnormal power supply costs to Idaho.It is calculated
by dividing normalized system firm load by Idaho
jurisdictional firm load.The number is 94.1 percent.
Finally, the Company updates the "Expense
Adjustment Rate for Growth" which is used to remove power
supply cost increases associated with growth.Mr. Said
CASE NO. IPC-O3 -02/20/04 1622 HESSING, K.(Di) Staff
calculates 13.98 $/MWh in the exhibit but uses a
different rational to propose 7.30 $/MWh in his
testimony.
Is it appropriate to update these calculations
in this general rate case?
Yes.These calculations are intended to be
updated in a general rate case.
Does Staff accept the results of the updated
calculations for use in the PCA?
Staff accepts the Company s updated
calculations as shown on Company Exhibit No. 36, except
for the calculation of the Expense Adjustment Rate for
Growth.Staff disagrees with the Company's rational for
and calculation of this adjustment.
Please discuss the Expense Adjustment Rate for
Growth.
Such a discussion requires some basic PCA
background.The PCA captures actual booked monthly power
supply costs that are above or below the normal values
established by the Commission and included in base rates.
These differences from normal power supply costs result
from abnormal streamflows, abnormal market prices,
abnormal fuel prices, abnormal loads that may be caused
by weather , buy-back programs, conservation , or load
growth or loss.The Expense Adj ustment Rate for Growth
CASE NO. IPC-O3-
02/20/04 HESSING , K.(Di)
Staff
1623
(EARG) is aimed very specifically at the variable cost of
power supply caused by changes in load.When load grows,
the EARG is part of the mechanism that removes the above
normal costs of power supply captured in PCA accounts
that are associated with load growth.In essence this
adjustment removes the power supply effects of load
growth and leaves the effects of abnormal water
condi tions and market prices, which the PCA is designed
to capture.
When loads are below normal, the EARG
multiplier is part of the mechanism that prevents the
Company from losing both the retail revenue and power
supply cost savings that are credited back to customers
through the PCA.Again, this adjustment removes from the
PCA the power cost effects of the loss in load and leaves
the effects of abnormal water and market prices in the
PCA.When these adjustments are appropriately made using
the correct multiplier , the Company neither over-collects
nor under-collects power supply costs through the PCA
when consumption is higher or lower than normal.The
difference between power supply costs incurred to serve
new customers and embedded power supply costs collected
in rates must still be recovered in a general rate case
just as it has been in the past.The PCA is left to
capture predominantly power supply cost changes that
CASE NO. IPC-O3-02/20/04 1624 HESSING, K.(Di)
Staff
result from abnormal water and market price conditions
that would not be captured under the normal conditions
assumed in a general rate case.
You mentioned that the load adj ustment
mechanism works if the correct value is used as the
Expense Adjustment Rate for Growth.What is the correct
EARG value?
Power supply costs associated with load changes
are captured in the PCA at the marginal cost level.
Therefore, they must be removed at the marginal cost
level.In Response No.3 0 to the Second Production
Request of the Idaho Irrigation Pumpers Association
Idaho Power identified the average annual marginal cost
of energy as 27.01 $/MWh.This is Staff Exhibit No. 123.
At the customer level , which includes 8.9% transmission
and distribution losses , this becomes 29.41 $/MWh.
propose this as the appropriate EARG.
What is the current EARG and where did it come
from?
The current EARG is 16.84 $/MWh and it was
established in Case No. IPC-E- 92 -25, the case that first
established Idaho Power's PCA mechanism.Staff proposed
16.84 $/MWh in that case as a surrogate for the average
marginal cost of power supply.It was calculated as the
average of Boardman and Valmy fuel costs which at that
CASE NO. IPC-O3 -
02/20/04 1625 HESSING , K.(Di) Staff
time spanned the range of normal market prices.
surrogate for Idaho Power I s marginal cost of power supply
was proposed in that case because Staff did not have an
operating power supply model that would allow it to
incrementally adjust the load and calculate the marginal
cost.In the Company s last general rate case, Case No.
IPC-94-, 16.22 $/MWh was calculated from an
incremental power supply model run.No recommendation
was made to change the 16.84 $/MWh EARG because the
difference was small.
What would be the result if the Commission
adopted the Company's proposal to use the average power
supply cost of 7.30 $/MWh for the Expense Adjustment Rate
for Growth?
The difference between the actual marginal
power supply costs of 29.41 $/MWh incurred to serve new
customers and the 7.30 $/MWh embedded cost proposed by
the Company would be collected from customers through the
PCA and flowed through to Idaho Power Company
shareholders.In other words the Company would collect
power supply costs from new customers through base rates
and collect 22.11 $/MWh (29.41 - 7.30) for new growth
through a PCA surcharge.While the Company has argued
that the revenue it receives from new customers does not
cover all the incremental costs of adding them, the EARG
CASE NO. IPC-O3-02/20/04 1626 HESSING, K.(Di)
Staff
proposed by the Company amounts to a windfall that more
than recovers power supply costs.As I have previously
stated , a general rate case, rather than the PCA , is the
appropriate place to recover load growth related power
supply costs.Therefore, Staff recommends that the
Commission adopt its Expense Adjustment Rate for Growth
of 29.41 $/MWh to eliminate the shareholder windfall and
maintain the integrity of the PCA.
CLOUD SEEDING
What is your understanding of the Company'
cloud seeding program?
Several years ago , members of the Commission
Staff, including myself, met with Idaho Power Company to
discuss cloud seeding.At that time the Company was
considering a pilot program to seed clouds in the upper
payet te River drainage.The Company I s goal was to
provide more precipitation in that area in the form of
snow that would melt during the summer and provide
additional water to the Company's hydro facilities,
allowing it to generate more electricity.
Part of the reason for the meeting had to do
with the effects on the PCA of such a proposal.To the
extent more water could be provided to generate more
electricity, the value of that electricity would be
captured by the PCA and substantially (90%) passed back
CASE NO. IPC-O3-
02/20/04 1627 HESSING , K.(Di) Staff
to ratepayers.This would leave customers with the
benefits and the Company's shareholders with the costs.
The Company did not believe this distribution of costs
and benefits to be fair.One alternative discussed was
to allow the Company to include the costs of cloud
seeding in the PCA so that customers would pay the costs
and receive the benefits.Of course, if the benefits did
not exceed the costs, the loss would be passed to
customers through PCA rates.
Another alternative for cost recovery discussed
at the meeting was that the Company simply begin the
program and incur and book the costs.The next general
rate case would then pick up a test year that included
the costs, at which time they could be discussed and the
Commission could choose to accept or reject them.
Rather than seeking recovery through the PCA,
the Company has included cloud seeding costs for the 2003
test year in this case.Those costs include $897 448 in
operation and maintenance expense (Account 536) and
$214,600 in capital costs (Account 101).
Does Staff have a position regarding the
recovery of these costs in the current case?
The Company did not provide enough information
in its filing for Staff to make a recommendation on the
merits of cloud seeding.For example , the Company did
CASE NO. IPC-O3-02/20/04 1628 HESSING , K.(Di) Staff
not state whether the program has created measurable
precipitation and, if so, how much.Without more
information it is not possible to evaluate whether the
cloud seeding costs were prudently incurred.If the
Company does not provide additional information in this
case, Staff recommends that all cloud seeding costs be
removed.
What information does Staff believe should be
provided by the Company to allow an adequate opportunity
to evaluate the requested cost recovery?
Given the experimental and somewhat
controversial nature of cloud seeding programs and the
sizable amount of money requested to be included in rates
on an annual basis, Staff believes the Company should
address the following issues:
1 )What activities constituted the cloud
seeding program in past years, including the test year
and what are the Company's cloud seeding plans for
upcoming years?
2 )What criteria will the Company use to
determine the level of cloud seeding activity and
expendi tures necessary in any given year?
3 )How does the Company evaluate whether cloud
seeding works and that the benefits exceed the costs?
4 )What would be the effect on the Company I
CASE NO. IPC-O3 -
02/20/04 1629 HESSING, K.(Di)
Staff
cloud seeding program if the Commission denied recovery
of the costs requested in this case?
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NO. IPC-O3-
02/20/04 1630 HESSING, K.(Di) Staff
open hearing.
(The following proceedings were had in
MR. STUTZMAN:And Mr. Hessing is
available for cross -examination.
questions.
COMMISSIONER SMITH:Thank you.
BY MR. EDDIE:
Do you have questions, Mr. Kline?
MR. KLINE:I do not have any questions.
COMMISSIONER SMITH:Mr. Eddie.
MR. EDDIE:I do have just a couple of
CROSS -EXAMINATION
Mr. Hessing, were you here on Monday when
I was rather clumsily asking Ms. Brilz about her Exhibit
CSB REPORTING
Wilder , Idaho
42 and the allocation of how other revenues are treated
I was here on Monday.That's not bringing
in that exhibit?
back a complete recollection to me.
The question was essentially how are
revenues from connection fees for pole rental spaces
treated on Exhibit 42.That was my question to Ms. Brilz
and my question to you is take, for example, revenues
from pole rental space on Idaho Power's distribution
1631 HESSING (X)Staff83676
network , in your view , should those revenues be credited
directly against the cost of those systems or should
those revenues be spread across the entire revenue
requirement?
Could you repeat that question one more
time, please?
Sure.Idaho Power receives revenues from
rental pole space, primarily from their distribution
network , assume that's the case , should those other
revenues which are not related at all to the sale of
kilowatt-hours , should those other revenues be credited
directly against the costs of that distribution system
for purposes of cost of service study or should those
other revenues be spread across the revenue
requirement?
I guess I've never really considered that
question.I guess I don't really have an opinion on
that.
MR . EDD IE:Okay, thank you.Nothing
further.
COMMISSIONER SMITH:Mr. Purdy.
CSB REPORTING
Wilder , Idaho
1632 HESSING (X)Staff83676
BY MR. PURDY:
CROSS -EXAMINATION
Yeah , you're the Staff I s technical expert
for how the Staff analyzed the Company's cost of service
CSB REPORTING
Wilder , Idaho
study methodology; isn t that true?
Yes , I reviewed the cost of service
If I had any questions about how Staff
proposes that the revenue requirement be allocated,
should I better direct those to Mr. Schunke?
Tha t 's true.
MR. PURDY:Then with that, I have no more
COMMISSIONER SMITH:Mr. Gollomp.
MR . GOLLOMP:No questions.
study.
COMMISSIONER SMITH:Mr. Ward.
CROSS - EXAMINATION
Mr. Hessing, in this case you performed
three al ternati ve cost of service studies; correct?
Yes.
And in fact , they re summarized in your
questions.
BY MR. WARD:
1633 HESSING (X)
Staff83676
exhibi ts, Exhibits 120, 121 and 122; is that also
correct?
Yes.
Now, as I understand it, Exhibit No. 120
basically replicates the Company s cost of service
approach; is that correct?
It I s the Company I s methodology and the
allocators and the Staff revenue requirement that we were
using at that point in time.
Okay, and then in 121 you've adopted a
weighted 12CP cost of service study; correct - - I'
sorry, a four-month weighted?
The weighted four months were non- zero
weighted and it was averaged with the unweighted 12CP
allocators.
You anticipated my question.You again
used the averaging to blend with the 4CP approach?
