HomeMy WebLinkAboutholm.pdf
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 1
Q. Please state your name and business address for
the record.
A. My name is Alden Holm. 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 (Commission) as a senior auditor in the
accounting section.
Q. What is your educational and professional
background?
A. I graduated from Boise State University in 1994
with a B.B.A. degree in Accounting. In 1998, I completed
a Masters Degree in Public Administration from Boise
State University. I have attended the annual regulatory
studies program sponsored by the National Association of
Regulatory Utilities Commissioners (NARUC) at Michigan
State University. Prior to joining the Commission Staff
in 2000, I worked for two years as an accountant at the
Boise Metro Chamber of Commerce and two years as an
accountant at Rocky Mountain Audio Visual, Inc.
Q. What is the purpose of your testimony in this
proceeding?
A. The purpose of my testimony is to describe
purchased power costs, surplus sales and new accounts in
the Power Cost Adjustment (PCA) mechanism. I will give
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 2
my analysis of the Company’s securitization proposal and
describe my recommended changes to the PCA carrying costs
proposed by Idaho Power Company (Idaho Power; Company).
Q. Please provide a summary of your
recommendations in this case.
A. I recommend that Idaho Power be allowed to
recover the majority of the costs included in its
IPC-E-02-3 Application. I have made four adjustments to
the amount Idaho Power requested. The first adjustment
is to remove the reduced revenues associated with the
Irrigation Load Reduction Program. Second, I removed
part of the expenses associated with the mobile diesel
generators. Third, I removed a portion of the Gas Fuel
Expenses for unused transportation expense. Finally, I
removed a capital expense from the Gas Fuel Expense
account.
I recommend that the Company not be allowed to
securitize the requested $172 million. I believe the
risks and expenses incurred by customers by securitizing
outweigh the benefits to the Company. I also recommend
that the Company not be allowed to change the interest
calculation for the normal PCA period. Instead, I
recommend that the Company be allowed to recover
reasonable interest costs on amounts that are deferred
for more than one year.
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 3
Purchased Power and Surplus Sales
Q. Did you audit the Company’s PCA filing?
A. Yes. I performed an extensive review of
purchased power expenses, surplus sales, and other actual
expenses and credits in addition to a review of all the
new accounts in the PCA this year.
Q. What did you find in regards to the purchased
power expenses and surplus sales?
A. With the exception of the real-time
transactions, I found that the sales and purchases had
been properly recorded according to Commission-authorized
methods.
Q. How were the power transactions priced?
A. There are typically three kinds of power
products that the Company bought or sold. They are term,
day ahead, and real-time. Each of these is priced in a
different manner.
Q. Please describe the manner that the term
purchases are priced and provide the audit results of the
term transactions.
A. The term transactions are transactions that
involve purchases or sales of more than one month’s worth
of power. Idaho Power sells surplus power when available
or purchases needed power from various parties as
determined by the Risk Management Committee. The
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 4
transactions are priced at the actual purchase or sale
price, and are not bought or sold to or through IDACORP
Energy.
During the PCA year, the Company entered into
several long-term transactions. Most of the transactions
were purchases. All the long-term purchases or sales
were authorized by the Risk Management Committee and
carried out in a timely manner. The Company did enter
into a few sell transactions longer than one month but
not longer than three months.
One transaction of note took place last year.
During November 2001, the Company took action to replace
some transactions that were in place with Enron when it
became apparent that Enron was no longer an appropriate
trading partner. The Risk Management Committee
authorized the replacement transactions, and they were
accomplished with little expense. These replacement
transactions removed the potential risk to Idaho Power
inherent in the Enron transactions.
Q. Please describe the day ahead transactions, the
manner that they are priced and the results of your audit
of those transactions.
A. The day ahead transactions are purchases and
sales that are for the next day’s use. They are
purchased entirely from the Company’s affiliate, IDACORP
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 5
Energy. The purchases and sales are priced at the Mid-C
index price for the day the energy is delivered with
additions or subtractions for the price of transmission.
The Commission previously approved and now requires this
pricing mechanism, and the Company carried it out
appropriately. In reviewing the day ahead purchases and
sales, I discovered no irregularities that required
Commission action.
Q. Please describe the real-time purchases and
sales, the manner that the real-time transactions are
priced and the results of your audit.
A. The real-time transactions are purchases or
sales carried out the day and hour the energy is needed
or becomes surplus. All real-time energy is purchased
from or sold to the Company’s affiliate, IDACORP Energy.
