20061208Part II.pdf

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accommodating our schedule.So we will continue.I believe we
were finished with questions from the Commission.
Are there any other questions from the
Commission?
(No response.
COMMISSIONER SMITH:Then redirect, Mr.
Kline?
MR. KLINE:Thank you, Madame Chairman, I do
have a couple of redirect questions.
REDIRECT EXAMINATION
BY MR. KLINE:
Mr. Said, Mr. Woodbury asked you several questions
regarding Intermountain Gas Company s purchase gas adj ustment
mechanism.And in response to a question proposed by
Mr. Woodbury on that issue , you stated that Intermountain Gas
has a fuel adj ustment clause or a fuel adj ustment mechanism to
purchase gas adj ustment mechanism based on a unit cost.Could
you tell me about that a little bit?
Yes.My understanding of Intermountain Gas s power --
gas power adj ustment -- I'm not sure of the exact name.
Purchase gas adj ustment?
--
purchase gas adj ustment is based on a
dollar-per-therm, I believe, basis.And so it is a rate per
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consumption of power that's used by customers.And the
mechanism looks at the proj ected cost on a per unit basis
compared to an existing component of rate that is also on a per
unit of consumption basis.
If Idaho Power Company s power cost adj ustment
mechanism had been established as a unit cost as the Company
originally proposed, would the Company have an issue today
regarding the load growth adj ustment mechanism?
I don t believe so, no.The Company s original
proposal was on a per-unit basis.And that was the reason that
we didn t feel a load growth adj ustment was required.And it
was only when the Commission adopted a power cost adjustment
based on dollars rather than a per unit cost that a load growth
adj ustment rate became appropriate.
Does Intermountain Gas Company s purchase gas
adj ustment allow Intermountain Gas to recover its
prudently-incurred commodity or fuel expenses associated with
load growth between rate cases?
Yes , it does.
Commissioner Hansen asked you a couple of questions
regarding the perception of customers when the power cost
And he indicated that customers kindadj ustment occurs in June.
of expect to pay more when there is a drought or when power
costs are higher.And then in low water conditions
--
I mean,
they expect to see that.What about the situation where you
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have got
--
well , could you comment on that part of his
questions?
Yes.Commissioner Hansen s question then got more
specific and suggested that perhaps in a high water condition
there might arise a circumstance where customers would be
expecting a rate decrease and instead would see a rate increase
associated with the Company s proposal.In reality, I think the
opposi te end of the spectrum is the more likely case that in a
drought condition when the Company is experiencing high power
supply expenses, Mr. Hessing s recommendation of a high load
growth adjustment rate could potentially remove enough of those
expenses such that customers were seeing a decrease in rates at
a time when power supply costs were their highest.I think
that's the more likely scenario when looking at the ends of the
spectrum.
Mr. Eddie, also on cross-examination , addressed a
question to you regarding whether acceptance of the methodology
that Idaho Power Company is proposing in this case would make it
more attractive for the Company to encourage load growth.
Idaho Power , under your proposal , is only being compensated for
the costs incurred in the PCA, would Idaho Power have an
incentive as he has discussed?
No.That's the maj or point that, I think, I was
trying to make in response to Mr. Eddie is that the best that
the Company can possibly do even under the Company s proposal
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is to recover the costs that it actually incurred to serve the
new customer; and, therefore, there is no real incentive to go
out and sell additional killowatt hours because the best we can
do is recover our expenses.We are not going to recover more
dollars than the cost that actually occurred.
MR. KLINE:That's it.
COMMISSIONER SMITH:Thank you, Mr. Kl ine .
And thank you, Mr. Said.
I don t know
--
was there any agreement on
the part of the parties as to who needed to go next or any time
constraints on any of the witnesses?
MR. KLINE:No.
Okay.Then looks go toCOMMISSIONER SMITH:
the Industrial Customers.
MR. THOMPSON:Thank you.
The Industrial Customers of Idaho Power
would like to call Dr. Don Reading to the stand.
DR. DON READING,
produced as a witness as the instance of the Joint Applicants,
being first duly sworn , was examined and testified as follows:
DIRECT EXAMINATION:
BY MR. THOMPSON:
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Are you the same Dr. Don Reading who caused direct
testimony with Exhibit No. 201 , your qualifications, to be filed
in this proceeding?
Yes.
Was that pre-filed direct testimony and attached
exhibi t prepared by you or under your supervision?