That's correct.
All right, and then finally, we have the
resul ts of the 12CP cost of service study in Exhibit 122
was there any averaging required there?
There was no weighting by marginal costs
and there was no averaging.
Okay.Now, just to summari ze, under --
even under the 12CP unweighted
- -
strike that.The 12CP
CSB REPORTING
Wilder, Idaho
1634 HESSING (X)Staff83676
methodology, the required change for the irrigation class
to bring them up to cost of service is still nearly 30
percent , is it not, 29.38 percent?
Tha ti s correct.
And that's the most favorable of the three
methodologies toward the irrigation class , is it not?
Yes.
And under all three cost of service
studies - - let me rephrase that.Don't all three cost of
service studies show Micron paying an amount
significantly in excess of their cost of service?
If you are balking at significantly,let
me give it some real numbers, from 7.55 percent in excess
of cost of service to 10.28 percent.
Yes.
MR.WARD:That's all I have.
COMMISSIONER SMITH:Mr. Richardson.
MR. RICHARDSON:No questions
Madam Chairman.
COMMISSIONER SMITH:Mr. Budge.
MR. BUDGE:Just a couple, if I may.
CSB REPORTING
Wilder , Idaho
1635 HESSING (X)
Staff83676
CROSS-EXAMINATION
BY MR. BUDGE:
I just wanted to clarify, if I could, Mr.
Hessing --
COMMISSIONER SMITH:Is your mike on?
MR. BUDGE:I I m sorry.
BY MR. BUDGE:Mr. Hessing, I just wanted
to clarify and make sure I understood your testimony.
it my understanding that the Staff has accepted the
Company's proposal to average the weighted 12CP with the
zero allocators and the 12CP?
Staff has accepted the Company's averaging
of the weighted and the unweighted allocation methodology
for the allocators.
So that includes at least as to the
weighted 12CP portion the zero allocators in seven
months?
Yeah , seven months are weighted at zero
and averaged with the unweighted allocators.
So is it your testimony or Staff'
position that to , that the weighted 12CP alone with the
zero allocators is not sufficiently accurate or reliable
to accept as a stand-alone method for cost allocation
between the classes?
CSB REPORTING
Wilder, Idaho
1636 HESSING (X)Staff83676
I guess I believe that without the
averaging and having the seven months weighted at zero
isn't the best way to do the allocation in this case.
If it were the best way, then it should be
used in and of itself?
If it were the best way to do the
allocation and captured all of the things that cost of
service is intended and has been intended to capture in
times past , then , yes, you would probably do it that way
wi thout the averaging.
And is that simply recognition that cost
methodologies are calculations that are not precisely
accurate in all circumstances for tracking costs and
causation?
I don't know if that's the reason for why
you would use - - average an unweighted and a weighted
12CP study, but I would agree that cost of service
studies use a few variables to try to track a lot of
rather complex cost causation.
MR. BUDGE:I have no further questions.
Thank you.
COMMISSIONER SMITH:Are there questions
from the Commissioners?Nor I.
Redirect?
MR. STUTZMAN I have no redirect.
CSB REPORTING
Wilder , Idaho
1637 HESSING (X)Staff83676
Mr. Hessing.
COMMISSIONER SMITH:Thank you
THE WITNESS:Thank you.
please.
(The witness left the stand.
MR. STUTZMAN:Staff calls Rick Sterling,
RICK STERLING,
produced as a witness at the instance of the Staff,
having been first duly sworn , was examined and testified
as follows:
DIRECT EXAMINATION
Please state your name for the record.
Rick Sterling.
How are you employed?
m employed as a Staff engineer for the
Public Utilities Commission.
CSB REPORTING
Wilder , Idaho
And in that capacity, did you prepare and
prefile direct testimony in this case dated February
Yes, I did.
Does that testimony consist of
BY MR. STUTZMAN:
20th , 2004?
1638 STERLING (Di)Staff83676
approximately 19 pages?
Yes.
Did you also prepare and prefile Exhibits
No. 124 , 125 and 126?
CSB REPORTING
Wilder, Idaho
Yes.
Do you have any changes or corrections to
your testimony or your exhibits?
No, I do not.
If I were to ask you the questions
contained in your prefiled testimony today, would your
responses be the same?
Yes.
MR. STUTZMAN Thank you, Mr. Sterling.
Madam Chairman , I move that the prefiled
direct testimony of Mr. Sterling be spread on the record
as if read and Exhibits 124, 125 and 126 be identified on
COMMISSIONER SMITH:If there is no
objection , it is so ordered.
(The following prefiled direct testimony
of Mr. Rick Sterling is spread upon the record.
the record.
1639 STERLING (Di)Staff83676
Please state your name and business address for
the record.
My name is Rick Sterling.My business address
is 472 West Washington Street, Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
Commission as a Staff engineer.
What is your educational and professional
background?
I received a Bachelor of Science degree in
Civil Engineering from the Uni versi ty of Idaho in 1981
and a Master of Science degree in Civil Engineering from
the University of Idaho in 1983.I worked for the Idaho
Department of Water Resources from 1983 to 1994.
1988, I became licensed in Idaho as a registered
professional Civil Engineer.I began working at the
Idaho Public Utilities Commission in 1994.My duties at
the Commission include analysis of utility applications
and customer petitions.
What is the purpose of your testimony in this
proceeding?
The first purpose of my testimony is to discuss
the methodology and results of Idaho Power's load
normalization, and to make a recommendation on whether
believe the Company's results should be accepted.Next,
CASE NO. IPC-E- 03 -1640 STERLING, R.(Di)
STAFF
I discuss the Company s power supply modeling and discuss
an alternative method that I used to evaluate Idaho
Power's results.Finally, I discuss the Danskin proj ect
and make a recommendation on whether I believe the
proj ect costs should be allowed in rate base.
Load No~alization
What is load normalization?
Load normalization is a process to determine
whether actual electricity sales were higher or lower
than normal as a result of actual weather.Energy use is
statistically estimated as a function of weather and
non-weather variables.
Why is load normalization important and how
does it affect the Company's revenue requirement?
Load normalization is important because it
establishes the loads that must be met by Idaho Power in
a normal year, which in turn are used for jurisdictional
separation , normalization of power supply costs, and cost
of service.Normalized loads are also used to determine
the revenue that the utility would be expected to receive
in a normal year.
Please describe the load normalization
performed by the Company in this case.
Idaho Power used multiple regression analysis
to normal i ze loads.Normalization was performed
CASE NO. IPC-E- 03 -1641 STERLING, R.(Di)
STAFF
separately using eleven different regression equations
two that describe Idaho Power I s total system residential
and commercial sales, two that describe Oregon'
residential and commercial sales, five that describe
irrigation sales for each of the Company's operating
centers, one that describes sales to the City of Weiser,
and one that describes sales to Raft River Rural Electric
Cooperative, Inc.To explain electricity use, the
regression equations utilize weather concepts such as
heating, cooling and growing degree-days and
precipitation, as well as economic and demographic
information such as electricity price, electric space
heat saturation , and air conditioning saturation.Once
regression equations were developed, normal variable
values were entered into the equations to compute
normalized loads.These normal loads were then used by
the Company in its power supply modeling, jurisdictional
allocation and cost of service studies.
Do you agree with the normalized loads proposed
by the Company?
Yes, I do.The regression equations developed
by the Company are very accurate predictors of usage by
various customer groups based on historic conditions and
consumption levels.The correlation coefficients
obtained by the Company that indicate the accuracy of
CASE NO. IPC-03-1642 STERLING, R.(Di)
STAFF
predictions in its analysis are very high.I believe
that the
CASE NO. IPC-03-1643 STERLING, R. (Di)
STAFF
methodology used by the Company is appropriate and that
the results are reasonable.
Power Supply Modeling
Have you reviewed the power supply modeling
performed by the Company as part this case?
Yes,have.
Do you agree wi th the normalized power supply
costs proposed by the Company?
Although I believe the power supply model the
Company used in this case could be improved , I conclude
that the normalized power supply costs proposed by Idaho
Power appear conservative and so Staff does not oppose
the Company's proposal.The Company computed a net power
supply cost of $49.6 million for the 2003 test year.
wi th known and measurable adj ustments, the Company is
proposing that a net power supply cost of $47.7 million
be adopted in this case.In the Company's last general
rate case (Case No. IPC-94-5) , a normalized net power
supply cost of $48 million was accepted.
Why is the Company's normalized net power
supply cost nearly the same as it was in Idaho Power'
last general rate case?
As discussed in Company witness Said'
testimony, several factors have caused upward pressure on
power supply expenses, while others have caused downward
CASE NO. IPC-E- 03 -1644 STERLING, R.(Di)
STAFF
pressure.The net effect of these factors has caused a
modest $1.9 million increase in normalized net power
supply costs before known and measurable changes. After
known and measurable changes, the difference is a $0.
million decrease from the last rate case.
As described in Mr. Said's direct testimony, factors
that have caused upward pressure on power supply costs
include higher market prices along with higher seasonal
and peak hour loads that must often be met using higher
cost resources.Factors that have caused downward
pressure on power supply costs include a slight net
decrease in annual system load, expiration of FERC
jurisdictional contracts, and overall decreases in coal
contract prices.
Did you explore or devise an alternative method
to evaluate the normalized power supply expenses proposed
by the Company.
Besides reviewing the Company s determination
of normalized power supply expenses using AURORA, I also
performed a regression analysis to estimate a range of
normal power supply expenses.In the analysis, I chose
the following eight independent variables that affect
power supply costs:
(a) Brownlee inflow
(b) Installed generation capacity
CASE NO. IPC-E- 03 -1645 STERLING, R.(Di)
STAFF
(c) Electric market price
(d) Unit cost of fuel at Bridger
(e) Unit cost of fuel at Boardman
(f) Unit cost of fuel at Valmy
(g) System firm load
(h) PURPA purchases
I used net power supply cost as the dependent
variable in the regression analysis.I used twenty- four
years of historical data in the analysis.
What did you hope to accomplish with your
regression technique?
My goal was simply to generally compare the
value proposed by Idaho Power to estimated net power
supply cost using other methods.
What did you conclude from your regression
analysis?
I concluded that the normalized net power
supply expenses proposed by Idaho Power are reasonable
and are probably low.
Do you recommend that the Commission accept the
normalized net power supply costs as proposed by Idaho
Power?
Yes , I do.However , I also recommend that the
Company and Staff monitor the actual net power supply
costs in the coming few years to assure actual net power
CASE NO. IPC-03-1646 STERLING, R.(Di)
STAFF
supply expenses properly track water conditions.
Danskin
Please summarize Commission Order No. 28773
(Case No. IPC-01-12) concerning the Danskin plant.
In Order No. 28773, the Commission authorized
Idaho Power to proceed with the construction of the
Danskin plant.In doing so, however, the Commission
We note that the procedure followed in this
case has limited the type and extent of
review that would otherwise occur in acertificate filing.
The information provided however is
insufficient to determine the reasonableness
of the related costs. As reflected in Staff
comments, it is unknown whether the Mountain
Home Station was the least cost al ternati ve.
Because the Mountain Home Station was not
selected pursuant a RFP process, we are unable
to conclude based on the information provided
that the commitment estimate is reasonable.
