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Q. Please state your name and business address for
the record.
A. My name is Keith D. Hessing and my business
address is 472 West Washington Street, Boise, Idaho.
Q. By whom are you employed and in what capacity?
A. I am employed by the Idaho Public Utilities
Commission as a Public Utilities Engineer.
Q. What is your educational and experience
background?
A. I am a Registered Professional Engineer in the
State of Idaho. I received a Bachelor of Science Degree
in Civil Engineering from the University 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. I have
worked with Idaho Power’s (Company) Power Cost Adjustment
(PCA) mechanism since 1992 when the formative case was
filed.
Q. What is the purpose of your testimony in this
proceeding?
A. My testimony addresses the calculation of the
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PCA forecast and true-up, alternatives for recovery of
this year’s PCA costs, the design of rates, except
residential rates, and a Demand Side Management (DSM)
rate rider.
Q. Please summarize your testimony.
A. I determine that the Company’s calculation of
the coming year’s power supply forecast cost is done
according to the Commission-approved methodology. I
incorporate four adjustments proposed by Staff witness
Holm into the true-up calculation. These adjustments
reduce the true-up amount to be recovered from ratepayers
by approximately $16 million. I review four
alternatives, including the Company’s three-year
securitization proposal, for spreading this year’s PCA
costs over one or more years. I recommend a two-year
recovery period with no securitization. My proposal
reduces customer rates by an average of 9.6 percent in
the coming PCA year. I recommend that PCA rate
reductions be incorporated in all customer rates on an
equal cents per kilowatt-hour basis except residential
customer rates. Staff witness Schunke addresses the rate
design for the residential class. I propose that a
Demand Side Management (DSM) rate be added to all
customer rates to fund additional DSM program costs.
Q. How do you view the two cases filed by Idaho
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Power that the Commission is reviewing in this
proceeding?
A. I view the consolidated case as Idaho Power
Company’s 2002 Power Cost Adjustment (PCA) rate filing.
The filing proposes a mechanism to recover PCA costs by
adjusting customer rates. The Company’s proposal seeks
to recover PCA costs using a combination of a PCA rate
and a securitized rate.
PCA DESCRIPTION AND HISTORY
Q. Please describe in general Idaho Power
Company’s Power Cost Adjustment Mechanism.
A. Idaho Power’s PCA is a rate adjustment
mechanism that annually increases or decreases customer
rates to reimburse the Company for above normal or below
normal costs of supplying power. Traditional power
supply costs are fuel costs and purchased power costs
offset by sales revenues from the sale of surplus energy.
The two major factors that affect power supply costs are
Snake River drainage water supply conditions and
Northwest wholesale power market prices. Good water
conditions decrease Idaho Power’s power supply costs and
return money to customers through reduced rates. Poor
water conditions increase power supply costs, which are
recovered from customers through increased rates.
Q. Traditionally, what have been the major
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components of the PCA?
A. Each year’s PCA has traditionally been composed
of a forecast or projection of costs for the coming year,
a true-up to actual costs of the previous year’s forecast
and a calculation of the PCA rate. Each year’s
forecasted PCA costs rely on the National Weather
Service’s River Basin forecast Center April 1 forecast of
April through July Brownlee Reservoir inflow volumes.
The estimated inflow volume is used in a mathematical
formula that relates inflow to Idaho Power’s power supply
costs. Only 90 percent of the above or below normal
forecasted power supply costs are allowed to be recovered
from customers in the PCA.
Each year the previous year’s forecasted power
supply costs are trued-up to actual power supply costs.
Ninety percent of the difference from normal goes into
the PCA. The other 10 percent of these costs are
absorbed by Idaho Power Company’s shareholders.
Finally, the PCA rate is calculated. The
dollar amount of the combined forecast and true-up is
divided by the number of kilowatt-hours (kWh) the Company
sells in a year. Customer rates are adjusted by this
¢/kWh amount, which may either increase or decrease
customer rates. Staff Exhibit No. 102 shows the history
of all PCA rate adjustments since the first PCA rate
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adjustment was instituted in 1992. The 2002 PCA amount
of $253.8 million is the amount I calculate, including
Staff adjustments, for the 2002 PCA year. In all PCA
years through 2001, the PCA amount has been recovered
from or credited to ratepayers in a single year. Some of
the options in this case would spread the recovery over
two or more years.