Yes.
Do you have any corrections or additions to make to
your testimony and/or exhibits at this time?
Yes, I do.I have a couple of exhibits that support
some calculations that are not in the record that need to be in
the record.
Okay.
MR. RICHARDSON:Madam Chair, may I have
your permission to approach the witness and Commissioners and
hand out exhibits to the parties?
COMMISSIONER SMITH:Yes.
(MR. RICHARDSON) The first exhibit is entitled on the
cover sheet Idaho Power Company s Response to Commission Stats
Request for Production No., indicate Case IPC-E-0608.
And if that could be marked as Exhibit No.
205 in the record.
COMMISSIONER SMITH:Thank you.We will
mark this as Exhibit 205.
MR. RICHARDSON:And then this second
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exhibit is titled, Said Exhibit 20, filed in Case No.
IPC-E-05-28, page 1 of 79.And I'd ask that it be marked as
Exhibit 206 for identification in the record.
COMMISSIONER SMITH:Thank you.Exhibi t 206
will be marked for identification.
(MR. THOMPSON) Mr. Reading, are there any other
additions or corrections that you would like to make?
No, there are not.
Thank you.Wi th those additions, if I were to ask you
the same questions today that you were asked in your pre-filed
direct testimony, would your answers be the same?
Yes.
Thank you.
MR. RICHARDSON:With that, Madame Chair , I
would move that the pre-filed direct testimony of Dr. Reading be
spread upon the record in this matter as if it were read in full
and Exhibit 201 and 205 and 206 be identified for the record.
COMMISSIONER SMITH:Wi thout obj ection it is
so ordered.
(The pre-filed direct and rebuttal
examination of Dr. Reading has been spread upon the record.
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PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Don Reading and my business address is Ben Johnson
Associates, 6070 Hill Road, Boise, Idaho.
WHAT IS YOUR OCCUPATION?
I am a principal with Ben Johnson Associates.
HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR
QUALIFICATIONS AND BACKGROUND?
Yes. Exhibit No. 201 serves that purpose.
ARE YOU SPONSORING ANY OTHER EXHIBITS WITH THIS
TESTIMONY?
No.
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
CASE NO. IPC-O6-08?
I have been retained by the Industrial Customers of Idaho Power (ICIP)
to review the load growth adjustment rate used in the true-up portion of the Power Cost
Adjustment (PCA) methodology.
DR. READING, COULD YOU PLEASE GIVE AN OVERVIEW
OF THE POLICY DECISION PRESENTED IN THIS CASE FOR THE
COMMISSION?
Yes. While the specific calculations and applications of the load growth
adjustment rate are complex, the policy choice for the Commission is straightforward and
easily defined. The basic question being presented to the Commission is whether the
calculation of the load growth adjustment rate should be changed from a marginal basis to
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an average basis. The complexity of the mechanism being discussed in the case can tend
to cloud this central issue. All parties agree, however, that the load growth adjustment
rate is currently based on a marginal analysis. Idaho Power is asking that this be
fundamentally changed, and is advocating that the load growth adjustment be calculated
on an average- or embedded-cost basis. Other PCA-related issues are not a part of this
docket.
SINCE THE LOAD GROWTH ADJUSTMENT IS PART OF THE
POWER COST ADJUSTMENT, COULD YOU FIRST GIVE A BRIEF HISTORY
WASIDAHOPOWER'COST ADJUSTMENTHOWPOWER
EST ABLISHED?
In 1981 , the Idaho Commission approved setting power supply costs
based on multiple hydro years, or normalized conditions. See Case No. U-1006-185. It
was assumed this approach would make the Company whole in the long run. However
severe droughts followed which caused the Company to file for drought surcharges due to
deteriorated hydro conditions. The Commission found this method of dealing with
volatile hydro conditions to be undesirable, and the PCA was subsequently developed and
implemented.
In its Order implementing the PCA the Commission explained
Since we adopted the current system of normalization, Idaho Power
has requested and received two separate drought related surcharges. . . .
We find that the current system of normalizing power supply costs and
granting Idaho Power a surcharge during drought years is defective
because it is unpredictable and ratepayers do not receive any rate reduction
during high water years. . . . (W)hile ratepayers are subject to a surcharge
in poor years, they currently do not receive any reduction in rates in high
water years leading most customer groups to believe that the current
system works to their disadvantage when hydro conditions are good. The
PCA we adopt addresses this concern and will produce consumer benefit
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in the form of lower rates during years of favorable stream flows. (IPUC
Order No. 24806, Case No. IPC-92-, March 1993 , pgs. 4 5).
