20040325SAID Direct PUC Original Scan.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATEOF IDAHO.
IDAHO POWER COMPANY
DIRECT TESTIMONY
GREGORY W. SAID
CASE NO. IPC-O3-
please state your name and business address.
My name is Gregory W. Said and my business
address is 1221 West Idaho Street, Boise, Idaho.
By whom are you employed and in what
capaci ty?
I am employed by Idaho Power Company as the
Manager of Revenue Requirement in the Pricing and Regulatory
Services Department.
Please describe your educational background.
In May of 1975, I received a Bachelor of
Science Degree with honors from Boise State University.
1999, I attended the Public Utility Executives Course at the
University of Idaho.
Please describe your work experience with
Idaho Power Company.
I became employed by Idaho Power Company in
1980 as an analyst in the Resource Planning Department.
1985, the Company applied for a general revenue requirement
increase.I was the Company witness addressing power supply
expenses.
In August of 1989, after nine years in the
Resource Planning Department, I was offered and I accepted
position in the Company s Rate Department.Wi th the
Company s application for a temporary rate increase in 1992,
my responsibilities as a witness were expanded.While I
SAID, DI
Idaho Power Company
continued to be the Company witness concerning power supply
expenses, I also sponsored the Company s rate computations
and proposed tariff schedules in that case.
Because of my combined Resource Planning and
Rate Department experience, I was asked to design a Power
Cost Adjustment (PCA) which would impact customers ' rates
based upon changes in the Company s net power supply
expenses.I presented my recommendations to the Idaho
Public Utilities Commission in 1992 at which time the
Commission established the PCA as an annual adjustment to
the Company s rates.I have sponsored the Company s annual
PCA adjustment in each of the years 1996 through 2003.
In 1996, I was promoted to Director of
Revenue Requirement.At year-end 2002, I was promoted to
the senior management level of the Company.
What topics will you discuss in your
testimony in this proceeding?
I will discuss changes in loads and resources
since the Company s last general rate case and the impact of
those changes on the Company s power supply expenses.
will sponsor the exhibits that provide the basis for
determining the Company s normalized net power supply
expenses for ratemaking purposes.I will also discuss how
the new normalized power supply expenses impact future PCA
computations until the Company s next general rate case.
SAID, DI
Idaho Power Company
Please describe the change in the Company
system loads since the last general rate case, IPC-94-
The Company s 1993 annual normalized system
load used in the IPC-94-5 case was 14.5 million megawatt-
The Company s 2003 annual normalized systemhours (MWh).
load used in this case is 14.1 million MWh.The annual
system load served today is approximately the same as it was
ten years ago.
Over the last ten years, what changes in
loads combined to result in a 2003 annual system load that
~s so similar to the 1993 annual system load?
While there has been load growth wi thin most
customer classes, the Company has also experienced load
decline in a couple of distinct areas.Ten years ago, FMC
was Idaho Power s single largest customer with a load of 1.
million MWh per year.FMC, which later became known as
Astaris, discontinued operation leaving only a small
residual industrial load being served as a Schedule
Idaho Power also had some FERC jurisdictionalcustomer.
contract loads amounting to approximately 1.4 million MWh
that were intended to be served by surplus resources that
existed at that time, but were scheduled for discontinuance
as the Company s state jurisdictional loads grew to match
generation capability.As planned, those FERC
jurisdictional contracts have reached their conclusion.The
SAID, DI
Idaho Power Company
1 million megawatt-hour reduction in annual system loads
have been replaced by 2.7 million MWh of load growth wi thin
other customer classes.
Has the monthly shape of the annual load
changed in the last ten years?
Yes.The FMC contract as well as the
concluded FERC contracts that existed ten years ago provided
the Company with relatively consistent monthly loads that
were somewhat f la t throughout the year.The FMC load had an
interruptible component.Load growth wi thin the various
customer classes has tended to be much more seasonal and
dependen t upon weather.As a result of the loss of
relatively flat loads and the addition of non-interruptible
seasonal loads, the Company s Integrated Resource plan now
shows the need for summer peaking resources (June, July, and
August) and winter peaking resources (November and
December) .