THE PCA FORECAST
Q. What is the Company’s proposed PCA forecast?
A. The Company proposes that the PCA forecast rate
be .2156 ¢/kWh. The rate is based on Brownlee inflows of
3.63 million acre-feet in the April through July period
this year. The Brownlee inflow forecast of 3.63 million
acre-feet is only 58 percent of normal. Last winter’s
precipitation was well above 58 percent of normal.
However, there are several large reservoirs above
Brownlee Reservoir on the Snake River. Due to last
year’s drought, these upstream reservoirs are low and
will require more of the available water than normal in
the April through July period. Therefore, the forecast
predicts only 58 percent of normal Brownlee inflow during
the April through July period.
Q. Do you agree with the Company’s calculation of
the forecast rate?
A. Yes I do. I have checked the April through
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July Brownlee inflow estimate and verified that the
Commission-approved methodology has been correctly
applied. Staff Exhibit No. 103 graphically represents
the computation of forecast PCA expense, which is later
used to calculate the forecast portion of the PCA rate.
I expect the proposed forecast rate to recover
approximately $27.5 million dollars during the PCA year.
THE PCA TRUE-UP
Q. What does the Company calculate the true-up for
2001-2002 to be?
A. The Company’s true-up calculation to last
year’s forecast, after jurisdictional allocation and
sharing between ratepayers and shareholders, indicates
that Idaho ratepayers are responsible for approximately
$223 million in unrecovered power supply costs and
miscellaneous items accorded PCA treatment. (Company
Exhibit No. 3) The true-up calculations contain
irrigation and Astaris load reduction costs, which
replaced market purchases, and some other new items
approved by the Commission for PCA treatment. Staff
witness Holm further discusses some of the components in
the true-up calculation.
Q. Does the Staff agree with the Company’s true-up
calculation?
A. Staff witness Holm proposes four changes to the
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Company’s true-up calculation. He proposes that lost
revenue be removed from irrigation load reduction program
costs, that an adjustment be made to mobile generation
costs and that two adjustments be made to the operating
costs of Idaho Power’s Mountain Home Combustion Turbine.
These adjustments to the Company’s true-up calculation
are shown on Staff Exhibit No. 104, pages 1 and 2. Page
1 shows March through October 2001 and page 2 shows
November 2001 through March 2002. The Staff adjustments
are in bold and shown on lines 14, 17 and 21. They are
all reductions to the Company’s actual PCA expense.
Q. What is the amount of the true-up recommended
by Staff?
A. The Staff adjustments to the true-up
calculation previously discussed reduce the amount of the
true-up from $223 million proposed by the Company to
approximately $207 million.
PCA COST RECOVERY OTIONS
Q. How does Idaho Power propose to recover this
year’s PCA cost?
A. Idaho Power proposes that part of the cost of
last year’s true-up and the unrecovered portion of last
year’s October PCA rate adjustment be spread over three
years. Idaho Power proposes to sell bonds and adjust
customer rates each year to ensure that the bonds are
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retired in three years. This bonding process is called
securitization. The securitized rates would also recover
bond interest and the cost of bonding. The remaining
unsecuritized portion of the true-up and the forecast
would be recovered using a normal PCA rate adjustment
over a one-year period.
Under the Company’s proposal, this year’s PCA
rates would have a PCA component and a securitization
component. The Company’s proposal offers customers an
average 6.6 percent decrease from existing rates in the
coming PCA year.
The Company proposes to securitize $172
million. This amount is composed of $147 million in
true-up costs, $18 million in unrecovered October 2001
PCA costs and $7 million in bonding costs. Bond interest
is in addition to the $172 million. As previously
mentioned, the securitization rate paid by customers also
includes bond interest, which can be estimated but is not
known until the bonds are sold. The one-year PCA rate is
composed of the remaining true-up amount of approximately
$76 million and the forecast amount of $28.5 million.