During the PCA year, the Company changed the way the
transactions were priced. From March 2001 through June
2001, the real-time transactions were priced at the
weighted average price of all real-time transactions on
the Idaho Power system. This method was approved by the
Commission, but currently is being reviewed by the
Federal Energy Regulatory Commission (FERC).
In July 2001, the FERC contacted the Company
and required a change in the way these transactions were
priced. The FERC proposed that real-time sales to Idaho
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 6
Power be priced at IDACORP Energy’s highest purchase
price in each hour and that the real-time purchases be
priced at the lowest sales price in each hour. At a
first glance, this pricing mechanism seems to provide a
reasonable method to price the energy. However, as
outlined in the Company’s testimony, it has proved to be
inappropriate.
As required by the FERC, the Company changed
the way the transactions were priced. However, Idaho
Power is working with the FERC to establish a more
appropriate pricing mechanism.
Q. Do you agree that the adjustment made by the
Company for real-time transactions is appropriate?
A. The adjustment for real-time transactions
provides customers the benefit of pricing based on
regional markets, which Idaho Power believes to be a more
appropriate pricing methodology than that required by the
FERC. I have reviewed the adjustment and agree it is
needed to reflect a more equitable transfer pricing
methodology for both the Company and its customers. The
adjustment results in $4,306,635.82 being credited to the
customers after jurisdictional sharing and interest.
Q. Do you have a recommendation for real-time
pricing?
A. I believe that real-time pricing should be
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 7
based on regional markets that reflect the cost of power
bought and sold in this area. The Company should
continue to work with the FERC to develop a more
reasonable transfer pricing methodology. In addition to
the method proposed by the Company, Staff would support
the FERC method if it included only transactions in the
Northwest and used the Mid-C Index when there are no
other relevant transactions in a particular hour. Once a
method is established with the FERC, it should be filed
with the Commission and evaluated by Staff.
Q. Did the Company follow the operational reports
and recommendations of the Risk Management Committee?
A. I reviewed the Risk Management Committee
meeting minutes to make sure the Company was operating in
the best interest of the ratepayers. During the PCA
year, the Company instituted a Risk Management Committee
for Idaho Power that was separate from the committee for
IDACORP.
At each regularly scheduled meeting, an
operational plan was presented to the committee. This
plan was prepared by Company personnel to show price
forecasts, energy deficiencies and surpluses, and other
factors that affect the Company’s ability to operate. I
reviewed these operating plans and found that they were
reasonably based on the best information available at the
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 8
time. The Risk Management Committee used the information
to take appropriate action. I found that the meetings
and actions were well documented and that the Company
followed up appropriately.
New Accounts in the PCA this Year
Q. What new accounts were included in the PCA this
year?
A. There were several new accounts in the PCA this
year. They included expenses relating to the Irrigation
Load Reduction Program and associated Reduced Revenues,
the Astaris Load Reduction Program, Mobile Generation
Costs, Gas Fuel Expenses relating to the Danskin facility
in Mountain Home, Mobile Home Metering shortfalls,
Intervenor funding from a variety of cases and a credit
associated with the IDACORP Energy contract.
Q. Would you describe each new account and make a
recommendation regarding the reasonableness of the
expenses?
A. Certainly. I will describe each account, give
the Commission order number that addressed the issue, and
make recommendations for recovery of the proposed
expenses and credits.
Irrigation Load Reduction Program - These
expenses relate to the Commission-approved program to pay
irrigators to reduce their consumption of energy. In
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 9
Order No. 28992, the Commission authorized the Company to
recover direct costs associated with the program. The
Company has identified, and I have verified
$73,941,839.42 of direct program costs. These costs
consist entirely of payments to irrigators in exchange
for reductions in irrigation loads. I found this amount
to be included in the PCA account appropriately.
Reduced Revenues – These revenues were
calculated by the Company to provide it with revenue it
claimed was lost when irrigators participated in the
Irrigation Load Reduction Program. As per the
Commission’s Order No. 28992, in Case No. IPC-E-01-34,
the recovery of reduced revenues was denied. Therefore,
I have removed the $15,146,639.32 associated with the
reduced revenues requested by the Company. See Staff
witness Hessing’s Exhibit No. 104, line 14, for the
monthly amounts.