Please define the term "power supply
expenses " as the Company and the Commission have used the
term historically.
The Company and the Commission have used the
term "power supply expenses " to refer to the sum of fuel
expenses (FERC accounts 501 and 547) and purchased power
expenses (FERC account 555) excluding PURPA qualifying
facilities (QF) expenses minus surplus sales revenues (FERC
SAID, DI
Idaho Power Company
account 447).For ra temaking purposes, QF expenses have
been quantified separately from other power supply expenses
and are treated as fixed inputs to power supply modeling
rather than variable outputs.
How would you expect power supply expenses to
be affected by the changes in loads, as you have described,
that resulted in approximately the same annual load, but
with seasonal shifts in loads and higher peak hour
requirements?
I would expect power supply expenses to rise
as a result of the seasonal and peak hour load shifts that
the Company has experienced over the last ten years.
Addi tional loads during the peak hours of the summer season
will need to be served by higher cost resources.
How have market prices of energy changed in
the last ten years?
Market prices for energy are generally higher
than market prices ten years ago.In the IPC-94-5 case it
was assumed that the highest monthly market price that the
Company might encounter would be $27 per MWh, which is
equivalent to 27 mills per kilowatt-hour (kWh) or 2.7 cents
per kwh.Ignoring the run-up in market prices that occurred
in the 2000-2001 time period, the Company has routinely s~en
market prices in the $40 to $50 per MWh price range during
the last two drought years.It has been quite some time
SAID, DI
Idaho Power Company
since the Company and the region experienced high water
conditions, but if high water was to occur, I would expect
that market prices would be significantly lower than the $40
to $50 per MWh range, but not as low as the $7 to $17 per
MWh range expected to accompany high water conditions ten
years ago.
What affect on power supply expenses would
you envision as a result of the upward movement in the
market price for energy?
As I have mentioned, I believe that a
relationship between hydro conditions and the market price
of energy still exists.When the Company and the regi
have abundant water, higher cost generating plants are not
required to satisfy Company or regional loads.The marginal
resource at such times is likely a low cost coal unit or
even on occasion hydro generation.As a resul t, the market
price for energy will fall to the incremental cost of the
marginal resource.Conversely, when the region is in a
drought condition, as is the current situation, higher cost
coal units and gas-fired units will be the marginal
resources influencing market prices.
As a resul t of the supply and demand
relationship, the Company will continue to encounter higher
market prices when both the Company and the region are
resource deficient and conversely will encounter lower
SAID, DI
Idaho Power Company
market prices when both the Company and the region have
abundant resources.Power supply expenses are reduced by
higher valued market sales, but are increased by higher
valued market purchases.I would expect overall upward
pressure on power supply expenses as a result of an upward
trend in market prices especially when considering the
seasonal and peak period load shifts that I discussed
earlier.
How have the fuel costs of the Company
coal-fired resources changed over the last ten years?
My response to this question includes known
and measurable changes to fuel costs, which I will discuss
later in my testimony.Including known and measurable
adjustments, the fuel cost for the Bridger units has
increased at an annual average rate of 1.0 percent per year
over the last ten years from $11.51 per MWh to $12.75 per
MWh.The fuel cost for the Boardman plant has increased at
an annual average rate of 0.5 percent per year over the last
ten years from $12.59 per MWh to $13.25 per MWh.Due to the
renegotiation and replacement of coal contracts for the
Valmy plant, the fuel cost for the Valmy units has decreased
by 31 percent from $21.19 per MWh in 1993 to $14.7 per MWh
in the test year 2003.
Due to the changes in the fuel costs of the
Company s coal-fired resources, what effect would you expect
SAID, DI
Idaho Power Company
to see wi th regard to power supply expenses?