The Company in its Application , we note, also
provides no comparison of alternatives(alternatives available but not chosen) ~.
There is no record as to whether other
alternatives were also considered and rejected.
We are unconvinced that the best measure of the
cost of alternative resources is market price
estimates in effect at the time the decision toproceed was made. The record supporting such a
finding remains to be developed.
We find that there is insufficient record to
assess and determine the reasonableness of the
Company's commitment estimate and cannot
therefore provide the Company with a dollar
amount of rate base assurance. As we indicated
in our prior Milner decision, Order No. 23520,
when the Commission authorizes construction of
new generation, ...i t informs the Company, its
CASE NO. IPC-03-
stated:
1647 (Di)
STAFF
STERLING, R.
ratepayers and its investors that, in the
ordinary course of events, prudently incurred
costs of construction in bringing the
authorized plant on line will later be
recogni zed in the Company's revenuerequirement..." at page 20. We then went on to
discuss examples of what type of recovery isnot guaranteed. That being said , we
nevertheless note that implicit in our decision
in this case to approve a certificate for
construction of the Mountain Home Station is
recovery of some reasonable amount as rate baseaddition. The Company needs to provide the
Commission with more information. What otheralternatives were considered? What was the
Company's forecasted need? The Company
expressed concern that we will assess its
decision to build based on hindsight and from a
perspective of changed market conditions. We
assure the Company that the review standard
employed by the Commission will be what Company
knew or should have known at the time it made
its decision to build.
Did Idaho Power provide additional
justification for Danskin in its testimony in this case?
No.
Why is Staff providing testimony in support of
Danskin cost recovery when the Company did not?
Danskin I s plant cost recovery represents a
large portion of increased revenue requirement requested
in this case.Staff believes it is important to address
the issue and provide the Commission with the Staff
position.
Has the Commission Staff audited the
construction costs for the Danskin plant?
A. Yes. The total plant cost including thesubstation, step-up equipment , and structures and
CASE NO. IPC-03-1648 STERLING , R.(Di)
STAFF
improvements is $52 484 209 as of year-end 2003.
Do you believe all of the costs incurred for
construction of the Danskin plant are reasonable and
should be allowed in rate base?
Yes, I do.The plant I s capi tal costs were
proj ected to be $46 million upon completion in 2001.
With an additional 20% for contingencies, Idaho Power I
"Commitment Estimate" for the capital cost portion of the
plant was $55.2 million.The Staff -audi ted cost of $52.
million is clearly below the Company's commitment
estimate.
The Danskin plant was nearly as costly to build
as the Bennett Mountain plant is expected to be , yet the
Bennett Mountain plant will have a capacity of 162 MW
compared to Danskin' s 90 MW.Why was Danskin so
expensive compared to Bennett Mountain?
The commitment estimate for construction of the
Bennett Mountain plant is $54 million , while the cost of
Danskin was $52.5 million.Bennet t Mountain I s uni t cost,
therefore, is expected to be $336 per kW , while Danskin'
was about $583 per kW - more than 1.7 times the cost of
Bennet t Mountain.
One reasonable measuring stick for Danskin' s plant
cost is generating plant cost estimates prepared by the
Northwest Power and Conservation Council for use in
CASE NO. IPC-E- 03 -1649 STERLING, R.(Di)
STAFF
its Fifth Power Plan.The estimates were prepared on
April 5, 2002, therefore , they are likely very
representative of costs at the time Danskin was built.
Although the Fifth Power Plan has yet to be released , its
power plant cost assumptions have not changed.The
Council's capital cost estimate for gas-fired simple
cycle plants ranges from $540 to $660 per kW , with $600
per kW being the base case estimate.Danskin I s cost of
$583 per kW is very close to the Council's base case
estimate.
Bennett Mountain's expected cost of $336 per kw is
very low compared to simple cycle plant costs of just two
years ago.The demand for gas turbines surged in the
1998-2001 time frame, peaking in 2000.During this time
period, turbine manufacturers could not keep pace with
orders for new equipment and buyers bargained with each
other for higher slots on manufacturer's waiting lists.
Since that time , however, electric market prices have
moderated and demand for new gas turbines has plummeted.
At the time Idaho Power committed to Bennett Mountain
turbines could be obtained at a highly discounted price.
That is the primary reason Bennett Mountain is so much
cheaper than Danskin on a cost per kW basis.
What has been the actual cost of energy from
Danskin?
CASE NO. IPC-03-1650 STERLING , R.(Di)
STAFF
The Company's Application in the Danskin Case
(Case No. IPC-01-12) indicated that the preliminary
estimate of the levelized cost per MWh would range from
an upper level of $223 per MWh based on a capital cost
for the plant of $55.2 million , 500 hours of annual
generation , and levelized fuel costs of $5.05 per MMBtu
over the 30-year life of the plant , to a lower range cost
of $77 per MWh based on a plant cost of $46 million, 5140
hours of annual dispatch, and average fuel costs of $5.
per MMBtu.The actual cost of the plant ended up being
closer to the high estimate, but the actual hours of
operation has been close to the low estimate.Gas prices
have varied substantially throughout the past two years,
and the estimated gas price may still be reasonable over
the 30-year plant life.Consequently, Danskin' s actual
energy costs have so far been much closer to $223 per MWh
than to $77 per MWh.Future changes in gas prices and
operating hours will, of course, change the cost of
energy from the plant.
If the cost of energy from Danskin is so
expensi ve, why did Idaho Power build the plant?
First, it is important to recogni ze that the
Danskin plant is a peaking plant, not a base-load plant.
As a peaking plant , it is intended to be operated for
only brief periods during peak hours in the summer and
CASE NO. IPC-03-1651 STERLING, R.(Di)
STAFF
winter. Peaking plants will always have high energy costs
due to
CASE NO. IPC-03-1652 STERLING, R. (Di) lla
STAFF
their limited operating hours.
Second , it is important to remember the
circumstances at the time the decision was made to
construct the Danskin plant.Idaho Power made its
decision to pursue construction in early 2001 , at the
height of the electric market price run-up. Idaho Power'
marketing and trading analysts were predicting that heavy
load period market prices for the next few years would
likely be in the range of $50 to $350 per MWh , and that
hourly prices could exceed $1000 per MWh in the near
term. A severe drought also persisted throughout the
Northwest at that time, which was part of the reason for
such high market prices.This combination of
exceptionally low stream flows and extremely high market
prices forced utilities to scramble for alternatives to
meet load.
Beginning in mid-2000, Idaho Power found it
necessary to go to the electric market and make large
purchases at extremely high prices.Consequently, the
Company began deferring massive power supply costs unlike
any that had been made before.The upper graph of
Exhibit No. 124 shows the Company's PCA deferrals between
1999 and 2003.In single months from late 2000 to mid
2001 , total deferrals frequently exceeded $20 million and
sometimes approached $50 million.In early 2001, no one
CASE NO. IPC-E- 03 -1653 STERLING, R.(Di)
STAFF
knew how much longer extremely high market prices would
persist.
CASE NO. IPC-E- 03 -1654 STERLING , R. (Di) 12a
STAFF
We did know, however , that drought conditions could not
end until at least the following winter.
In response to the dire circumstances, in January
2001 , Idaho Power began identifying alternatives to
market purchases. In addition to building a simple-cycle
peaking plant, the Company planned buy-backs from
irrigators, ASTARIS and Simplot.The Company al
planned to lease mobile diesel generators and to purchase
hedges to guard against price volatility.Later, on May
, 2001, anticipatjng continued high prices and poor
stream flows , the Commission issued Order No.2 8 722
Case Nos. IPC-01-7 and IPC-Ol-, directing Idaho
Power to prepare and file a report which would identify
and outline plans for meeting loads during the summer and
winter of 2001.
The Danskin proj ect, with its short construction
lead time , was intended to be on-line in time to provide
a resource that could mitigate exposure to extremely high
near-term market prices.
Did Idaho Power issue a request for proposals
or solicit bids for the Danskin proj ect?
No, Idaho Power did not issue a request for
proposals, nor did it formally bid the equipment contract
or the construction contract.While conceding in Case
No. IPC-01-12 that an ideal way to determine the cost
CASE NO. IPC-03-1655 STERLING , R.(Di)
STAFF
of available alternative resources would be to initiate a
request for proposals, the Company contended that
pursuing the RFP route would likely have delayed the
resource acquisition until 2002 , thereby exposing the
Company to increased levels of market purchases through
fall and into the winter season.
Before the extreme price run-up began, however,
Idaho Power did issue a Request for Proposals as a result
of its 2000 IRP.The Company received proposals for
gas-fired combustion turbines and coal-fired generation.
In addition , the Company evaluated self-build
alternatives using gas-fired combustion turbines.The
Garnet proposal was eventually selected , although the
project was later abandoned.The proposals received
during this process gave Idaho Power at least some
indication of the costs of new gas-fired generation.
However, because the RFP was seeking 250 MW of capacity
during a limited number of days in only five months, I do
not believe the bids provided a fair approximation of the
cost that could be expected for a 90 MW simple cycle
plant.Although the RFP was broad enough that smaller
proj ects could be proposed, only a handful of proposals
were received in response to the RFP , and of the
proposals received, only two were for less than the
requested amount of capacity and energy.
CASE NO. IPC-E- 03 -1656 STERLING, R.(Di)
STAFF
In the Company s 2000 IRP, a number of other
technologies for generation were evaluated, including
CASE NO. IPC-E- 03 -1657 STERLING, R. (Di) 14a
STAFF
coal , combined cycle gas, wind and other renewables.The
evaluations were non-si te-specific , however, and most
were not realistic alternatives to building a simple
cycle plant due to the urgency with which new generation
was needed.
How did the Danskin plant compare to the other
alternatives available to Idaho Power at the time?
Obviously, one of the al ternati ves to
constructing Danskin would have been to continue to make
energy purchases from the market.However , given the
exceptionally high prices , poOr stream flow conditions,
and the extremely high PCA deferrals, it was believed
that continued reliance on the market would only
exacerbate the problem.
Another option was to initiate buybacks with some of
its largest customer groups.Idaho Power agreed to
purchase 50 MW from ASTARIS for a two-year period at a
cost of $159 per MWh.Thirty megawatts were also
purchased from Simplot at $75 per MWh in the first year
$90 per MWh in the second year and 85% of market price in
the third year.An additional block of 8 MW was
purchased from Simplot at two-thirds of market price.
buy-back program for large commercial and industrial
customers was also initiated, but no customers
participated.
CASE NO. IPC-E- 03 -1658 STERLING, R.(Di)
STAFF
A buy-back program for irrigators was also
implemented.The Company purchased 262 MW of load
reduction at a cost of $150 per MWh.
Two large QF contracts, one with Simplot and one
wi th Amalgamated Sugar, were also re-negotiated during
this time frame.
Finally, the Company leased mobile diesel
generators.The generators were capable of providing 39
MW at an estimated cost of $124 per MWh.Exhibit No. 125
provides a summary of the short - term programs and
contracts pursued during this time period in response to
the price run-up.
Over the course of time during which they were in
effect, most of the programs proved quite expensive.The
ASTARIS buy-back cost a total of nearly $128 million. The
irrigation buy-back cost $86 million.The mobile diesel
generators , despite never being used to satisfy load,
cost almost $5.5 million.The lower graph on Exhibit No.