Thus, the PCA mechanism was established as a result of dissatisfaction on the part
of the Company s customers and the Commission itself. Its purpose was to create a
system where both Idaho Power and its customers would share in the costs and benefits of
changes in power supply costs, caused primarily by variations in stream flows, that occur
between general rate filings. The PCA looks at year-to-year changes in power supply
costs caused primarily by changing water conditions. It is first set on a forward looking
basis, then trued up after loads and power costs are known.
BY ESTABLISHING A PCA BASED ON ANNUAL CHANGES IN
STREAM FLOWS, AND HENCE POWER SUPPLY COSTS, WAS THE
COMMISSION ABANDONING THE APPROACH IT TOOK IN 1981 OF
NORMALIZING POWER SUPPLY COSTS BASED ON MULTIPLE HYDRO
YEARS?
No. The Commission stated expressly that it viewed the normalization
procedure (basing power supply costs on multiple hydro years) as a valuable tool in
setting rates in a general rate case. The PCA mechanism, on the other hand, is a limited
exception to the usual reliance on normalization procedure. In adopting the PCA, the
Commission explained the limited departure from the multi-year normalization procedure
that the PCA represents. The Commission stated
We find, therefore, that it is in the best interests of ratepayers and
shareholders alike to adopt a PCA for Idaho Power. We emphasize
however, that our decision is limited to the unique circumstances of Idaho
Power s highly variable power supply costs. While it is difficult for a
normalization process to capture these large annual changes, we continue
to believe that normalization is a valuable ratemaking methodology for
other types of expenses and revenues. Nothing in this Order should be
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construed to the contrary. (IPUC Order No. 24806, pg. 5) (emphasis
added).
Later, in the same order, the Commission explained the PCA was not intended to
substitute for normal prudency review of costs incurred by Idaho Power to serve load
growth. The Commission explained
We recognize and support the Company s right to recover costs
associated with prudent plant additions. Our decision to not allow PCA
mechanism to recover costs to offset legitimate plant costs caused by load
growth in no way prevents the Company from recovering these costs in
traditional ratemaking proceedings. PCA is not intended to replace the
prudency review process inherent in general rate case. (IPUC Order No.
24806, pg.20) (emphasis added).
Thus, although the Commission believed it appropriate to allow a PCA to modify
rates based on large annual changes in power supply costs due to variability in fuel costs
(primarily hydro variations), it did not believe that the PCA should become a mechanism
through which Idaho Power could avoid traditional ratemaking review of its other costs
including costs incurred in order to serve load growth. The PCA is meant to adjust for
the change (up or down) in power supply costs each year from those set between rate
cases.
The cost of generation used to serve additional load, that is, load in addition to the
load accounted for in the PCA year, is different from the cost of generation established in
a general rate case. It thus represents a different type of cost than that for which the PCA
was intended to provide automatic recovery in rates.
COULD YOU EXPLAIN BRIEFLY WHAT FUNCTION THE
LOAD GROWTH ADJUSTMENT SERVES IN THE PCA MECHANISM?
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A. The load growth adjustment was implemented by the Commission to prevent the
Company from double-recovering certain costs under the PCA. (IPUC Order No. 24806).
The load growth adjustment factor is used to adjust for power supply costs that the
Company has already recovered from customers through their rates. Although new
customers (or other new loads) add to Idaho Power s power supply costs over and above
those established through rate case normalization procedures, these new customers (or
other increased loads) pay Idaho Power s rates for the power they receive. Allowing the
Company to automatically recover in the PCA the full costs of serving new load would
therefore result in an over-recovery by the Company. In other words, if the PCA were not
adjusted to take into account the revenues the Company receives from new customers or
increased load, the Company would again receive them automatically in the PCA
higher power supply costs.
Additionally, since this load growth is on the margin, Idaho Power incurs marginal
power generation costs to serve the load. The load growth adjustment also serves the
purpose of preventing the Company from automatically recovering the marginal costs of
serving new load. As stated above, the marginal costs of serving new load are properly
subjected to prudency review in general rate proceedings.