With only modest increases in the fuel costs
for Bridger and Boardman and significant decreases in the
fuel cost for Valmy, I would expect some downward movement
Lower per uni t fuelin the Company s power supply expenses.
costs at Valmy will reduce the fuel expense at Valmy when it
is dispatched to serve system loads, but also will provide
for more frequent opportunities to sell Valmy surpluses into
the market.Both of these impacts serve to reduce net power
supply expenses.
Are there any resource addi tions that have
occurred in the last ten years that would reduce power
supply expenses?
Yes.The addition of any resource has the
effect of reducing power supply expenses.This results
because of economic dispatch principals.If additional
resources can be dispatched at costs lower than
alternatives, then dispatch of the new resources occurs thus
reducing power supply expenses.If the additional resource
cannot be dispatched at costs lower than al ternati ves,
addi tional power supply expense occurs.In the las t ten
years, the Company has added the Danskin gas-fired plant,
located at the Evander Andrews complex near Mountain Home,
Idaho and has also received energy from additional PURPA QF
proj ects.In 2004, the Company will acquire additional
SAID, DI
Idaho Power Company
generation from the PPL Montana Power Purchase Agreement
(PPA) and from a new QF proj ect called the Tiber Montana LLC
(Tiber) proj ect The costs of QF proj ects have not
historically been included in "power supply expenses " and
thus power supply expenses are reduced by new QF proj ects as
they reduce the need for resources that are reflected in
power supply expenses.
Have you supervised the preparation of power
supply modeling to reflect the changes in test year
characteristics that you have described in your testimony?
Yes.Under my supervision and at my request,
two power supply simulations representative of the test year
2003 under a variety of water conditions were prepared.The
first simulation is for the test year 2003 prior to known
and measurable power supply adjustments.This simulation
reflects the load changes, market price changes, fuel cost
changes and resource changes that have occurred in the last
ten years since the last test year 1993.The second
simulation modifies the first simulation of the test year to
reflect known and measurable power supply adjustments that I
will describe later in my testimony.As has been the case
in the past, the power supply modeling results reflect the
average power supply expenses associated with multiple hydro
conditions that are representative of the possible
circumstances the Company might encounter.Thi s year the
SAID, DI
Idaho Power Company
analyses include water conditions corresponding to years
1928 through 2003.The average of the expenses related to
each of the 76 water conditions represents the normalization
of power supply expenses.
Have you supervised the development of an
exhibi t showing the results of the power supply expense
normalization for test year 2003 prior to any known and
measurable power supply adjustments?
Yes. Exhibit 32 shows the results of the
power supply expense normalization prior to known and
Page 1 of Exhibit 32measurable power supply adjustments.
shows the summary results containing the 76-year average
power supply generation sources and expenses.Pages 2
through 77 contain results for each of the 76 individual
water conditions 1928 through 2003.
Please summarize the sources and disposition
of energy as shown on page 1 of Exhibit 32.
From the summary information contained on
page 1 of Exhibit 32 it can be seen that for the test year
2003, hydro generation supplies 8.8 million MWh while
thermal generation supplies 6.7 million MWh (Bridger 5.
Boardman 0.4, Valmy 1.3) from Company-owned generation
resources.Danskin, as a peaking plant, operates
intermi ttently, but offers significant contribution at
important times when resources and purchases are inadequate
SAID, DI
Idaho Power Company
Purchases of power come from threeto serve peak loads.
sources:market purchases, contract purchases other than QF
QF purchases are assumed at fixedand QF purchases.
normalized levels amounting to 783,635 MWh.Because the
fixed QF purchases are fixed inputs to power supply
modeling, they are not shown on the variable output summary,
however, when combined with the market and other contract
purchases, total purchases amount to 1.1 million MWh.As a
resul t, hydro generation contributes approximately
percent (8.8 / 16.6) of the generation mix, thermal
generation contributes approximately 40 percent (6.7 / 16.
and purchases contribute approximately 7 percent (1.1 /
Of the over 16.6 million MWh consumed, 14.1 million16.6) .