124 shows PCA deferrals by month as a result of each of
these three measures.Compared to the total cost of
these alternatives, Danskin s $52.5 million capital cost
doesn't seem so large.In analyzing the Danskin proj ect
Idaho Power estimated the present value of the revenue
requirement over the 30-year expected plant life to be
approximately $180 million.
CASE NO. IPC-03-1659 STERLING , R.(Di)
STAFF
Didn't Idaho Power receive an unsolicited
competing proposal for the Danskin plant?
Yes.Power Development Associates, LLC of
Boise submitted a proposal to Idaho Power to install two
45 MW simple cycle gas turbines near Mountain Home at a
si te different than the Danskin site.The proposed
turbines, I believed , were more efficient in a simple
cycle mode than the turbines Idaho Power planned to
install , but were less efficient in a combined cycle
mode.Idaho Power eventually rej ected the proposal
primarily because of uncertainty about whether the
proj ect could come on -ine soon enough to meet the
Company s immediate need to be relieved of purchasing
from the market.
As it turned out, Power Development Associates , LLC
was the predecessor to Mountain View Power , Inc., the
successful bidder to construct the Bennett Mountain
plant. The site of the Bennett Mountain plant is the same
as the site proposed as an al ternati ve to Danskin.
Bennett Mountain's plant capacity and equipment package
is different than what was proposed initially, however.
If Power Development Associates proposal had been
selected as an alternative to Danskin , the Bennett
Mountain plant would not have recently been available as
an option.
CASE NO. IPC-E- 03 -1660 STERLING, R.(Di)
STAFF
Do you believe Idaho Power adequately
considered other alternatives to construction of the
Danskin plant?
Yes , I do , given the circumstances that existed
CASE NO. IPC-E- 03 -1661 STERLING, R.(Di) 17a
STAFF
at the time the decision to build Danskin was made.
What has been the history of operation of the
Danskin plant so far?
Since the plant went on-line at the end of
September 2001, the plant has operated on average about
500 hours per year.The plant has been operated most in
the summer months, although it has operated at least some
in every month of the year.Exhibi t No. 126 shows the
generation of the plant by month since it went on-line in
September 2001.
Will construction of the Bennett Mountain plant
make the Danskin plant no longer useful?
, I don't believe so.Operation of the
Danskin plant could change after Bennett Mountain becomes
available , but I believe Danskin will continue to be used
to meet peak loads primarily in the summer and winter.
Bennett Mountain will be a more efficient plant than
Danskin , thus it will have a lower dispatch cost.
However, Bennett Mountain will not always be able to meet
the Company I s peak load requirements by itself, making
Danskin necessary.In addition , I think there could be
times when Danskin would be dispatched before Bennett
Mountain because Danskin' s two 45 MW turbines can be
dispatched independently, whereas Bennett Mountain will
have a single 162 MW unit.Small peak load needs might
CASE NO. IPC-E- 03 -1662 STERLING , R.(Di)
STAFF
be more economically met using Danskin despite its higher
dispatch cost.
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NO. IPC-03-1663 STERLING , R.(Di)
STAFF
(The following proceedings were had in
open hearing.
MR. STUTZMAN:Mr. Sterling is available
for cross -examination.
COMMISSIONER SMITH:Thank you.
Mr. Eddie.
MR. EDDIE:No questions.Thank you.
COMMISSIONER SMITH:Mr. Purdy.
MR. PURDY:None for me.Thank you.
COMMISSIONER SMITH:Mr. Gollomp.
MR. GOLLOMP:No questions.
COMMISSIONER SMITH:Mr. Ward.
MR. WARD:No questions.
COMMISSIONER SMITH:Mr. Richardson.
MR. RICHARDSON:Thank you,
Madam Chairman , just a couple of questions.
CROSS-EXAMINATION
BY MR. RI CHARDSON:
Mr. Sterling, would you refer to page 7 of
your direct testimony, and there on page 7 you quote the
Commission's Order approving the Danskin plant and the
first part of that quote the Commission is declaring that
we note that the procedure followed in this case has
CSB REPORTING
Wilder, Idaho
1664 STERLING (X)Staff83676
limited the type and extent of review that would
otherwise occur in a certificate filing.Do you see
that?
Yes , I do.
Would you agree that the Commission'
statement there was accurate?
CSB REPORTING
Wilder , Idaho
Yes.
And then the Commission went on to state
that the information provided, however , is insufficient
to determine the reasonableness of the related costs.
Yes.
Would you agree that the Commission was
accurate when it made that finding?
Yes.
And then the Commission went on to state
that we are unconvinced that the best measure of the cost
of alternative resources is market price estimates in
effect at the time the decision to proceed was made.
Would you agree that the Commission was accurate when it
made that statement?
Yes.
And finally, the Commission stated in that
Order , on page 13 of the Order , that the Company needs to
provide - - actually, the Commission required, they didn'
you see that?
1665 STERLING (X)
Staff83676
just state - - the Company needs to provide the Commission
with more information.What other al ternati ves were
considered?What was the Company's forecasted need?
your opinion , has the Company satisfied that mandate by
the Commission?
Well , more information certainly would
have been helpful.
Can you be more specific?
Specific as to what additional information
or --
More specific in terms of responding to
the question which was, is it your opinion that the
Company has satisfied that mandate by the Commission?
Well , it's the Commission I s Order and I
can I t speak for what the Commission's expectation was in
the Order.I can say that I personally would have liked
to have had more information.
MR. RICHARDSON:Thank you , Mr. Sterling.
Madam Chairman , that's all I have.
COMMISSIONER SMITH:Thank you,
Mr. Richardson.
Mr. Kline, do you have questions?
MR. KLINE:I do not.
COMMISSIONER SMITH:Mr. Budge.
MR. BUDGE:I have none.
CSB REPORTING
Wilder, Idaho
1666 STERLING (X)
Staff83676
COMMISSIONER SMITH:Do the Commissioners?
It looks like we're done with Mr. Sterling.
redirect.
MR. STUTZMAN:are.I have no
COMMISSIONER SMITH:Thank you.
(The witness left the stand.
MR. STUTZMAN:I next call Dave Schunke to
the stand , please.
DAVID SCHUNKE
produced as a witness at the instance of the Staff
having been first duly sworn, was examined and testified
as follows:
DIRECT EXAMINATION
Good morning.
Good morning.
Please state your name for the record.
My name is David Schunke.
And how are you employed?
m the engineering manager for the Idaho
Public Utilities Commission Staff.
CSB REPORTING
Wilder , Idaho
In that capacity, did you prepare and
BY MR. STUTZMAN:
1667 SCHUNKE (Di)
Staff83676
prefile direct testimony in this case dated February
20th , 2004?
Yes , I did.
Does that consist of approximately 36
Yes, it does.
Did you also prefile Exhibits Nos. 127
Yes.
Do you have any changes or corrections to
Yes , just a couple.On page 4 , line 23,
pages?
through 138?
$2.51 should be $2.50.On page 34 , line 19, the without
CSB REPORTING
Wilder, Idaho
should be with , and on line 20 of page 34 , with should be
MR. BUDGE:What was the page number on
THE WITNESS:m sorry, page 34.
your testimony?
MR. BUDGE:34, thank you.
THE WITNESS:And it's lines 19 and 20 and
without.
the withs and withouts should just be swapped.
MS. MOEN:Could you please just repeat
that , Dave?
your second correction?I believe it was page
THE WITNESS:The first correction was on
page 4 --
1668 SCHUNKE (Di)
Staff83676
should be $2.50.
MS. MOEN:All right.
THE WITNESS:-- line 23, $2., that
corrections.
MS. MOEN:Thank you.
THE WITNESS:And those were the only
BY MR. STUTZMAN:Okay, wi th those
changes, if I asked you the same questions today as
contained in your testimony, would your answers be the
same?
Yes , they would.
MR. STUTZMAN Thank you, Mr. Schunke.
Madam Chairman , I'd ask that the prefiled
testimony of Dave Schunke be spread on the record as if
CSB REPORTING
Wilder, Idaho
read and Exhibit Nos. 127 through 138 be identified on
COMMISSIONER SMITH:It is so ordered
the record.
seeing no obj ection.
(The following prefiled direct testimony
of Mr. David Schunke is spread upon the record.
1669 SCHUNKE (Di)Staff83676
Please state your name and business address for
the record.
My name is David Schunke and my business
address is 472 West Washington Street, Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
Commission as a Public Utilities Engineer.
What is your educational and experience
background?
I received my Bachelor of Science Degree in
Civil Engineering at Montana State University in 1972.
have been licensed as a Registered Professional Engineer
in Idaho since 1977.I have worked in various
capacities , including a Cost and Materials Engineer with
Morrison Knudsen Co., Inc. and a consulting engineer with
Stevens, Thompson & Runyan (STRAAM Engineers) As a
consul tant , I worked as proj ect Engineer on numerous
civil engineering proj ects in Idaho and Oregon for more
than six years.
Since joining the Commission Staff as a
Utilities Engineer in 1979 , I have been continuously
invol ved in rate design and regulatory matters with
virtually all the water , gas and electric utilities
regulated by the Commission.I served as the Engineering
Section Supervisor from 1983 to 1991, Utilities Division
CASE NO. IPC-03-02/20/0 1670 SCHUNKE, D.(Di) Staff
Deputy Administrator from 1991 through 2000 and Engineer
Manager from 2001 to present.
INTRODUCTION AND SUMMARY
What is the purpose of your testimony?
The purpose of my testimony is to describe
Staff's rate design proposal for tariff and special
contract customers.
How is your testimony organized?
A summary of my recommendations is followed by:
( a)A general discussion of my rate design
objectives and long-term goals,
(b)An explanation of how Staff proposes to
cap the increase to irrigators and redistribute the
revenue requirement to the other customer classes , and
(c)Based on the resulting revenue requirement
for the various customer classes , I then provide specific
rate design proposals for each customer class.
Please summarize your testimony.
In general I am recommending small increases in
customer charges and believe the Company's proposed
increases in the various customer charges are too large.
I am also recommending increased energy rates in the
summer months for Schedules 1 , 7, 9 and 19.I believe it
is important for rates to reflect the differences in cost
depending on time-of-use and I am recommending
CASE NO. IPC-03-02/20/0 1671 SCHUNKE , D.(Di)
Staff
time-of -use (TOU) rates wherever they are practical.
Staff recommends
CASE NO. IPC-E- 03 -02/20/0 1672 SCHUNKE, D. (Di)
Staff
that rates for all customer classes move closer to cost
of service.However , the irrigation class should be
moved only one-third of the way to full cost of service
because of the magnitude of the increase that otherwise
would be required.Staff is also proposing that any rate
reduction dictated by cost of service analysis be limited
to one-third the amount indicated in the cost of service
study.The rate design proposal presented in my
testimony is based on Staff's initial determination of an
overall revenue requirement increase of 3.14%.The Staff
recommended revenue requirement is actually less than
that, as discussed in Staff witness Keith Hessing'
testimony.The Staff recommended increase for each
customer class is shown in Staff Exhibit No. 127:
(a)Residential Schedule 1 would receive an
overall average increase of 2.51%.I am recommending
that the monthly customer charge be increased from $2.
to $3.00 and that there be an increased energy rate for
the summer months for energy use above 800 kWh per month.
