20040220schunke direct.pdf

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS INTERIM
AND BASE RATES AND CHARGES FOR
ELECTRIC SERVICE.
) CASE NO. IPC-O3-
DIRECT TESTIMONY OF DAVE SCHUNKE
IDAHO PUBLIC UTILITIES COMMISSION
FEBRUARY 20 , 2004
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 Utili ties Engineer.
What is your educational and experience
background?
I received my Bachelor of Science Degree in
Civil Engineering at Montana State Uni versi ty 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
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
involved 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
Deputy Administrator from 1991 through 2000 and Engineer
CASE NO. IPC-E- 03 -
02/20/04 (Di)SCHUNKE , D.Staff
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 propos~l 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 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
lncreases 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 time-of -use
(TOU) rates wherever they are practical.Staff recommends
CASE NO. IPC-E- 03 -02/20/04 (Di)SCHUNKE, D.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 $2.51 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-03-1302/20/04 (Di)SCHUNKE, D.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.
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
wi th 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 $2.51 to
$3.00.The in-season demand charge would increase from
$3.58 to $4.00 and I -am proposing an out-of-season demand
CASE NO. IPC-03-
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(Di)SCHUNKE, D.Staff
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 36.6%, 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 obj ecti ves?
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 with 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 major factor in determining the cost of service.
These differences are generally addressed by grouping
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE , D.Staf f
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 custDmer 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 objective 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 reasonable
by balancing the cost of service goals with the goals for
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
6 .
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 at tempted 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'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 cos t , hydro condi t ions, 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?
No.While I believe that their rates should be
increased sufficiently to move the irrigation class in a
significant way toward COB, I also believe that some cap
is necessary in order to keep the increase reasonable.
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.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 cas amount.All other customer classes
would move to full cost of service with two adjustments
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% I 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 Adjustment is
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
shown in Staff Exhibit No. 127, Column 6, "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
Adjustment, the adjustment 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-E- 03 -02/20/04 (Di)SCHUNKE , D.Staff
final revenue requirement proposal for the customer
classes after the adj ustments 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 obj ectives?
Deaveraging rates so they can be pricedYes.
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 faci~ities 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?
Nei ther the Staff nor the Company proposal would
CASE NO. IPC-E- 03 -02/20/04 (Di)SCHUNKE, D.Staff
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 I line 12) :
The Company faces its highest power supply
costs during the months of June, July, and
August.
...
i t is the peak usage during these three
months , along with the usually low hydro
conditions 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 conditions
during the November-December winter peak also contribute
to the Company s need to seek new peaking resources.
the Commission determines that the seasonal rates should
be extended to winter peak months l it would not be
difficul t 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 Tau rates?
Seasonal rates are easier to implement and do
not require the special equipment that Tau rates do.The
primary disadvantage of seasonal rates is that they do not
CASE NO. IPC-E- 03 -
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(Di)SCHUNKE, D.Staff
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 within
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?
There are a number of rate designs thatYes.
can provide proper price signals.Each has its advantages
and di sadvantages .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 coincident with higher
CASE NO. IPC-03-02/20/04
(Di)SCHUNKE , D.Staff
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 also 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 hope of reducing the
peak load during that period.The Commission presently
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
has an Idaho Power application before it in Case No.
IPC-E- 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
ul timately 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:
Al though 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 to
supply-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 significantneed for capacity 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-effecti ve DSM or other conservation programs.
RATE DESIGN - RESIDENTIAL
What change in revenue requirement is Staff
recommending for Residential Schedule 1?
CASE NO. IPC-E- 03 -02/20/04 (Di)SCHUNKE, D.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 customer charge
be increased to $3.00 i (2) the energy rate for the base
period remain the same as the current energy rate,
$0. 049303/kWhi 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?
The Company s proposal increasei theNo.
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 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-03-02/20/04 (Di)SCHUNKE, D.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:
...
promotinq additional enerqy usaqe through a
general policy change is not in the long-term
best interest of the Company or itscustomers. Furthermore, the proposed
customer charge is too hiqh 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.
customer charge.Order No. 25880.
Do you believe some increase in the customer
charge is justified?
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staf f
I am recommending that the residentialYes.
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 ch&rge 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.
addi tional 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.
If the customer charge were increased to $4.00, the full
increase in revenue requirement recommended by 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-E- 03 -
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(Di)SCHUNKE , D.Staff
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 r~te?