Under the Company’s proposal, PCA rates would
also decrease at the beginning of the second and third
PCA years, returning to base levels at the beginning of
the fourth year. Securitization causes additional
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interest and bonding costs.
Q. Have you reviewed additional options for the
recovery of this year’s PCA costs?
A. Yes. I have examined four options. Option No.
1 is the Company’s securitization proposal with Staff’s
adjusted true-up. None of the other three options
include securitization. Option No. 2 recovers all of the
PCA costs in the first PCA year, which requires an
increase above existing rates. Option No. 3 continues
the existing rates in the first PCA year and carries the
unrecovered costs over to the 2003 PCA year with
interest. Option No. 4 reduces rates in the first year
by an average amount of 9.6 percent, 7.8% for Residential
customers, and carries the unrecovered amount into the
2003 PCA year for recovery. The four options are
compared in Staff Exhibit No. 105.
Q. Please describe Staff Exhibit No. 105.
A. Staff Exhibit No. 105 identifies each of the
four options across the top of the columns. The cost
recovery proposed for each option is broken down by year
in the top three sections on the page. Each year
identifies costs to be recovered in that year under the
traditional “PCA” mechanism and with “Securitization”.
The bottom section on the page totals the recovery over
the three years identified. The bottom line on the page
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demonstrates that the total costs are the same for all
four options excluding interest and bonding.
Option 2, one year recovery, is the lowest cost
option because it has no additional interest or bonding
costs. Option 3, existing rates continued, demonstrates
the next lowest total cost. It includes $1.8 million in
interest costs associated with carrying $26.1 million
into the second PCA year for recovery. The third-lowest
cost option is Option 4. Due to the substantial first
year rate decrease it offers, it carries $96.6 million
into the second year which accumulates $6.8 million in
interest. Option 1, the securitization proposal is the
most expensive option. Over three years it incurs $11.9
million in interest costs and $9.4 million in bonding
costs.
In Option 1, bond interest has been assumed at
4 percent. In Options 2, 3 and 4, interest has been
assumed at 7 percent on the amount that is carried over
from one year to the next. Staff witness Holm makes the
Staff’s proposal concerning appropriate interest rates
for PCA purposes. That proposal has not been included
here due to the compressed time allowed for processing of
this case. Interest differences are small and would not
affect Staff’s proposal in this case.
Q. Which option do you recommend to the
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Commission?
A. I recommend Option 4, which immediately
decreases rates and avoids bonding costs and some of the
interest costs associated with securitization. It also
recovers this year’s PCA costs in two years, which
reduces the probability that a PCA true-up or forecast in
the third year would push rates to higher levels than
that year’s PCA alone would require. This type of
exposure exists during the second year of each option
except Option 2 which recovers all of this year’s PCA
costs in the first year but requires an increase over
existing rates to do it.
Q. Have you prepared exhibits that show the impact
of each of the options that you previously discussed on
each of the Company’s customer classes?
A. Yes I have. Staff Exhibit No. 106, pages 1
through 4 shows the expected impact of the Company’s
proposal, modified to reflect the Staff’s true-up
adjustments, on customer rates over the next 4 PCA years.
Staff Exhibit No. 107, pages 1 and 2, shows the rate
impact of Staff Option 2, single year recovery. Staff
Exhibit No. 108, pages 1 through 3, shows the rate impact
of Option 3, current rates continued. Staff Exhibit No.
109, pages 1 through 3, shows the rate impact of Staff
Option 4, which provides for an average 9.6 percent first
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year decrease without securitization.
The above analysis is limited to the effects
resulting from the decisions that the Commission will
make this year. Any future variations from normal water
conditions or normal power supply costs may cause other
rate differences in PCA years after 2002 that are not
contemplated in this testimony.
Q. How have you treated the $18 million in
unrecovered 2001 PCA costs that are scheduled for
recovery between May 16, 2002 and September 30, 2002?
A. I respread the costs over full PCA years in
each of the options that I have presented. The drawback
of respreading the $18 million to recover these costs is
that summer energy users receive lower rates that are
paid by winter energy users. It is a trade-off that
eliminates multiple PCA rate changes in the same year.