(b)General Service Schedule 7 would receive
an overall average revenue increase of 4.17%.I am
recommending that the monthly customer charge be
increased to $3.50.
(c)Large General Service Schedule 9 Secondary
Service would receive an overall average revenue decrease
CASE NO. IPC-E- 03 -02/20/0 1673 SCHUNKE , D.(Di) Staff
of 0.13% while Primary and Transmission Service would
receive an overall average revenue increase of 13.31%.
For Secondary Service, I am recommending no change in the
Customer Charge or in the Basic Charge.The demand and
energy rates would be increased about 10% in the summer
and decreased about 4% in the non-summer months to
reflect the higher cost to serve in the summer.
(d)For Schedule 9 Primary Service , I am
recommending that the Customer Charge increase from
$85.58 to $100.00 and that the Basic Charge be increased
by 13 % from $ 0 . 77 to $ 0 . 87 .The demand and energy rates
would be increased about 25% in the summer and increased
about 9% in the non-summer months to reflect the higher
cost to serve in the summer.
(e)Large Power Schedule 19 would have no
change in the overall average revenue.Time-of-use and
seasonal rates would be implemented in a manner
consistent with the Company's proposal.
(f)Schedule 24 customers would receive an
overall average revenue increase of 15%.The in-season
customer charge would increase from $10.07 to $12.00.
The out-of-season customer charge ("bills out-of-season"
along with the minimum charge would increase from $2.
to $3.00.The in-season demand charge would increase
from $3.58 to $4.00 and I am proposing an out-of-season
CASE NO. IPC-03-02/20/0 1674 SCHUNKE, D.(Di)
Staff
demand charge of $0.80.Currently the energy charge is
higher in the out-of-season than in the in-season , and I
am proposing a single energy rate for both in-season and
out-of-season.
(g)
Schedules 15, 40 , and 41 would receive
overall average revenue decreases of 36., 10.48% and
91%, respectively.Schedule 42 would have no change in
the overall average revenue.
(h)Micron , Schedule 26, and Simplot Schedule
29, would receive overall average revenue decreases of
01% and 3.43%, respectively.DOE Schedule 30 would
receive an overall average increase in revenue of 1.05%.
RATE DESIGN OBJECTIVES
What are Staff's rate design objectives?
The electricity industry and this Commission
have had a long history of pricing power differently to
customers with different load and usage characteristics.
Residential customer rates differ from those of
commercial and industrial customer rates because the cost
of providing service differs depending on the
characteristics of the end use.Large loads wi
high-load factors (constant use) tend to be less costly
per kWh to serve than smaller loads with large
fluctuations.Time-of -use is also a maj or factor in
determining the cost of service. These differences are
CASE NO. IPC-03-
02/20/0
1675 SCHUNKE , D.(Di) Staff
generally addressed by grouping customers with similar
end-use characteristics together.They form a rate class
such as residential , commercial , irrigation, industrial
or lighting.The cost of providing service to the
various customer classes has been addressed in the cost
of service (COS) studies discussed in Staff witness
Hessing s testimony.The first obj ecti ve in rate design
is to set rates that are more closely aligned to the cost
of providing service.
The cost of providing power varies greatly from
month to month and there is considerable variation in the
cost depending on the time of day that the usage occurs.
The time-of -use (TOU) is a maj or factor in the cost of
providing service and is becoming increasingly important
as Idaho Power's peak load continues to increase relative
to its average load.However , currently most customer
class rates are not dependent on TOU.Therefore, another
rate design obj ecti ve is to consider the time-of -use
implications in rate design.I believe it is becoming
increasingly important to discourage energy use during
peak periods by providing proper rate signals or through
direct load control programs, both of which will help to
mitigate the increasingly high costs that Idaho Power
incurs to provide peak load capacity.
It is also an obj ecti ve to keep rates
CASE NO. IPC-E- 03 -
02/20/0
1676 SCHUNKE, D.(Di) Staff
reasonable by balancing the cost of service goals with
the goals for simplicity, for minimizing rate shock, and
for promoting conservation - especially during high cost
periods.
Finally, in my specific rate design proposal
for individual customer classes , I attempted to
distribute the increase in revenue requirement to the
customer classes by increasing the rate components
somewhat uniformly.
CUSTOMER CLASS REVENUE ALLOCATION
What cost of service study is Staff I s rate
design proposal based on?
Staff witness Hessing has completed a number of
cost of service (COS) analyses which he discusses in his
testimony.In particular, Staff considered the Company
proposed cost of service analysis which uses a monthly
weighting to calculate the demand and energy allocators.
The five months with the most critical conditions , with
respect to power supply cost, hydro conditions, and
loads , were chosen.This is the methodology that Staff
believes is most appropriate and is the one Staff has
based its rate design analysis on.
Do you propose to move the irrigation class to
full COS as determined by the class cost of service
study?
CASE NO. IPC-E- 03 -
02/20/0 1677 SCHUNKE , D.(Di)
Staff
No.While I believe that their rates should be
increased sufficiently to move the irrigation class in a
significant way toward COS, I also believe that some cap
is necessary in order to keep the increase reasonable.
CASE NO. IPC-E- 03 -02/20/0 1678 SCHUNKE , D.(Di)
Staff
The lower the cap, the greater the subsidy required from
other rate classes.A competing goal is to minimize the
subsidy.With these goals in mind, I propose to cap the
total increase to the irrigation class at approximately
one-third the increase dictated by COS , or 15%.I also
propose to cap any class revenue requirement decreases at
one-third the full COS amount.All other customer
classes would move to full cost of service with two
adj ustments that are discussed later.If the overall
increase awarded the Company is substantially greater
than the 3.14% recommended by Staff, I believe this cap
should be reevaluated.
If the irrigation class rate increase is capped
at 15%, how do you propose to spread the revenue
shortfall?
The revenue shortfall is redistributed to the
other classes in proportion to their revenue requirements
at full cost of service.
What effect does this redistribution have on
the customer classes?
The primary effect is that the revenue
responsibility of the irrigation class is reduced by over
$19 million and this amount is reallocated to the other
customer classes.Staff's proposal for the
redistribution of this amount plus the Cost of Service
CASE NO. IPC-03-02/20/0 1679 SCHUNKE , D.(Di) Staff
Adjustment is shown in Staff Exhibit No. 127 , Column
"Revised Revenue Requirement.
The secondary effect is a credit of about $2.
million that occurs as a result of the cap on any
decreases.This amount is redistributed as a credit to
the remaining customer classes requiring an increase
(except irrigation).The Final Revenue Adjustment is
shown in Column It includes the Cost of Service
Adj ustment, the adj ustment for the reallocation of the
irrigation costs and the adjustment for the reallocation
of the credit resulting from limited decreases.This
Final Adjustment is added to the Current Base Revenue to
arrive at the Staff-Proposed Base Revenue shown in Column
8 of Staff Exhibit No. 127.This is the amount that
Staff used in its rate design proposals.
If Staff had chosen a different cost of service
study to base its rate design proposal on, how would this
have affected Staff's recommended average change in rates
to the various customer classes?
If the increase to the irrigation class is
capped at. 15% (about one-third) and decreases are capped
at one-third, then the choice of COS studies makes little
difference.Even if the most extreme cost of service
study were chosen where all the months are weighted
equally (the un-weighted study), the difference in the
CASE NO. IPC-03-02/20/0 1680 SCHUNKE , D.(Di)
Staff
final revenue requirement proposal for the customer
classes after the adjustments are made changes less than
1% for most customer classes.The increase for the
irrigation class would still be greater than 15% to
achieve full cost of service.
SEASONAL AND TIME-OF-USE
The Company has proposed time differentiated
rates, both seasonal and TOU, for several customer
classes.Are seasonal and TOU rates consistent with your
rate design objectives?
Yes.Deaveraging rates so they can be priced
higher in peak periods and lower in off -peak periods
provides two important price signals.The higher price
during the periods when costs are higher encourages
customers to reduce consumption and allows rates to be
lower when the cost of power is lower, thus encouraging
use during these off -peak periods.By shifting load
peaking facilities and peak power purchases can be
reduced and existing base load facilities can be better
utilized.
Both the Company's proposal and the Staff'
proposal would accomplish this through the recommendation
for seasonal and TOU rates.
How is the winter peak addressed in your
proposal?
CASE NO. IPC-03-
02/20/0 SCHUNKE, D.(Di) 10Staff
1681
would
Neither the Staff nor the Company proposal
CASE NO. IPC-E- 03 -02/20/0 1682 SCHUNKE , D. (Di) 10aStaff
provide a direct price signal in the winter months.
However , the summer peak is the critical peak.As Ms.
Brilz stated in her testimony (page 26, line 12) :
The Company faces its highest power supply
costs during the months of June, July, andAugust.
...
it is the peak usage during these three
months , along with the usually low hydro
condi t ions during the months of November and
December , which are driving the need for the
Company to seek new peaking resources...
Seasonal rates...are intended to signal customers
that consumption during the summer months is
more costly.
I agree with Ms. Brilz that the three summer
months are the most critical, but the low hydro
condi tions during the November-December winter peak also
contribute to the Company s need to seek new peaking
resources.If the Commission determines that the
seasonal rates should be extended to winter peak months,
it would not be difficult to make that change to either
the Company proposal or to my proposal.I believe that
either seasonal rate proposal provides a reasonable step
in the right direction.
What are the advantages and disadvantages of
seasonal rates compared to TOU rates?
Seasonal rates are easier to implement and do
not require the special equipment that TOU rates do.The
primary disadvantage of seasonal rates is that they do
CASE NO. IPC-03-
02/20/0 1683 SCHUNKE, D.(Di) 11Staff
not differentiate between heavy-load hours and light-load
hours.They can only differentiate between high-load
seasons and low-load seasons.All the energy used wi thin
the season is priced at the average for that season.
Therefore, customers would be charged the same seasonal
rate for power that they use both night and day, even
though the cost of power at night is lower.TOU rates
provide a greater degree of deaveraging and the
opportunity to shift loads between hours within the day.
This gives customers another tool to control their energy
bill.By simply shifting energy use to a different time
customers can lower their bill.As off-peak usage
increases, the utility facilities are better utilized and
the need to add peaking resources is avoided or delayed.
For these reasons, I believe TOU and seasonal rates
should be encouraged wherever practical.
Are there other ways to provide the proper rate
signal?
Yes.There are a number of rate designs that
can provide proper price signals.Each has its
advantages and disadvantages.Tiered rates, for example,
are an imperfect but effective way to provide a proper
price signal to customers.A tiered rate structure
charges a higher rate for energy as consumption
increases.Generally higher cost generation is
CASE NO. IPC-E- 03 -
02/20/0 1684 SCHUNKE, D.(Di) 12Staff
coincident with higher use, so when a customer's usage is
high for space heating or air conditioning it is during
the winter and summer when energy costs and the total
Company load are high.Therefore, tiered rates provide
an effective way of providing proper price signals
without having to define peak seasons.However tiered
rates, like seasonal rates, do not differentiate between
high- and low-load hours.