MWh are utilized for system loads while over 2.5 million MWh
are sold as surplus.
Please describe the expense and revenue
information associated with the normalized operation that
you have described as shown in Exhibit 32.
Exhibit 32 contains variable expense and
revenue information limited to FERC accounts 501, Fuel
(coal); 547, Fuel (gas); 555, Purchased Power; and 447
Sales for Resale. Hydro generation has no assumed fuel
Coal expenses of $89.9 million are comprised ofexpense.
Bridger at $63.7 million, Valmy at $20.8 million and
Gas expenses amount to $ 3 . 2Boardman at $5.4 million.
SAID, DI
Idaho Power Company
Purchased power expenses not including QF amountmillion.
to $10.6 million while surplus sales amount to $54.
million.Al together, net power supply expenses amount to
$49.6 million (89.9 + 3.2 + 10.6 - 54.1).
How do these power supply expenses compare to
the 1993 normalized amounts approved by the Commission
the conclusion of the IPC-94-5 case.
Fuel expenses (entirely coal related) for the
1993 normalized test year were $61.5 million.Purchased
power not including QF was $11.0 million and surplus sales
The Company had no gas fuelwere at a $24.5 million level.
expenses in 1993.Net power supply expenses were $48
While normalized surplus salesmillion (61.5 + 11 - 24.5).
revenues have increased by $29.6 million (54.1 - 24.5), fuel
costs have also increased by $31.6 million (89.9 + 3.2 -
61. 5) .While market prices have increased, reliance on
purchases has decreased, resulting in little change to non-
QF purchased power expenses.The net change in normalized
power supply expenses before known and measurable
adjustments is only a $1.9 million increase from 10 years
ago.
please describe the types of "known and
measurable " power supply adjustments that you recommend i~
thi s proceeding.
I propose two types of known and measurable
SAID, DI
Idaho Power Company
adjustments to normalized power supply expense computations;
(1) changes in purchased power contracts and (2) changes in
These adjustments have not only a direct impactfuel costs.
on specific expenses, but also have indirect impacts on the
Company s market purchase expenses and market sales
revenues.
Please describe your proposed changes to
purchased power contracts that will have a known and
measurable impact on the power supply expenses of the
Company.
I propose the inclusion of two power purchase
contracts that will become effective in 2004 as new rates
The first contract, as I mentioned earlierare implemented.
in my testimony, ~s a PURPA QF contract with Tiber Montana
LLC for the acquisition of 29,144 MWh at a cost of $1.
million.First deliveries of power from Tiber are scheduled
The second contract, also mentioned earlierfor May 2004.
in my testimony, is a PPA with PPL Montana for the purchase
of 99,360 MWh at a cost of $4.4 million.The first delivery
of power from PPL Montana is scheduled for June 2004.This
Commission has approved both of these contracts.
Please describe your proposed changes to fuel
costs that will have a known and measurable impact on power
supply expenses.
I have been informed by employees in the
SAID, DI
Idaho Power Company
Company s Power Supply Department that certain minor known
and measurable changes in coal prices will occur in 2004 as
a result of contract provisions, train lease agreements and
depreciation.A change of greater significance results from
the expiration of a long-term coal contract at Valmy.For
two plants, Boardman and Valmy the known and measurable
adjustments result in lower per unit fuel costs.Boardman
fuel costs drop from $13.66 per MWh to $13.25 per MWh. Valmy
fuel will drop from $16.2 per MWh to $14.7 per MWh.
Bridger, the fuel cost rises slightly from $12.65 per MWh to
$12.75 per kWh.
Have you supervised the development of an
exhibi t showing the results of the power supply expense
normalization when the known and measurable power supply
adjustments are included?