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 year and from
hour to hour throughout the day, energy rates currently
CASE NO. IPC-E- 03 -02/20/04 (Di)SCHUNKE, D.Staff
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.To 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
and only in the peak periods are the very high cost
CASE NO. IPC-E- 03 -
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(Di)SCHUNKE, D.Staff
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 expensive 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
consumption established by the Commission to define the
CASE NO. IPC-03-02/20/04
(Di)SCHUNKE , D.Staff
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'
proposed non- summer energy rate is the same as the current
energy rate and because the proposed non-summ~r 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 than
current bills.For usage in excess of 800 kWh, the summer
rate is higher than the non-summer rate; therefore summer
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
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.
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 rates
CASE NO. IPC-E- 03 -
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SCHUNKE, D.Staff (Di)
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 t ional revenue.
RATE DESIGN SCHEDULE 7
What change in revenue requirement is Staff
recommending for Small General Service Schedule 7?
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/kWhj 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
Exhibi t 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?
For the same reasons cited for theNo.
residential customers, I am opposed to a $10.00 customer
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
charge.
Do you believe some increase in the customer
charge is justified?
I am recommending that the Schedule 7Yes.
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 s 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
lncrease for Schedule 7 is higher than residential
Schedul e 1.
CASE NO. IPC-O3-02/20/04 (Di)SCHUNKE , D.Staff
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 in the
summer.Therefore, I have selected 600 kWh to define the
CASE NO. IPC-E- 03 -02/20/04 (Di)SCHUNKE, D.Staff
- 5
! 21
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 ba sic 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 0.4%, and (3)
the energy rate for the non-summer period be reduced 4%
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
and the summer energy rate increase 10% for an overall
decrease in the energy rate of 0.1 % .These rates are
shown on Staff Exhibit No. 134 , page 1 of
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?
Because the overall rate change proposed isNo.
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.
to $0., a 13% increase;(3) the summer demand charge be
increased 25% from $2.65 to $3.32, with the non-summer
demand charge increasing 9% from $2.65 to $2.89 for an
overall increase of 13% in the demand charges; and (4) an
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
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 3.
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., a 13% increase;(2) the basic charge be increased
from $0.39 to $0.44, 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
time-of -use rates.TOU rates are most appropriate for
Schedule 19 customers who are sophisticated enough to
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.Staff
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 2,
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 24
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 time. The
amount of increase that is reasonable is a matter of
CASE NO. IPC-O3-
02/20/04
(Di)SCHUNKE , D.Staff
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-IO06-265 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-94-S, 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 that
CASE NO. IPC-E- 03 -02/20/04 (Di)SCHUNKE , D.Staff
the full cost of service rate is 54.76 mills/kWh and would
require a 47.22% increase.wi th 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 s~udy that the Commission used in the
I006 -265 case in 1986, Schedule 24 would require an 8.
increase to bring them to the full 1986 COS rate even with
no overall increase in revenue to the Company.Today
Staff'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-o~-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 energy rate would decrease 9%
so that both rates are equal at $0. 032830/kWh.These
CASE NO. IPC-E- 03 -
02/20/04 (Di)SCHUNKE, D.Staff
rates are summarized on Staff Exhibit No. 136.
the bills in-season, bills out-of -season and the minimum
How did you arrive at your proposed increase for
charge?
I applied 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
$3.00.
bills out-of-season would be $2.88, which I rounded up to
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?
season.
Currently there is no demand charge out-of-
Any fixed cost that would normally be collected
energy rate.
in a demand charge are now collected in the out-of-season
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 with proposed rate
structures designed to send price signals reflecting
CASE NO. IPC-03-02/20/04 SCHUNKE, D.
Staf f
(Di)
higher costs in peak periods than in off. peak periods.
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 reflective 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 energy
rate.The resulting energy rate is $0. 03283/kWh, which
15% higher than the current in-season rate and 9% lower
than the current out-of-season rate.
CASE NO. IPC-03-
02/20/04
(Di)SCHUNKE , D.Staff
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 without
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.
under the rate without a demand charge as compared to
$87.56 under the proposed rate with the demand charge.
that same horsepower pump were to operate for 200 hours
the bills would be $552.00 under the rate without a demand
charge and $624.00 under the proposed rate with 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 that
CASE NO. IPC-E- 03 -02/20/04 (Di)SCHUNKE , D.Staff
8 ,
recommended for the Irrigation Schedule 24.
What are your rate design recommendations for
Schedule 25?
I am making the sam~ 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 j 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/kWhj Mid-peak $0. 034025/kWhj Off-peak
$0. 017013/kWhj 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
40, Street Lighting Schedule 41, and Traffic Control
Lighting Schedule 42?
CASE NO. IPC-03-02/20/04 (Di)SCHUNKE, D.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., 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
rat~s for Micron of 2.01%, a uniform reduction in rates of
43% for Simplot, and a uniform increase in rates of
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-O3-
02/20/04
(Di)SCHUNKE, D.Staff