Does the Company currently have TOU rates or
other load shaping programs that target the peak hours in
the summer months?
Yes, currently there are a number of pilot
programs and tariffs that the Commission has recently
ordered that are specifically designed for this purpose.
Commission Order No. 29362 authorized the installation of
automatic meter reading equipment in the Emmett and
McCall service areas.Along with the testing of the
automatic meter reading capability, this effort will test
TOU rates to determine their effectiveness in reducing
both summer and winter peaks.The Company al so has an
air conditioning load control program authorized in
Commission Order No. 29207.This program is designed to
reduce loads in the peak hours of the summer months.
Schedule 25 is a TOU Irrigation tariff designed to
provide peak hour pricing in the summer months with the
CASE NO. IPC-03-
02/20/0 SCHUNKE , D.(Di) 13Staff
1685
hope of reducing the peak load during that period.The
Commission presently
CASE NO. IPC-E- 03 -02/20/0 1686 SCHUNKE , D. (Di) 13aStaff
has an Idaho Power application before it in Case No.
IPC-04-3 to implement a "Peak Clipping" program
designed to reduce irrigation loads during the peak
summer hours.In this rate case, the Company is
proposing TOU rates for Schedule 19 customers where TOU
metering is already in place.All these programs are
designed to go beyond what seasonal rates can do by
reducing the peak-hour load and ultimately avoid
supply-side resources.
Staff believes that these programs should be
aggressively pursued; they are the type of programs that
the Commission was referring to in its Bennett Mountain
Order No. 29410:
Although we grant the certificate, we concur
wi th the thrust of the Advocates and Staff
comments regarding Idaho Power's obligation to
aggressively consider alternatives tosupply-side resources. We have not retreated
from our belief that DSM and peak-load
management programs offer viable al ternati ves
to the incremental construction of peaking
generation units. According to the Staff , the
Company's most recent load-resource balance
analysis demonstrate a significant need forcapacity and associated energy (or load
shedding/shifting alternatives) during peak
hours in the summer and winter. Programs or
procedures that reduce critical peak hourly
demand have great value to both ratepayers and
the Company. Idaho Power must vigorously
pursue all available cost-effective DSM or
other conservation programs.
RATE DESIGN - RESIDENTIAL
Q. What change in revenue requirement is Staff
recommending for Residential Schedule
CASE NO. IPC-03-02/20/0 1687 SCHUNKE , D.(Di)
Staff
Staff recommends an average overall increase in
revenue of 2.51% to Residential Schedule
What is your recommendation for the Residential
Schedule 1 rate design?
I am recommending that ( 1) the cus tomer charge
be increased to $3.00;(2) the energy rate for the base
period remain the same as the current energy rate,
$0. 049303/kWh; and (3) the rate for energy use in excess
of 800 kWh/month in the peak summer months (June, July
and August) be priced at $0.059022/kWh.
Staff Exhibit No. 128 shows the existing and
proposed rates along with the resulting revenue for
Residential Schedule
The Company has proposed an increase in the
residential customer charge from $2.51 to $10.00.Do you
agree with this proposal?
No.The Company's proposal increases the
customer charge about 300%.This would have a
disproportionate affect on customers with low usage.
would increase 10% of the residential customers' bills
more than 50%.The Company I s proposal for such a large
customer charge would also be inconsistent with energy
conservation goals.
Historically the Idaho Commission has been
careful to provide the proper price signal in customers'
CASE NO. IPC-E- 03 -02/20/0 1688 SCHUNKE , D.(Di) Staff
rates.This was especially true during and shortly
following the energy crisis of 2000 and 2001.Large
amounts of consumption were billed at a higher rate,
reflecting the increased cost to meet higher system
peaks. The Company s customer charge proposal in this
case would send exactly the opposite message.The
Company's Exhibit No. 44 , page 1 , shows that the customer
with the lowest usage would see a 298% increase while the
largest users would see only an 8% increase.
What is the history of Idaho Power's customer
charge?
In 1987 , the Company proposed to replace the
minimum charge with a $5.00 customer charge in the
I006-265 case.The Commission denied the Company'
proposal , stating in Order No. 21365 that:
...
promoting additional energy usage through a
general policy change is not in the long-term
best interest of the Company or its customers.
Furthermore, the proposed customer charge is
too high because it is based upon cost of
service studies that allocate fixed plant costs
into customer-related costs. (Emphasis added)
In Idaho Power's last general rate case in
1995 , the Commission accepted the Company's proposal for
a $2.50 customer charge.Order No. 25880.
Do you believe some increase in the customer
charge is justified?
CASE NO. IPC-E- 03 -02/20/0 1689 SCHUNKE , D.(Di) 16Staff
Yes.I am recommending that the residential
customer charge be increased to $3.00.
What did you base the $3.00 amount on?
The customer charge should be based on the
direct cost of meter reading and billing and should not
include any fixed plant cost.I believe this is
consistent with the finding in Commission Order No. 21365
that it was not appropriate to base the customer charge
on fixed plant cost.The monthly cost associated with
meter reading and billing is $4.20 for this customer
class.Given the relatively small overall increase in
rates that Staff is recommending, I believe $3.00 is the
appropriate amount for the customer charge.This would
cover the maj ori ty of the cost of meter reading and
billing.If additional revenue is required from the
residential class, I believe a customer charge that moves
closer to full cost of meter reading and billing would be
reasonable.
If a $4.20 customer charge can be justified
from cost of service, why are you recommending only
$3. OO?
A one dollar increase in the residential
customer charge produces $4 million in additional
revenue. I f the customer charge were increased to $4. 00,
the full increase in revenue requirement recommended by
CASE NO. IPC-E- 03 -02/20/0 SCHUNKE , D.(Di) 17Staff
1690
Staff for Schedule 1 would be recovered and the energy
rate for the peak summer period could not be increased
without an
CASE NO. IPC-03-02/20/0 1691 SCHUNKE , D. (Di) 17aStaff
offsetting decrease in the non-summer energy rate.
Although this is an option , it is not Staff'
recommendation.
Please describe Staff's recommended Residential
Schedule 1 energy rate?
The energy rate would consist of two
components. The base usage rate would apply to all energy
used in the non-summer period and the first 800 kWh per
month used in the summer period.The peak period rate
would apply only in the summer months for energy used
above 800 kWh of base monthly usage.The peak period
energy rate would be about 20% higher than the base use
rate to reflect the higher power supply cost in that
period.This is similar to the summer/non-summer
differential that the Company is proposing except it
would apply only to energy used above base monthly usage
during the peak summer period , rather than all energy
used in the summer.
Why should the peak period rate only apply to
energy used in excess of 800 kWh per month in the summer
months?
The rate for the first 800 kWh/month in the
summer is based on the cost of generation from
non-peaking resources.Al though the cost to produce
energy varies greatly from month to month throughout the
CASE NO. IPC-E- 03 -02/20/0 1692 SCHUNKE, D.(Di) 18Staff
year and from hour to hour throughout the day, energy
rates currently
CASE NO. IPC-E- 03 -
02/20/0 1693 SCHUNKE, D. (Di) 18aStaff
are based on the average cost of providing energy
throughout the year.Seasonal rates are a step toward
proper price signals because they deaverage the annual
cost and provide seasonal (or monthly) rates that are
more reflective of the average cost in that month.
achieve the best possible match between power cost and
rates, the monthly cost could be deaveraged and provide
hourly rates that are more reflective of the average cost
in that hour or group of hours.In the absence of TOU
meters, however , energy used during the heavy-load hours
of the month cannot be distinquished from energy used in
light-load hours.Much of the base load energy used for
refrigeration, lighting, water heating and small
appliances occurs off -peak.By contrast, energy used for
air conditioning typically occurs during the peak period.
By allotting each customer a base amount of energy, 800
kWh/month, that is priced at the lower base usage rate
some recognition is given to this off-peak energy use
that occurs in high-cost months but during low-cost
hours.
A base and peak energy rate is also justified
by looking at the utilization or dispatch of system
generation resources.The Company meets system load by
dispatching low-cost generation resources first.Then as
load increases the higher cost resources are dispatched,
CASE NO. IPC-03-02/20/0 1694 SCHUNKE , D.(Di) 19Staff
and only in the peak periods are the very high cost
peaking units dispatched to a small portion of the total
load.The lowest cost resources supply energy for the
base load consumption during the entire year , even during
peak demand in the summer months.
It is only when customer demand exceeds this
base level of consumption that higher cost resources are
needed.When this occurs, as it does during the summer
peak period, energy rates provide a price signal
indicating that higher priced resources are being
utilized.Therefore , Staff believes that the peak period
energy charge should only be applied to incremental
energy provided by expensive marginal resources or
peaking units to meet load above base level consumption.
How did you determine that 800 kWh was the
right amount to use for base level consumption?
Staff Exhibit No. 129 shows the monthly average
residential load which varies from just over 800 kWh in
the spring and fall to over 1100 kWh in the summer and
over 1300 kWh in the winter.The expens i ve peak
generation is only required in the summer and winter.
The system utilizes less expensive generation to meet the
fall and spring load.Therefore, I selected 800 kWh to
define the base level consumption that can be met by
low-cost base load generation.This is the same level of
CASE NO. IPC-03702/20/0 1695 SCHUNKE, D.(Di) 20Staff
consumption established by the Commission to define the
first block of the tiered rates in place during the
2001-2002 PCA period in Order No. 28852.
How did you determine a peak period rate?
The differential recommended by Staff is 20%,
approximately the same as what the Company is
recommending.I believe that increase achieves a
reasonable balance that sends an appropriate price signal
to customers, is affordable, and is cost-justified based
on the higher cost resources needed to meet higher loads.
How do the proposed rates compare with current
rates?
Staff Exhibit No. 130 shows a graphic
comparison between current bills and Staff's proposed
summer and non-summer bills at various kWh usage.
Because Staff's proposed non-summer energy rate is the
same as the current energy rate and because the proposed
non-summer customer charge is only $0.49 higher than the
current customer charge , at all levels of usage the graph
of current bills and proposed non-summer bills appear to
be the same.
The Staff -proposed summer energy rate would be
the same as the non-summer energy rate for usage up to
800 kWh/month.Therefore bills would be the same in
summer or non-summer up to the 800 kWh , and $0.49 higher
CASE NO. IPC-03-02/20/0 1696 SCHUNKE, D.(Di) 21Staff
than current bills.For usage in excess of 800 kWh , the
summer rate is higher than the non-summer rate; therefore
CASE NO. IPC-E- 03 -
02/20/0
summer
1697 (Di) 21a
Staff
SCHUNKE, D.
bills are higher than non-summer bills for usage above
800 kWh.For example, at 2000 kWhs of usage a
residential customer would pay $101.12 under current
rates, $101.61 under Staff-proposed non-summer rates, and
$113.27 under Staff-proposed summer rates.
Please explain Staff Exhibit No. 131.
Staff Exhibit No. 131 is a graphic display of
the total annual Residential Bill Frequency analysis
results for November 2002 through October 2003.I t shows
the number of customer bills at various blocks of energy
usage.The highest number of bills occur around 600 to
700 kWhs per month.The number of bills per block of
monthly usage begins to drop off quickly as usage gets
above 1000 kWhs.Almost 80% of the bills are for usage
below 1500 kWhs and about 90% of the bills are for usage
below 2000 kWhs.Only 3% of the total bill exceed 3000
kWhs per month.The number of kWhs billed in the block
and the number of kWhs in the block are also shown on
this graph.