HOW DOES THE PCA ADJUST FOR THE POTENTIAL OVER-
RECOVERY OF POWER SUPPLY COSTS?
Each year the PCA surcharge is established based on normalized
Company loads and forecast stream flow conditions that are a significant driver of power
supply costs. Because these are simply projections, actual power supply costs for the year
will differ from the forecast. The difference between actual and projected power supply
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costs are 'trued-up,' and then become part of the coming year s PCA rate. During the
true-up step, the load growth adjustment rate is multiplied by the difference between
actual MWh sales and those used as base loads in the PCA original calculation. This
amount is then subtracted from the costs that are to be recovered by the PCA surcharge.
When the Company s loads are growing, the load growth adjustment results in a
reduction of the PCA surcharge. This prevents the PCA from recovering an amount that
would represent a double-recovery of the revenues it receives from new loads, and from
collecting an amount that would automatically compensate the Company for the marginal
costs it incurs to meet new loads. If the Company s loads decrease between the time the
PCA is established and the time of the true-up, the load growth adjustment would
increase the PCA rate.
WASTHISCOMPLEXADJUSTMENTTHAT
IMPLEMENTED BY THE COMMISSION IN ESTABLISHING THE PCA
SURCHARGE. COULD YOU GIVE AN EXAMPLE TO HELP CLARIFY YOUR
EXPLANATION?
As stated above, the PCA is set based on assumptions of stream flow
conditions and normalized loads.If all of the assumptions that go into the PCA
calculations turned out to perfectly match actual conditions and costs, then forecasted
power supply costs and actual power supply costs would be exactly the same. However
if over the course of the PCA year the Company had experienced load growth or decline
such that actual loads differed from what was assumed in the original PCA calculation
then actual costs will not match forecasted costs. If loads have increased above forecasts
then the costs of serving those loads would have been incurred by the Company and
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power supply costs will be higher than projected. Allowing the Company to collect all of
those increased costs through the next year s PCA, however, would result in a double
recovery by the Company of significant costs because the new customers (or other
sources of increased loads) that came onto the system have already paid the Company
rates for the power they have received. Without a load growth adjustment, the extra
revenues received due to the increased load would not be accounted for, and the
Company would simply collect its increased costs, without an offset for the revenues
produced by the increased load.
Also, in addition to preventing a double-recovery by the Company of the costs
associated with new load, the load growth adjustment prevents the Company from
automatically recovering the marginal costs of serving new load.The load growth
adjustment currently removes from the PCA the marginal costs of serving new load. If it
did not remove these costs, the Company would automatically get them through the PCA
and the Commission and Idaho Power s customers would lose the opportunity to be
involved in a review of the prudency of those costs.
IS IT TRUE NONE OF THE PARTIES ARE REQUESTING THE
ELIMINATION OF THE LOAD GROWTH ADJUSTMENT, BUT ARE
RATHER PRESENTING DIFFERING METHODS OF HOW IT SHOULD BE
DETERMINED?
Yes.As stated above, the issue before the Commission in this
proceeding is simply whether the load growth adjustment should be calculated based on
the marginal costs of serving new load, or whether it should be calculated based on the
embedded cost of serving load. Throughout the history of the PCA, the load growth
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adjustment has been based on marginal costs of serving new load. However, Idaho Power
is now advocating that it should be based on embedded costs.
WHAT ARE SOME OF THE REASONS THE IDAHO
COMMISSION RELIED ON WHEN IT ORIGINALLY ADOPTED THE USE OF
MARGINAL COSTS RATHER THAN AVERAGE COSTS IN DETERMINING
THE LOAD GROWTH ADJUSTMENT?
In its Order establishing the PCA mechanism for Idaho Power, the
Commission agreed with the Commission Staff s recommendation that the load growth
adjustment method be based on marginal costs. The Commission stated
We find that the net power supply costs associated with serving
differences in load between normal and actual should be removed from the
PCA. We adopt the method proposed by the Staff for making this
adjustment; it was the only method proposed. We agree with Staff that
Idaho Power s proposal unduly broadens the scope ofthis proceeding,
which is simply to devise a mechanism for the recovery of power supply
costs that include the sum of fuel costs, non-firm energy purchases and
CSPP costs less revenues from non-firm energy sales and FMC secondary
sales. Idaho Power s proposed PCA allows it to double recover fuel costs
associated with load growth which, essentially, offsets the cost of
constructing additional plant. (IPUC Order No. 24806, p 20).