Astaris Load Reduction Program – The Astaris
Load Reduction Program involved payments to Astaris for
reductions in the firm energy used by that company. In
Order No. 28992, the Commission authorized the inclusion
of costs incurred by the program. I have reviewed the
expenditures associated with the Astaris Load Reduction
Program and found that the Company has correctly included
expenses totaling $96,842,644.86 in the PCA account.
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 10
These amounts are subject to change pending an order
resolving issues related to the Astaris Load Reduction
Program rate reduction in Case No. IPC-E-01-43.
Mobile Generation Expenses - These expenses
are the result of the 25 diesel-powered generation units
that were leased during the months of May through October
2001. In May 2001, the Company filed an Application in
Case No. IPC-E-01-14 with the Commission seeking an
accounting order to authorize the recovery of expenses
associated with these generators. While the Commission
allowed the Company to flow the expenses through the PCA
accounts in Order No. 28837, it did not guarantee that
any specific amount would be recovered by Idaho Power.
During that case, the Commission Staff made a
recommendation that a portion of those expenses should
not be recovered. Staff’s position has not changed and I
recommend that the associated power supply costs be
reduced by $3,832,663. Staff’s comments in Case No.
IPC-E-01-14 are attached as Exhibit No. 101 to provide a
detailed analysis of the expenses and an explanation of
the adjustment to the mobile generators expense proposed
by Staff. The adjusted amounts are also shown in Staff
witness Hessing’s Exhibit No. 104, line 17.
Gas Fuel Expenses – These fuel expenses are the
result of the Danskin single-cycle natural gas fired
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 11
plant in Mountain Home, Idaho. In Case No. IPC-E-01-12,
the Company filed an Application requesting a Certificate
of Public Convenience and Necessity to include the
proposed plant in base rates. In addition, the Company
requested that the Commission allow the Company to
include the costs of the plant’s fuel, gas transportation
and storage for recovery through the existing Purchase
Cost Adjustment (PCA) mechanism. In Order No. 28773, the
Commission allowed Idaho Power to account for and recover
expenses associated with fuel and transportation in the
PCA mechanism.
I have reviewed the purchases of gas and
transportation and found that the Company has an
agreement with IGI Resources to supply it with fuel and
transportation to run the plant. The fuel is currently
purchased at a monthly index price and the Company is not
required to pay for the fuel if it is not needed. On the
other hand, the Company is required to pay for firm
transportation for the fuel whether or not it is used.
The agreement provides that IGI Resources will attempt to
market the unused transportation, but so far the Company
has received only two credits totaling $54,433.72. Staff
will continue to work with Idaho Power and IGI Resources
to insure that customers receive all potential benefits
from the unused portion of the Company’s firm
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 12
transportation purchases.
For the 2001-2002 PCA period, the Company
included $3,337,553.12 in the PCA account for Danskin
fuel expenses. I have made two adjustments to the amount
requested by the Company. First, the Company contracted
for firm transportation on April 11, 2001 with the
intention of finishing the plant in July 2001. However,
due to various delays, the plant did not operate until
September 25, 2001. Customers never had the opportunity
to benefit from the transportation expense incurred by
the Company during the months of July, August and most of
September. Because it was not used or useful during this
time period, I removed the $682,272.40 from the Company’s
PCA request.
The second adjustment relates to $419,054 that
the Company paid to Williams Gas Pipeline West
(Williams). This amount was characterized as a “Facility
Cost of Service Charge”. In essence, Williams built a
4,200 foot pipeline from its mainline to the Company’s
facility, a meter station and control equipment that
Idaho Power will use at it’s Danskin facility. The
facility charge recorded by Idaho Power in the PCA
account will pay for these items over the next 30 years.
Since this is a capital cost and not an annual gas
delivery cost, I believe that it should be considered in
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 13
a rate case and not be recovered in the PCA filing.
Consequently, I removed the $419,054 from the Company’s
request. Both adjustments are shown in Exhibit No. 104
on line 21.
From September 25, 2001 through March
2002, the Danskin plant produced 27,789 MWHs of energy.
The average variable fuel cost was $26.44 per MWH.