What are the revenue effects of changing the
summer peak rate and the base energy rate?
Under my proposal for residential customers, a
one-cent/kWh increase in the summer peak rate over
existing base rates will produce $3.4 million in
addi tional revenue.A one - cent increase in the base
CASE NO. IPC-E- 03 -02/20/0 SCHUNKE, D.(Di) 22Staff
1698
rates over the current base rate will produce $38 million
in additional revenue.As previously discussed a $1.
increase in the customer charge produces $4 million in
addi tional revenue.
RATE DESIGN SCHEDULE 7
What change in revenue requirement is Staff
recommending for Small General Service Schedule
Staff is recommending an average overall
increase in revenue of 4.17% to Small General Service
Schedule 7.
What is your recommendation for the Small
General Service Schedule 7 rate design?
I am recommending that (1) the customer charge
be increased to $3.50;(2) the energy rate for the base
period remain the same as the current energy rate,
$0. 059649/kWh; and (3) the rate for energy use in excess
of 600 kWh in the peak summer months (June, July and
August) be increased 16.5% to $0.069459/kWh.Staff
Exhibit No. 132 shows the existing and Staff-proposed
rates along with the resulting revenue for Schedule
The Company has proposed an increase in the
Schedule 7 customer charge from $2.51 to $10.00.Do you
agree with this proposal?
No.For the same reasons cited for the
residential customers, I am opposed to a $10.00 customer
CASE NO. IPC-03-02/20/0 1699 SCHUNKE , D.(Di) 23Staff
charge.
Do you believe some increase in the customer
charge is justified?
Yes.I am recommending that the Schedule 7
customer charge be increased to $3.50.
What did you base the $3.50 amount on?
The same rationale presented in my discussion
of the residential rates applies here.The customer
charge should be based on the direct cost of meter
reading and billing.According to the Company
analysis, the monthly cost associated with meter reading
and billing for Schedule 7 is $4.34.Given the
relatively small overall increase in rates that Staff is
recommending, I believe $3.50 is the appropriate amount
for the customer charge.This would cover the maj ori ty
of meter reading and billing costs.However , if
additional revenue is required from Schedule 7 customers,
I believe a customer charge that moves closer to the full
cost of meter reading and billing would be reasonable.
Why are you recommending a higher customer
charge for Schedule 7 than for Residential Schedule
Schedule 7 has a higher cost of billing and
meter reading and Staff's overall proposed revenue
increase for Schedule 7 is higher than residential
Schedule 1.
CASE NO. IPC-03-
02/20/0
(Di) 24Staff1700SCHUNKE, D.
Describe the Small General Schedule 7 proposed
energy rate.
The energy rate would consist of two
components. The base use rate which would apply to all
energy used in the non-summer period and the first 600
kWh per month in the summer period.The peak period
energy rate would apply only in the summer months for
energy used in excess of 600 kWh/month.The peak period
energy rate would be about 17% higher than the base rate
to reflect the higher power supply cost in that period.
This is similar to the summer/non-summer differential
that the Company is proposing and it would apply only to
energy used above base monthly usage during the peak
summer period.
Why should the peak period rate only apply to
energy used in excess of 600 kWh per month in the summer
months?
The justification for this peak period rate
design was previously discussed in the residential rate
section of my testimony.
How did you determine that 600 kWh was the
right amount to use for the base level of consumption?
Staff Exhibit No. 133 shows that the average
Schedule 7 load varies from about 650 to 700 kWh per
month in the spring and fall to almost 900 kWh per month
CASE NO. IPC-E- 03 -02/20/0 SCHUNKE , D.(Di) 25Staff
1701
. 19
in the summer.Therefore , I have selected 600 kWh to
define the
CASE NO. IPC-E- 03 -
02/20/0
SCHUNKE, D. (Di) 25a
Staff
1702
base level of monthly consumption that can be met by
low-cost base load generation.
How was the peak period rate determined?
The peak period rate of $0. 069459/kWh is about
16.5% higher than the base use rate of $0.059649/kWh.
The relative differential between the base use rate and
the peak period rate is less than the differential
recommended by the Company between summer and non-summer.
However, I believe it is large enough to provide a
reasonable price signal to customers reflecting the
higher cost of generating resources.
RATE DESIGN LARGE GENERAL SERVICE SCHEDULE 9
What is the overall rate change recommended by
Staff for the Large General Service Schedule 9 (secondary
service) ?
Staff recommends an overall rate decrease of
13% .
What is your recommendation for the Large
General Service Schedule 9 secondary service rate design?
I am recommending that (1) the customer charge
and the basic charge remain the same;(2) the summer
demand charge be increased from $2.73 to $3.00 and the
non-summer demand be reduced from $2.73 to $2.62 for an
overall reduction in the demand charges of 0., and (3)
the energy rate for the non-summer period be reduced 4%
CASE NO. IPC-03-02/20/0 1703 SCHUNKE , D.(Di) 26Staff
and the summer energy rate increase 10% for an overall
decrease in the energy rate of 1%.These rates are
shown on Staff Exhibi t No.134,page
The Company has proposed an increase in the
Schedule 9 (secondary service) customer charge from $5.
to $21.00.Do you agree with this proposal?
No.Because the overall rate change proposed
is a decrease of 0.13%, I am recommending no change in
the customer charge.Furthermore, the direct cost of
meter reading and billing for these customers is $4.56,
so the current charge already covers the full cost of
meter reading and billing.
What is the overall rate change recommended by
Staff for Large General Service Schedule 9 (primary and
transmission) ?
Staff recommends an overall increase of 13.31%.
What are your rate design recommendations for
Schedule 9 primary service?
I am recommending that (1) the customer charge
for primary service be increased from $85.58 to $100.00,
a 13 % increase;(2) the basic charge be increased from
$0.77 to $0., a 13% increase;(3) the summer demand
charge be increased 25% from $2.65 to $3., with the
non-summer demand charge increasing 9% from $2.65 to
$2.89 for an overall increase of 13% in the demand
CASE NO. IPC-03-02/20/0 1704 SCHUNKE , D.(Di) 27Staff
charges; and (4) an overall energy rate increase of 13%,
with the summer rate increasing 25% and non-summer
increasing 9%.These rates are shown on Staff Exhibit
No. 134, page 2 of
What are your rate design recommendations for
Schedule 9 transmission service?
I am recommending that (1) the customer charge
for transmission service be increased from $85.58 to
$100.00, a 13% increase;(2) the bas i c charge
increased from $0.39 to $0., a 13% increase;(3) the
summer demand charge increase 25% from $2.57 to $3.22,
with the non-summer demand increasing 9% from $2.57 to
$2.80 for an overall increase of 13% in the demand
charges; and (4) an overall energy rate increase of 13%,
with the summer rate increasing 25% and non-summer
increasing 9%.These rates are shown on Staff Exhibit
No. 134 , page 3 of
RATE DESIGN LARGE POWER SERVICE SCHEDULE 19
What is Staff's recommended change in the
revenue requirement for Large Power Schedule 19?
Because Staff's COS analysis shows no change in
revenue requirement for Schedule 19, my proposed changes
in rate design are revenue neutral.I am recommending
rate design changes in the demand and energy charges
consistent with the Company's proposal for seasonal and
CASE NO. IPC-E- 03 -
02/20/0 SCHUNKE , D.(Di) 28Staff
1705
time-of -use rates.TOU rates are most appropriate for
Schedule 19 customers who are sophisticated enough to
CASE NO. IPC-03-
02/20/0
1706 SCHUNKE , D. (Di) 28a
Staf f
understand them and where the metering equipment already
exists.
Please summarize the rates you are proposing
for Schedule 19.
For Schedule 19 I am recommending no change in
the customer charge or the basic charge.Currently there
is no distinction in the demand or energy charges between
summer and non-summer , peak and non-peak.My proposal
like that of the Company's, would be to price peak demand
and energy higher in the summer and in the peak periods.
The specific rates that I am proposing are shown in Staff
Exhibi t No. 135, page 1 , Schedule 19 Secondary; page
Schedule 19 Primary; and page 3, Schedule 19
Transmission.
RATE DESIGN IRRIGATION SCHEDULE 24
What is Staff's recommended revenue requirement
increase for Irrigation Schedule 24?
Staff recommends that Schedule 24 rates be
increased by 15% or about one-third the amount dictated
by the COS study.
Why is Staff not recommending that Schedule
rates be increased the full amount dictated in COS?
The increase to move Schedule 24 to the full
COS would be 47.2%.Staff believes that amount of
increase is excessive and should not be made all at one
CASE NO. IPC-E- 03 -
02/20/0
1707 SCHUNKE , D.(Di) 29
Staff
time. The amount of increase that is reasonable is a
matter of
CASE NO. IPC-03-
02/20/0 1708 SCHUNKE, D.(Di) 29aStaff
judgment.While irrigators would receive a substantial
rate increase (15%), the one-third move requires that
over $19 million attributable to irrigation customers be
reallocated to the other customer classes.If this
reallocation amount were much greater , other customer
classes would be affected to the point that some would
actually require increases larger than that required for
Schedule 24.Staff felt that a one-third move toward COS
was a reasonable balance between the obj ecti ves of COS,
the subsidy required from other classes , and the ability
of the irrigation class to absorb the rate increase.
What is the history of COS for the Irrigation
Schedule 24?
In the U-I006-265 rate case, the increase
needed to bring Schedule 24 to the full COS rate of 40.
mills/kWh , was 31.71%.The Commission ordered a 5.02%
increase bringing the average rate for the Schedule to
32.08 mills/kWh.Order No. 20610.
In the next general rate case, IPC-E- 94 - 5, the
increase needed to bring Schedule 24 to the full COS rate
of 40.78 mills/kWh , was 17.99%.The Commission ordered a
10.23% increase bringing the average rate for the
Schedule to 38.10 mills/kWh.Order No. 25880.
Currently, Schedule 24 is paying an average
rate of 37.2 mills/kWh.The Staff's COS study indicates
CASE NO. IPC-E- 03 -02/20/0 1709 SCHUNKE , D.(Di) 30Staff
that the full cost of service rate is 54.76 mills/kWh and
would require a 47.22% increase.With the 15% increase
that Staff is proposing, the Schedule 24 rate would
increase to 42.77 mills/kWh.
It is interesting to note that if one were to
rely on the COS study that the Commission used in the
I006-265 case in 1986, Schedule 24 would require an
2% increase to bring them to the full 1986 COS rate
even with no overall increase in revenue to the Company.
Today, Staff I s proposal for the 15% increase would bring
Schedule 24 to a rate just 2.5 mills above their 1986 COS
rate.
What is your rate design proposal for Schedule
24?