IN HIS TESTIMONY IN THIS CASE, COMPANY WITNESS MR.
SAID IMPLIES THAT THE COMPANY NEVER WEIGHED IN ON WHETHER
THE LOAD GROWTH ADJUSTMENT SHOULD BE BASED ON THE
MARGINAL OR EMBEDDED COSTS OF SERVING GROWTH.DO YOU
BELIEVE THAT THE COMMISSION FAILED TO CONSIDER WHETHER
THE LOAD GROWTH ADJUSTMENT SHOULD IN FACT BE BASED ON
EMBEDDED COSTS RATHER THAN MARGINAL?
No. The full Question and Answer you refer to by Mr. Said is:
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Q. In the original PCA case, did the Company state a position
regarding the appropriateness of the Staff proposed load growth
adjustment rate?
A. No. At the time the PCA was created, the Staff s proposed
marginal load growth adjustment rate seemed like a small detail compared
to the larger goal of establishing a peA mechanism. It was only after some
time had passed that the Company came to realize the impacts of the
penalty introduced by setting the load growth adjustment at a marginal
level rather than an embedded level. (Direct Testimony of Said, IPC- E-
06-p. 11).
However an examination of the record in the original PCA case, as pointed out
below, shows that the Commission had an ample opportunity to consider, and decide, on
the record that the load growth adjustment should not be based upon embedded average
costs. In the original PCA Case the Commission agreed with the marginal approach
proposed by Staff. In the current docket the Commission is being asked to re-decide the
same issue again. The Commission agreed with its Staff in the original PCA proceeding
by ruling that the load growth adjustment should be based on the marginal costs of
serving new load. The Commission rejected Idaho Power s proposed approach. It
refused to allow the Company to automatically collect the costs it incurs in serving load
growth.
In surrebuttal testimony in the case establishing the PCA (IPC-92-25), Staff
witness Mr. Hessing responded to an example presented by the Company witness Mr.
Said of the types of costs Idaho Power incurs in serving load growth. In that example the
Company assumed to serve a base load of 100 000 MWh at a cost of $300 000, or $3 per
MWh. The Company went on to assume that an increase in load of 10 000 MWh would
cost an additional $30 000 , meaning the costs for serving new customers would remain at
$3 per MWh. (Said Rebuttal Testimony, IPC-92-, p. 19). Staff witness Hessing
answered this Company example by stating,
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Although his example is technically possible it is far from normal. It
requires that the Company s resources be operated in an uneconomic
manner. The example assumes that 10 000 MWh of additional energy can
be supplied in a given situation for the same average cost as the initial
100 000 MWh. Since load growth is served from the marginal resource it
will be served at a higher incremental cost than average cost. Thus Mr.
Said's example which demonstrates a $3 MWh additional and a $3 per
MWh incremental cost is at best an anomaly. (Hessing Surrebuttal, IPe-
92-, p. 5).
Thus, Staff made clear its position that Idaho Power incurs higher marginal costs in
order to serve load growth and that the load growth adjustment should be based on those
marginal costs.
Additionally, the record shows that Idaho Power advocated for a PCA that would
allow it to automatically collect the marginal costs it incurs in serving new loads. In his
Rebuttal Testimony, Idaho Power witness Gail argued that Staff failed to include in the
PCA a host of other factors that contribute to the costs of serving new load other than fuel
costs.
With increasing economic prosperity comes increasing employment
and increasing population. Load growth associated with increasing
population causes other costs than just variable energy costs. Load growth
of this type means new services, line extensions, meters, meter reading,
customer service activity, contract construction, and other miscellaneous
costs which vary with additional customers. Witness Hessing fails to
consider these other incremental costs in his analysis and his
recommendation to exclude the power supply expenses associated with
load growth from the PCA. (Gail Rebuttal, IPe-92-, p. 14).
Thus, as demonstrated by the above quotes, Idaho Power was advocating for a peA
that allowed it to automatically recover the costs of serving new load. Commission Staff
on the other hand, argued that the marginal costs of serving new load should be removed
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from the PCA, and that those costs were more appropriately part of a general rate
proceeding.