Mobile Home Metering Shortfalls – These
expenses result from modification of the three-tier rate
as it applies to master-metered mobile home parks. After
the last PCA rate change, the Commission became aware of
an inequity created by applying the tiered rates to
master-metered mobile home and RV parks. To address this
inequity, Commission Order No. 28753 authorized a
temporary subclass of Schedule 1 called “Schedule 3” so
that master-metered customers could be billed at a flat
rate. In addition to the new tariff, the Commission
allowed Idaho Power to include and pass on to customers
through the PCA account any revenue shortfall created by
the new tariff. The Company has calculated the amount to
be $106,528.87. I have reviewed the calculations and
found that they appear to be reasonable.
Intervenor Funding – In Case No. IPC-E-01-03,
the Idaho Irrigation Pumpers Association (IIPA) filed for
intervenor funding. The Commission granted $14,201.75 in
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 14
funding to the IIPA and required the Company to flow the
amounts through the PCA account with recovery from the
irrigation class.
In Case No. IPC-E-01-06, the Idaho Irrigation
Pumpers Association (IIPA) received $5,932.54 of
intervenor funding per Order No. 28770. The Commission
also allowed Idaho Power to recover that amount in the
Company’s next PCA filing and required the Company to
flow the amount through to the irrigation class.
In the Case Nos. IPC-E-01-7 and IPC-E-01-11,
the Land and Water Fund of the Rockies, Mary McGowen,
Idaho Rivers United and Idaho Rural Council (Intervenors)
petitioned the Commission for intervenor funding in the
amount of $9,661.84. Idaho Power did not object to the
intervenor funding, but it did seek authority to include
the amounts of any award as an expense in the PCA
mechanism. In Order No. 28756, the Commission granted
the total amount requested and allowed the amount to be
flowed through the PCA mechanism to all customer classes.
I reviewed the amounts included in the PCA
accounts and found that the $29,796.03 allowed above has
been properly included.
IDACORP Energy Credit – In Case No.
IPC-E-00-13, Idaho Power filed an Application with the
Commission requesting approval of an electricity supply
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 15
and management services agreement between Idaho Power and
an affiliate, IDACORP Energy (IE). This agreement
provided a mechanism to allow the Company to purchase
wholesale energy at published index prices from IE. One
benefit of the agreement was that a credit would flow
back to Idaho Power customers for the difference between
the contract charges and the amount reflected in the last
rate case. That amount was rounded to $2,000,000
annually. The payments were to commence on the date that
all commissions (Idaho, Oregon and the FERC) approved the
contract between Idaho Power and IDACORP Energy.
The Idaho Commission approved the stipulation
on December 19, 2000 in Order No. 28596. By July 2001,
all three commissions had approved the contract and Idaho
Power began booking PCA entries for the required credits.
For the PCA period of 2001-2002, Idaho Power booked
$1,500,000 for July 2001 through March 2002. These
credits were accounted for properly and should be
included in the PCA accounts to benefit all Idaho
customers.
Securitization and Interest Costs
Q. How does the Company’s securitization proposal
differ from the traditional PCA cost recovery?
A. First, the Company receives all of the $172
million of securitized power supply costs immediately.
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 16
Under the traditional PCA mechanism, Idaho Power must
wait to recover the deferred amounts over twelve months.
This shifts responsibility for carrying charges on the
deferred amounts during recovery from the Company to
customers. Rather than rates that reflect recovery of
power supply costs as required under the existing PCA
mechanism, the Company’s proposal results in rates that
reflect both power supply cost recovery and carrying
charges during the three-year recovery period.
Idaho Power states that financial analysts on
Wall Street would like the Company to have the amounts
securitized to guarantee recovery and improve cash flow
quickly. The Company believes that it could have a
positive impact on its ability to borrow. I believe that
the Commission can structure the recovery of deferred
costs to provide the recovery assurances these analysts
want by guaranteeing a fixed recovery period even if it
is greater than one year.
Q. Please describe the additional expenses to
customers associated with the securitization of deferred
costs.
A. There are some significant expenses associated
with the securitization of deferred power costs.
Expenses are incurred before the bonds are ever issued.
Idaho Power must pay to set up a Special Purpose Entity
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 17
(SPE) that will administer the bonds and proceeds. This
requires legal fees, accounting fees, and capital
funding. Then the Company must pay brokers, analysts and
others to administer the bonds. Finally, there are
interest amounts that are added to the outstanding
financed amounts. The Company estimates that the initial
fees to borrow $172 million dollars are up to $7 million
dollars. The ongoing servicing fees and trustee expenses
total approximately $1.5 million dollars and the interest
expense will be about $12 million dollars over three
years if the Company can finance the bonds at 4%. If the
interest rate is higher, the costs will be higher.