I am proposing an overall increase in the
Schedule 24 rates of 15%.The in- season customer charge
("bills in-season") would increase from $10.07 to $12.00;
the out-of-season customer charge ("bills out-of-season"
and the minimum charge would increase from $2.50 to
$3.00. The in-season demand charge would increase from
$3.58 to $4.00 and I am proposing that there be an
out-of-season demand charge of $0.80.I propose to
reduce the out-of-season energy rate so that it is no
longer higher than the in-season rate.The in-season
energy rate would increase 16%, and the out -of - season
CASE NO. IPC-03-02/20/0 1710 SCHUNKE, D.(Di) 31Staff
energy rate would decrease 9% so that both rates are
equal at $0. 032830/kWh.These
CASE NO. IPC-03-
02/20/0
1711 SCHUNKE, D. (Di) 31aStaff
rates are summarized on Staff Exhibit No. 136.
How did you arrive at your proposed increase
for the bills in-season, bills out-of-season and the
minimum charge?
I appl ied the average increase of 15 % to the
existing rate and rounded to an even dollar amount.For
example, a 15% increase to the $2.50 minimum charge or
bills out-of-season would be $2.88, which I rounded up to
$3.00.Under my proposal the Residential Schedule 1 and
the Irrigation Schedule 24 would have the lowest minimum
charge of any customer class at $3.00.
How did you arrive at the amount of your
proposed increase for the in-season demand charge?
I applied the average increase of 15% to the
existing rate and rounded to an even dollar amount.
Why are you proposing an out-of-season demand
charge?
Currently there is no demand charge
out-of-season.Any fixed cost that would normally be
collected in a demand charge are now collected in the
out-of-season energy rate.This results in an
out-of-season energy rate that is 27% higher than the
in-season energy rate.Al though I understand why this
may have occurred in the past, it now seems inconsistent
wi th proposed rate structures designed to send price
CASE NO. IPC-E- 03 -
02/20/0 SCHUNKE , D.(Di) 32Staff1712
signals reflecting higher costs in peak periods than in
off peak periods.I am proposing an out-of-season demand
charge that would recover the fixed costs that are now
being collected in the out-of-season energy rate so that
an out-of-season energy rate can be set that is no higher
than the in-season energy rate.
How did you arrive. at the amount of your
proposed out-of -season demand charge?
If the current out-of-season energy rate were
set equal to the current in-season energy rate, it would
collect $2.4 million less revenue.I propose to collect
that amount plus 15% (the average proposed increase) in
the out-of-season demand charge, or $0.80.This protects
the current split between in-season revenue and
out-of-season revenue, but it collects fixed
demand-related costs in the demand charge and not in the
energy charge.This restores an energy rate that is more
reflecti ve of power supply cost.
How did you establish the energy rate?
I calculated the average energy rate necessary
to produce the total revenue requirement with the
in-season energy rate set equal to the out-of-season
The resulting energy rate is $0. 03283/kWh,energy rate.
which is 15% higher than the current in-season rate and
9% lower than the current out-of -season rate.
CASE NO. IPC-E- 03 -
02/20/0 SCHUNKE, D.(Di) 33Staff1713
How will this new out-of-season demand charge
affect irrigation customers?
Staff Exhibit No. 137 shows what an irrigation
bill would be for operation of a 100 horsepower pump
using various amounts of energy under the proposed rate
1) with a demand charge and lower out-of-season energy
rate, and 2) without a demand charge but with the higher
out-of-season energy rate.It shows that for usage above
6843 kWh in a month the customer will actually pay less
under the proposed rate than he or she would under rates
wi thout a demand charge.Customers with high demand and
low usage will pay more and those with low demand and
high usage will pay less.If an irrigation customer
started a single 100 horsepower pump and ran it for only
10 hours in the entire month, having no other usage, he
would pay $34.20 under the rate without a demand charge
as compared to $87.56 under the proposed rate with the
demand charge.If that same horsepower pump were to
operate for 200 hours, the bills would be $552.00 under
the rate with a demand charge and $624.00 under the
proposed rate without the demand charge.
What is the overall change in revenue that
Staff recommends for the TOU Irrigation Schedule 25?
Staff recommends an overall average increase in
rates for TOU Irrigation of 15%, which is the same as
CASE NO. IPC-E- 03 -02/20/0 1714 SCHUNKE , D.(Di) 34Staff
that recommended for the Irrigation Schedule 24.
What are your rate design recommendations for
Schedule 25?
I am making the same rate design proposal for
Schedule 25 as I made for Schedule 24 except the energy
rates are dependant on TOU.
(a)In-season charges would increase from
$10.07 to $12.00; out-of-season charges and minimum
charges would increase from $2.50 to $3.00; the meter
charge would remain at $3.00; the in-season demand charge
would increase from $3.58 to $4.00; and the out-of-season
demand charge would be established at $0.80.
(b)I maintained the same relationship between
the On-peak, Mid-peak and Off -peak rates while reducing
the out-of -season rate to be equal to the Mid-peak rate.
The resulting energy rates are 19.7% higher than current
rates except for the out -of - season rate, which is 5.
lower.The energy rates are as follows:
On-peak $0. 059544/kWh; Mid-peak $0. 034025/kWh; Off-peak
$0. 017013/kWh; and Out-of-Season $0. 034025/kWh.The
rates are shown on Staff Exhibit No. 138.
What are your recommendations for Dusk to Dawn
Lighting Schedule 15 , Unmetered General Service Schedule
, Street Lighting Schedule 41 , and Traffic Control
Lighting Schedule 42?
CASE NO. IPC-03-02/20/0 1715 SCHUNKE, D.(Di) 35
Staff
I am recommending a uniform change in all the
rates (except the minimum charges) for Schedules 15 , 40,
and 41 for an overall reduction of 36.6%, 10.48%, and
91%, respectively.I am recommending no change in
Schedule 42.
What is your recommendation for the following
contract schedules:Schedule 26 Micron , Schedule 29
Simplot, and Schedule 30 DOE?
I am recommending a uniform change reduction in
rates for Micron of 2.01%, a uniform reduction in rates
of 3.43 % for Simplot, and a uniform increase in rates of
1. 05% for DOE.
Do you have any other rate design
recommenda t ions?
Yes, I am recommending no change in the Energy
Efficiency Rider Schedule 91.
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NO. IPC-E- 03 -
02/20/0 1716 SCHUNKE , D.(Di) 36Staff
(The following proceedings were had in
open hearing.
COMMISSIONER SMITH:Mr. Eddie, do you
have questions?
MR. EDD IE:I have just a few questions
for Mr. Schunke.Shall I go ahead?
COMMISSIONER SMITH:Okay, please go
ahead.
CROSS -EXAMINATION
BY MR. EDDIE:
Mr. Schunke, page 17 of your testimony at
line 6, lines 4 through 6, you say, "The customer charge
should be based on the direct cost of meter reading and
billing and should not include any fixed plant cost.
"fixed plant cost," that would include the cost of the
distribution system?
Yes.
At page 18, the next page, 1 ine 2 , you
note that a rate design option for the Commission would
be to more greatly increase the fixed charge or perhaps
not do anything with the summer rate or decrease the
summer rate.
COMMISSIONER KJELLANDER:Mr. Eddie, I
CSB REPORTING
Wilder, Idaho
1717 SCHUNKE (X)Staff83676
still can't hear you.
MR. EDDIE:Sorry.
BY MR. EDDIE:You note at page 18, line
, that the option could be to increase the fixed charge.
CSB REPORTING
Wilder , Idaho
Is the essential reason that you have not recommended
that increase in the fixed charge is that rate design
should, in essence, send a proper price signal to
Well , I did recommend an increase in the
Beyond the $3. OO?
, beyond the $3. OO?
Yes.
Well , there's two reasons that I describe
in my testimony there for not going beyond the $3.00.
The first one is that the revenue requirement the Staff
is proposing doesn't really require that we go beyond the
$3.00.Then it's my position that anything beyond the
-- let me find that, $4.20 would not be
Okay, is it true that one price signal
that Staff's recommendation is trying to send to
customers is that least cost resources should be
utilized, trying to encourage the use of least cost
resources through your rate design proposal?
customers?
fixed charge.
four dollars and
cost j ustif ied.
1718 SCHUNKE (X)Staff83676
Well, that's true.
Would it also be true that a sharp
increase in the fixed service charge could have an
opposi te effect?
Yes , it could have the effect of lowering
the energy rate which I believe could send the wrong
price signal.
Your analysis also at page 18 indicated
that the level of about 800 kilowatt-hours per month for
the residential class, that level of usage could
essentially be served by the Company's base load
resources.
Yes.
In your judgment , has Idaho Power'
proposal to have a higher summer rate for all
kilowatt-hours, does that go too far?Does it go too far
in terms of not seeking to discourage the use of high
cost resources , peaking resources, perhaps paint with too
broad of a brush?
Well, I state in my testimony that the
Company's proposal for a seasonal rate is one approach.
I think seasonal rates are a step in the right direct
direction.I think they're better than just a flat rate
year-round.I obviously believe that the proposal that
make has some advantages.
CSB REPORTING
Wilder, Idaho
1719 SCHUNKE (X)Staff83676
You also note at page 20 of your
testimony, it's just a reference to the fact that Idaho
Power serves a load that has two peaks per year , summer
and winter peak.Staff has not proposed or do you agree
that Staff has not proposed a pricing system that would
target that winter peak?
That I S true.
Could you just briefly explain why that'
the case?
As I discuss in my testimony, I mention
the fact that the Company does have a winter peak.
think the Company discusses that , also , and I quote
Ms. Brilz in my testimony.I mention that if the
Commission were to determine implementing a seasonal rate
similar to what I propose in both summer and winter,
think that that could be implemented fairly easily if the
Commission determined that was appropriate.Tha t was not
part of my testimony and that was not my recommendation
but I would certainly not be opposed to that either.
Okay, thank you.Lastly, have you
reviewed the direct testimony filed by Ralph Cavanagh in
this case on behalf of Northwest Energy Coalition?
Yes.
Would you support the Commission
initiating a proceeding or investigation to examine the
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Wilder , Idaho
1720 SCHUNKE (X)
Staff83676
type of true-up mechanism for fixed cost recovery that
Mr. Cavanagh has proposed?
I would support a review to examine
methodologies, Mr. Cavanagh's being one of them.I don'
think that should be the only one, but I think it should
examine possibilities to resolve those issues.
Resolve the fixed cost recovery/lost
revenues issue?
Yes.
MR. EDDIE:Okay, thank you.Nothing
further.
COMMISSIONER SMITH:Mr. Purdy.
MR. PURDY:Yes.
COMMISSIONER SMITH:How much do you have?
MR. PURDY:Probably more than 15
minutes.
COMMISSIONER SMITH:Okay, let I s go
lunch, then , and come back at 1:00 p.When we'
finished with Mr. Schunke, Mr. Richardson had requested
that Mr. Henderson be taken.
MR. RICHARDSON:That's right,
Madam Chairman.Mr. Henderson is available to present
his rebuttal testimony at 1: 00 0' clock.
COMMISSIONER SMITH:Well , we won't do it
at 1: 00 0' clock because I don't want to interrupt
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Wilder , Idaho
1721 SCHUNKE (X)
Staff83676
Mr. Schunke.
MR. RICHARDSON:
COMMISSIONER SMITH:
Mr. Schunke is completed.
That's fine.
So we'll do it after
Thank you
Madam Chairman.
CSB REPORTING
Wilder , Idaho
MR. RICHARDSON:
(Noon recess.
1722
83676
COLLOQUY