After reviewing the positions of both the Commission Staff and the Company, this
Commission accepted the marginal approach proposed by its staff. The Commission
explained in its order adopting the PCA
Our decision to not allow a PCA mechanism to recover costs to
offset legitimate plant costs caused by load growth in no way prevents the
Company from recovering these costs in traditional ratemaking
proceedings. A PCA is not intended to replace the prudency review
process inherent in general rate case. (IPUC Order 24806
, pg.
emphasis added).
HAVE YOU REVIEWED THE RECORD AND PARTIES'
POSITIONS IN THE ORIGINAL PCA DOCKET?
Yes. I have reviewed the record and the positions taken by Idaho Power
and the Commission s Staff in the original docket.
WHAT, IF ANYTHING, HAS CHANGED SINCE THAT TIME
SUCH THAT THE COMMISSION SHOULD REVERSE ITSELF ON THIS
ISSUE?
Nothing.
WHERE DO YOU STAND ON SETTING THE LOAD GROWTH
ADJUSTMENT ON A MARGINAL OR AVERAGE BASIS?
I agree with the Idaho Commission s decision in the original PCA case
to set the load growth adjustment based on the marginal costs of serving new load. The
Company s arguments presented in this docket simply rehash an issue settled by the
Commission some time ago, when it established the PCA. The underlying reasons for
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setting the load growth adjustment based on the marginal costs of serving new load
remain sound and compelling. The Company s proposal in this proceeding to set the load
growth adjustment based on an average, embedded-cost basis would fundamentally
change the nature of the PCA.
WHY IS IT APPROPRIATE TO USE THE MARGINAL
APPROACH FOR THE LOAD GROWTH ADJUSTMENT RATE?
U sing a load growth adjustment based on the marginal cost of serving
new load is the most appropriate method to prevent the Company from automatically
recovering too much from the Company s customers under the PCA. Using a marginal
cost-based load growth adjustment allows the PCA to achieve its intended purposes, and
preserves the prudency review of other costs incurred by the Company to serve new load
growth for general rate proceedings. The Commission can best evaluate the prudency of
load growth costs in a general rate case, before they are charged to customers.
The Company claims in its Application that there is a "mismatch" caused in using
the marginal approach for the load growth adjustment because it collects costs at the
embedded rate. However, new loads are served by the marginal units in the Company
resource stack. These resources are higher cost resources and push up the power supply
costs at a greater rate than the average of all the Company s resources. This increment is
then reflected in higher power supply costs at the end of the PCA period. It is not a
mismatch, then, to use the Company s marginal fuel costs to offset these higher power
supply expenses incurred to serve load growth. Contrary to the Company s position, it is
important for the load growth adjustment to be based on marginal costs of serving new
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load, so that it can prevent the Company s automatic recouping of those marginal costs
without the appropriate prudence review.
The Commission established the PCA to account only for annual changes in power
costs, caused primarily by stream flow variations. The Commission has clearly stated
however, that other costs that may be associated with serving additional load should be
adjudicated in a general rate case and not through the PCA mechanism. I agree with the
Commission s original position on this issue. The PCA should not become a mechanism
through which Idaho Power can automatically recover the costs it incurs in serving new
growth. Those costs should be reviewed in a general rate proceeding.
PROBLEMS RAISEDARETHEREANYOTHER
ALLOWING THE PCA TO BE USED BY IDAHO POWER TO RECOVER
COSTS ASSOCIATED WITH LOAD GROWTH?
Yes. The PCA moves on a very fast track. It is typically filed in late
April or early May, with an effective date of June 1 st. There is not enough time to do a
thorough prudency review in that short of a time. We would, in effect, have to turn each
PCA into a general rate case, which would defeat the purpose of a PCA.
WHAT IS THE CURRENT LOAD GROWTH ADJUSTMENT
RATE?
The current load growth adjustment rate is $16.84 per MWh.
WHAT VALUE FOR THE LOAD GROWTH ADJUSTMENT
RATE ARE OTHER PARTIES TO THIS PROCEEDING PROPOSING?
A. Idaho Power is proposing that it be decreased to $6.81 per MWh. In the last
general rate case that was fully presented to the Commission (IPC-03-13), Commission
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Staff advocated that it should be raised to $29.41 per MWh. The Staff s position has
likely changed to reflect higher current marginal costs of serving new load.
WHAT VALUE OF LOAD GROWTH ADJUSTMENT ARE YOU
ADVOCATING?