Yes. Exhibit 33 shows the results of the
power supply expense normalization once the known and
measurable power supply adjustments have been included.
Page 1 of Exhibit 33 shows the summary output containing the
76-year average power supply generation sources and
The following pages 2 through 77 show theexpenses.
individual water conditions 1928 through 2003 output as
those water conditions would impact the test year 2003.
Have you supervised the development of an
exhibit to quantify the extent to which the normalized power
SAID, DI
Idaho Power Company
supply expenses change as a result of including the known
and measurable adjustments you have proposed?
Exhibit 34 details the changes in bothYes.
normalized power supply expenses that exclude QF expenses
and also the change in QF expenses that result from known
and measurable adjustments.Net power supply expenses
decrease by $1.9 million as a result of changes to fuel
costs and additional power purchase contracts.QF expenses
increase by $1.2 million as a result of inclusion of the
Tiber contract.
How do base level PCA expenses differ from
test year power supply expenses?
Base level PCA expenses differ from test year
power supply expenses in two ways.First, base level PCA
expenses include QF expenses.Second, base level PCA
expenses are determined for an April through March time
frame rather than a calendar year.April represents the
beginning of the runoff period that provides the basis for
the PCA proj ection.
What are the 2003 test year normalized QF
expenses including the Tiber project?
Including the Tiber project, 2003 test year
normalized QF expenses amount to $46.4 million.
How do 2003 test year normalized QF expenses
compare to 1993 test year QF expenses?
SAID, DI
Idaho Power Company
$46.4 million are $12.1 million greater than the $34.
The 2003 test year normalized QF expenses of
million 1993 test year normalized QF expenses.However, the
$46.4 million value is $1.2 million less than the value used
in the current PCA proj ection formula.
test year 2003?
What is the base level of PCA expenses for
As I stated earlier in my testimony, the base
level of PCA expenses is the sum of the normalized power
In this case,supply expenses and normalized QF expenses.
normalized power supply expenses amount to $47.7 million and
normalized QF expenses amount to $46.4 million.The sum,
$94.1 million, represents the new base PCA expense level.
exhibit that shows the derivation of the appropriate new PCA
Have you directed the preparation of an
regression formula to be used for proj ecting the next year
PCA expenses?
Yes, I directed the preparation of Exhibit
to show the derivation of the new PCA regression formula.
Please describe Exhibit 35.
the page.
from 1 75.
Exhibit 35 consists of six columns at the top
Column one shows the number of the observation
Column 2 contains the PCA year corresponding
to each observation; observation 1 is 1928, observation 2 is
1929, and so on through observation 75, which is 2002.
SAID, DI
Idaho Power Company
Because the PCA year is for months April through March of
the following year, there are only 75 observations instead
of the 76 conditions represented in Exhibit 33.Column 3
contains the April through July runoff for each of the
observation years 1928 through 2002.Column 4 contains the
natural logarithm of the runoff value contained in Column
Column 5 contains the observed April through March annual
power supply expense based upon data from Exhibit 33, but
reflecting PCA totals rather than calendar year totals.
Finally, Column 6 contains the regression predicted value of
April through March annual power supply expenses.
To the right of the columns are summary output of
certain regression statistics (such as r-square) and formula
coefficients.
Please describe the new PCA regression
formula based upon Exhibit 35.
The basic PCA formula takes the following
Annual PCA expense = C1 - C2 * ln (Brownlee runoff) +form:
C3. The values of C1, C2 and C3 are constant with the only
variable being Brownlee runoff.The equation without C3 is
used to predict net power supply expenses and is the direct
result of the regression analysis contained in Exhibit 35.
The constant C1 represents the prediction of annual net
power supply expense that would occur if there was zero
April through July Brownlee runoff.The value of C1 is
SAID , DI
Idaho Power Company
In reality, the lowest April through July$1, 140,615,325.