Q. Is there another risk to customers of
securitization?
A. Yes. Another risk in addition to the expenses
associated with securitization is that additional
deferred expenses may have to be recovered in future
cases. These costs may have to be recovered at the same
time customers are paying off the power supply bond.
This would add one cost recovery on top of another to
create a pancaking effect. It is difficult to predict
what the total rate may be.
Q. Is there a fairness issue associated with
securitization?
A. Yes. The longer the power supply cost recovery
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 18
is delayed, the greater the risk that the customers who
caused the deferred costs will avoid payment of an
equitable share.
Q. Did you review other securitization options
besides the one proposed by the Company?
A. Yes. I analyzed the costs of securitizing
amounts smaller than the amount proposed by the Company.
In the case of the lower amounts, it did not prove
economical to securitize because the fixed costs that
have to be spread over fewer dollars reduce the benefit
that securitization may have provided.
Q. Do you recommend securitization be accepted in
this case?
A. No. I do not support securitization in this
case. I believe the costs and risks to customers for
securitization outweigh the benefits to customers.
However, if the Commission decides to allow Idaho Power
to securitize a portion of the deferred expenses, it is
important that Staff be allowed to review the true up of
the recovery and expenses every year to verify that the
customers are paying the bond charges appropriately and
the Company is not overcollecting.
Q. Does Staff have alternatives to propose
regarding the recovery of PCA expenses?
A. Yes. Mr. Hessing has proposed three
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 19
alternatives for recovery of the PCA expenses. His
recommendation involves deferring a portion of the PCA
expenses for one year to allow a decrease while avoiding
some of the costs and risks associated with
securitization. Those alternatives are described in the
testimony of Staff witness Keith Hessing.
Carrying Costs of the PCA
Q. Do you accept the Company’s proposal to change
the interest rate on deferred costs to the authorized
rate of return on a going forward basis?
A. No, I do not. I believe the Company and
Commission have taken steps to reduce the amounts in the
deferral account going forward. For example, in Case No.
IPC-E-01-16, the Company and Staff are working with
interested parties to develop risk management guidelines
that should limit significant deferrals and market
exposure. The parties have discussed permitting the
Company to come to the Commission earlier in the PCA year
to review significant high cost transactions. The
Company is also considering changing its planning
practices from median water to a 70% of critical water
level. All of these steps should limit the size of
deferrals going forward.
Q. What interest rate do you recommend?
A. I do not recommend that the structure of the
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 20
PCA mechanism be modified to allow interest accrual on
amounts that are in rates. I recommend that the carrying
charges continue to be based on the customer deposit rate
that is set annually, currently at 4%.
Q. Has the Commission allowed another company to
change the interest rate on deferred amounts in recent
years?
A. No. In Case No. AVU-G-00-4, Avista applied to
change the interest rate calculation on its deferred
balances. The Commission did not change the rate and, in
fact, reiterated that the customer deposit rate was to be
used even though the deferrals were large and the
customer deposit rate did not cover the costs of
borrowing. In some years the allowed customer deposit
rate may be higher than the short-term debt rate and the
Company may recover more than its actual cost. When the
Commission allows utilities to recover interest on
deferrals, the customer deposit rate is the rate that is
generally used to calculate that interest.
Q. Should the Company be allowed to earn interest
on an amount held in the deferred account for a time
period longer than the traditional PCA recovery period?
A. If the normal PCA procedure of passing through
increases over a period of one year is not used, I agree
that the Company should be allowed to set aside the
IPC-E-02-3 STAFF
4/22/02
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. IPC-E-02-2 HOLM, A (Di) 21
IPC-E-02-3 STAFF
4/22/02
amount deferred in excess of one year and earn interest
on that amount. The rate should be equal to the larger
of its short-term debt rate or the customer deposit rate.
This will allow the Company to recover its reasonable
carrying costs during the additional deferral period.
Once the deferred amounts are placed into rates, no
additional carrying charges would accrue. Even using a
hypothetical rate of 7%, Mr. Hessing’s analysis shows
that Idaho Power customers will save $14.6 million over
the Company’s securitization proposal by paying off the
deferrals according to his recommended schedule.
Currently, Idaho Power’s short-term debt rate is lower
than the 4% customer deposit rate, but it varies monthly.
Q. Does this conclude your direct testimony in
this proceeding?
A. Yes, it does.