Also $18 million is a relatively small amount of the $253
million that I am proposing for recovery.
CUSTMER CLASS RATE DESIGN
Q. How does the Company propose to adjust rates
within customer classes to recover PCA costs?
A. Idaho Power proposes that the energy rate
within each customer class be adjusted by an equal
cents/kWh amount (i.e., a flat rate) to recover the
approved revenue. Schedules without energy-based rate
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components, such as lighting schedules, should have rates
adjusted by an equal percentage amount that recovers the
required revenue.
Q. Do you agree with the Company’s proposal?
A. Yes, except for residential class rates. Staff
witness Schunke addresses the design of Residential rates
in his testimony.
Q. Did the Commission order a portion of the costs
included in this year’s PCA true-up calculation be
recovered from a specific class of customer?
A. Yes. Orders in two different cases required
that intervenor funding awarded to the irrigation class
be included in the PCA and be recovered from irrigators.
This would require that the PCA rate for irrigators be
different than the PCA rate for all other customer
classes. Given the very small amount subject to recovery
and the fact that the PCA is not set up to apply
different rates to different customer classes, Staff
suggests that the $20,134 in question be spread to all
customer classes. Apparently the Company also proposes
to do this since it is included in the “Intervenor
Funding” line on Company Exhibit No. 3 that is spread to
all customer classes.
Q. Are the rates shown in Column 9 of Staff
Exhibit Nos. 106, 107, 108 and 109 the energy rates that
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would result from the four proposals that you have
reviewed?
A. No. The rates shown in Column 9 of the
referenced Staff exhibits are average rates that are
calculated using all revenues normally received from the
class. The actual energy rate for each customer class,
which is the base energy rate plus any PCA adjustments,
is shown as the “effective rate” on each of the Company’s
rate schedules.
DSM RATE RIDER
Q. Given that electricity wholesale market prices
have returned to more normal ranges since the price spikes
that occurred in 2000 and 2001, what is Staff’s position
regarding Idaho Power’s proposal filed July 31, 2001 in
Case No. IPC-E-01-13 to implement additional conservation
efforts that would be funded through a 0.5% energy
surcharge?
A. The Staff position essentially remains the same
as when it filed its comments on September 20, 2001.
Although many of the conditions that caused the wholesale
electricity price spikes have now abated, some
conservation and other demand side management (DSM)
measures may be economically viable resources for meeting
customer demand. In addition, having a DSM funding
mechanism and programs in place allows a quicker ramp-up
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of DSM efforts in the event that wholesale electricity
prices increase dramatically in the future.
Q. In that case the Staff supported Idaho Power’s
proposed energy surcharge based on 0.5% of the Company’s
base revenue requirement. It was estimated that the
surcharge would provide approximately $2.6 million
annually for DSM measures. Does the Staff still support
this amount of DSM funding?
A. Yes.
Q. What DSM rate would result from 0.5% of base
revenue spread over normalized energy in this case?
A. The DSM rate rider would be 0.0192 ¢/kWh. The
actual calculation is:
(.005)(508,321,215)/(13,209,552)=0.192 $/MWh = 0.0192
¢/kWh.
Q. Do you propose to include the DSM rate rider in
rates as part of this filing?
A. Yes. Due to the extremely compressed
processing time associated with this case, the DSM rider
is not shown in the calculation of rates anywhere in this
filing.
Q. How do you propose the DSM rate rider be
incorporated into the Company’s rates?
A. The DSM rate rider can either be added to the
first year rates calculated in this case, causing smaller
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decreases or larger increases, or the tariff rider can be
added with an equivalent amount of true-up costs being
deferred to the following year. The latter would not
affect first year increases or decreases but would affect
rates throughout the remainder of the recovery period by
a relatively small amount.
With regard to Staff’s proposal in this case, I
recommend that $2,541,606 of additional PCA true-up costs
be deferred to the 2003 PCA year with interest. So doing
allows the customers to receive the full decrease
proposed by Staff for this PCA year.
Q. Does this conclude your direct testimony in
this proceeding?
A. Yes, it does.