Brownlee runoff contained in the observations is 1.
million acre-feet which occurred in the 1992 observation.
Because the regression provides a linear fit of a
non-linear transformation, the value of C2 is somewhat
difficult to explain.Observed Brownlee runoff data in
acre-feet is first transformed by the natural logarithm
function.For each unit increase in the natural logarithm
of the Brownlee runoff data the projection of annual power
supply expenses will be reduced by C2, which is $70,685,112.
The average natural logarithm of Brownlee runoff values,
based upon the observations contained in Exhibit 35, is
This value corresponds to a runoff of approximately15.46.
2 million acre-feet (e A 15.46 = 5,178,365 million acre-
Wi th a runoff of 5.2 million acre-feet and a naturalfeet) .
logari thm of 15.46, the proj ected net power supply expenses
would be $47,823,493 ($1,140,615,325 - $70,685,112 * 15.46).
An increase of 1 to the natural logarithm would result if
the runoff was approximately 14.1 million acre-feet
(In(14,076,256) equals 16.46 which equals 15.46 + 1).With
a runoff of 14,076,266 million acre-feet, the net power
supply expenses would be $70,685,112 less than $47 823,493
making the projection of power supply expenses a negative
$22,861,619 ($1,140,615,325 - $70,685,112 * 16.46).
The natural logarithms of observed Brownlee runoff
SAID, DI
Idaho Power Company
Theranged from 14.49 (1992 runoff) to 16.35 (1984 runoff).
difference, 1.86 (16.35 - 14.49), multiplied by $70,685,112
equals approximately $131.5 million, which represents the
change in projected power supply expenses from the highest
water case (1984) to the lowest water case (1992).
The value of C3 is $46,413,000, the normalized
Because the normalized expense for QF isexpense for QF.
quantified separately from net power supply expenses it is
added to net power supply expenses to determined the PCA
expenses.
What is the new PCA regression equation with
values inserted for the constants?
The new PCA regression equation is:
Annual PCA expense = $1,140,615,325
- $70,685,112 * ln (Brownlee runoff)
+ $46,413, 000.
In the past, has the PCA regression equation
also contained a constant related to FMC, later Astaris,
second block revenues?
Yes, FMC second block revenues were
previously treated as separately identified revenue that,
like surplus sales, reduced net PCA expenses.The FMC
constant is no longer appropriate due to the cancellation ,
the FMC contract.
How does the range in proj ected power supply
SAID , DI
Idaho Power Company
expenses from high condition to low condition resulting from
this regression equation compare to the range of projected
power supply expenses in the previous regression equation?
The predictions of power supply expenses
based upon the regression observations contained in the
previous regression analysis ranged from minus $9.9 million
(1984) to $112.4 million (1992), a range of $122.3 million.
Do you recommend any addi tional PCA
computational changes with the establishment of the new PCA
regression formula?
There are three PCA computationalYes.
factors that need to be updated as a result of the current
First, for PCA projectionreview of power supply expenses.
calculations, a new normalized base PCA rate can be
Second, a new Idaho jurisdictional percentagedetermined.
can be determined.Third a new expense adjustment rate to
be applied to load growth or decline can be determined.
Have you supervised the development of an
exhibi t to determine the PCA computational factors you have
just mentioned?
Yes, Exhibit 36 is a one-page exhibit
detailing the appropriate computation of the PCA factors I
have outlined.
What is the first computation shown on
Exhibi t 36?
SAID, DI
Idaho Power Company
The first computation recaps the normalized
PCA computation that I have discussed thoroughly in my
testimony.The new normalized PCA expenses for 2003 test
year amount to $94.1 million compared to the previous $73.
million value for the 1993 test year.
Please discuss the normalized Base PCA rate
computation contained in Exhibit 36.
First, I would point out that in my opinion,
the normalized Base PCA rate has been improperly determined
in the past.While expenses are incurred based upon loads,
they are recovered based upon sales.Historically, the
normalized Base PCA rate of 0.5238 was determined by
dividing the $73.1 million of normalized PCA expenses by the
normalized system firm load value.My recommendation for
the current computation of the normalized Base PCA rate is
that the $94.1 million normalized PCA expenses be divided by
the normalized system sales value of 12,863,484 MWh.The
resulting PCA base rate is 0.7315 cents per kWh.
Was a similar load/sales error previously
corrected by the Commission?
Yes, PCA true-up rate computations were
originally based upon Idaho jurisdictional firm loads rather
than Idaho jurisdictional firm sales levels.In 1996, the
Commission corrected that error in Order No. 26455.
Please discuss the Idaho jurisdictional
SAID, DI
Idaho Power Company
percentage computation contained in Exhibit 36.
The Idaho jurisdictional percentage is
der i ved by dividing the Idaho Jurisdictional firm load by
the sys tem firm load number.I mentioned earlier in my
tes timony ,the Company FERC Jur~sdictional contract loads
have been reduced by 1.4 million MWh while at the same time
Idaho jurisdictional loads have grown. As a result, Idaho
jurisdictional loads now represent 94.1 percent of the
Company s total load.
please discuss the Expense Adjustment rate to
be applied to load changes for PCA true-up computations.
When the PCA was established, the Commission
recognized that load growth would provide additional revenue
that would in part offset the corresponding additional power
supply expenses incurred to serve the additional load.The
revenues generated would be the result of rates designed to
recover the full embedded costs of serving existing
customers including generation costs, distribution costs,
transmission costs and other costs of the Company.However,
the true cost of serving additional customers is comprised
of a blend of new marginal costs incurred to serve new
customers and reduced embedded costs when existing
facilities allow for additional customers at zero or low
cost.The Commission determined that rates paid by new
customers would cover all additional costs including $16.
SAID, DI
Idaho Power Company
per MWh of PCA expenses that might occur to serve additional
load.The $16.84 per MWh credit was computed by averaging
the Boardman and Valmy fuel costs.Using the same
computational method the new expense adjustment rate for
load changes is $13.98 per MWh.
Based upon your understanding of Mr. Keen
testimony in this proceeding, do you believe the $13.98 per
MWh rate should be used as the new credit for load growth?
No.Mr. Keen pointed out that whether
looking at generation, distribution, or transmission, the
Company has little ability to serve additional customers
without investment in new facilities.In my opinion
revenues derived from additional customers served at
embedded rates will not be sufficient to recover both the
incremental costs of required new facilities and an amount
greater than the embedded cost of PCA expenses (the PCA base
rate) I believe it would be more appropriate to have
load growth credit based upon the normalized PCA base rate
of $7.30 per MWh (7.3 mills per kWh) .That is the portion
of customers ' rates that it is contemplated will cover base
PCA expenses.The remainder of customers ' rates cover the
other than PCA expenses that Mr. Keen has suggested will
grow at a significant pace in the coming years.
Do you have a non-computational
recommenda tion wi th regard to the PCA?
SAID , DI
Idaho Power Company
Mr. Gale, Ms. Brilz and I haveYes.
discussed Ms. Brilz ' recommendations in this proceeding to
create seasonal pricing that if accepted would create a
seasonal rate change on June 1 of each year.I f the PCA
rate change date were to continue to occur on May 16 of each
year, customers would see two rate changes wi thin 16 days.
If Ms. Brilz ' seasonal pricing recommendations are approved
then in order to eliminate back-to-back rate changes, I
recommend that the PCA recovery period be moved from a May
16 through May 15 period to a June 1 through May 31 time
No other changes to PCA time frames would beperiod.
required.PCA projection and true-up computations would
still be based upon an April 1 through March 31 time frame
and the Company would still file its PCA request by April 15
each year.
Does that conclude your testimony?
Yes.
SAID, DI
Idaho Power Company