As stated above, I believe the marginal approach, which is consistent
with the Commission s orders, is the correct method to use. Staff, in its calculation, uses
the AURORA power supply model and increases loads 10MWa for each hour of the year
and then compares that to fuel costs for the base amount and finds the incremental fuel
costs. I do not have the AURORA model available and cannot verify its algorithms or
input assumptions. However, there are several proxies that can be found that indicate
marginal fuel costs for Idaho Power.
COULD YOU PLEASE OUTLINE THOSE PROXY MEASURES
THAT COULD BE USED AS ESTIMATES FOR MARGINAL FUEL COSTS FOR
IDAHO POWER?
There are three that come immediately to mind. First, one could use the
marginal cost study that the Company uses in general rate cases for rate design, which
finds marginal fuel costs. Second, the AURORA model is used to calculate PURP A rates
paid to Qualifying Facilities (QFs). The energy portion of the current PURPA rate can be
used because it represents marginal fuel costs for the Company. Third, the Company
fuel costs of the Company s newest resource, Bennett Mountain, could be used under the
assumption that its latest resource is its marginal unit.
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COULD YOU PROVIDE THE VALUES FOR EACH OF THESE
PROXY MEASURES OF MARGINAL OR INCREMENTAL FUEL COSTS FOR
IDAHO POWER?
The Company provided its 2005 Marginal Cost Study in Case IPC-05-
28 (Brilz workpapers). On Schedule 1 of that study the Company lists "Marginal Energy
Cost at Service Level: Power Supply" with an annual value of $40.96 per MWh.
According to the text of the document, the Company s marginal cost analysis follows the
concept and design from the National Economic Research Association (NERA) with
input values primarily from their 2004 IRP.
The energy portion ofthe current QF rates were set in IPC-04-25. The adjustable
portion of that rate for Idaho Power was set at $36.42 per MWh. This value is derived by
using the cost of a surrogate avoided plant - in this case a gas combined cycle combustion
turbine. The Commission has found this type of plant to be the Company s avoided
resource. Therefore its fuel costs are a reasonable proxy for marginal fuel for the
Company.
For costs of Bennett Mountain, the Commission could refer to page 403 of Idaho
Power s 2005 FERC Form 1 , which lists the costs and output for its Bennett Mountain
plant over the course of2005. Line 12 shows generation from the facility of 56 222 000
Kwh and line 20 lists the fuel expense at $2 744 349. Dividing output by fuel expense
yields 4.881 cents per Kwh or $48.81 per MWh. Since Bennett Mountain is the last
resource brought on line by Idaho Power, it is its marginal unit and its fuel costs are the
Company s marginal fuel cost.
Reading (Di)
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Marginal fuel costs found for these three proxies are relatively close and range
from $36.42 to $48.81 per MWh. They are, of course, very different from the $6.
advocated by the Company based on an embedded approach. What is clear is that the
Company s marginal fuel costs to serve new load centers around $40 per MWh. Without
the use of the AURORA model, I would recommend the use of the Company s latest
marginal cost study that yields $40.96 per MWh as the value to be used for the load
growth adjustment. It is based on an accepted marginal cost methodology and adjusts for
line losses. Any of the proxies or the results ofthe AURORA model would be
acceptable. The important decision is that a marginal approach be used for estimating the
value of the load growth adjustment.
YOU STATED ABOVE THAT THE COMMISSION'S STAFF HAS
CALCULATED THE LOAD GROWTH ADJUSTMENT BY RUNNING AURORA
WITH A LOAD INCREASE OF 10 AVERAGE MW FOR EVERY HOUR. DO
YOU KNOW WHAT THIS APPROACH YIELDS?
The Commission Staff asked Idaho Power to perform an AURORA
model run with the same 10 aMW load increase. (Response to Request No., First
Production Request of Staff). The results indicate power supply costs $3 578 900 higher
than the base amount filed in the Company s last rate case (IPC-05-, Exhibit 20).
This means the marginal cost of power supply for the Company is $40.86 per MWh.
(3578900/87600). This value is essentially the same level as that found in the Company
marginal cost study that I recommended to use as the load growth adjustment above.
Reading (Di)
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IPC-06-
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VISTA ALSO HAS A POWER COST ADJUSTMENT
MECHANISM. DO YOU KNOW IF THEY USE A LOAD GROWTH
ADJUSTMENT, AND IF IT IS SET ON A MARGINAL ENERGY COST BASIS?
The Commission does use the marginal cost of generation in adjusting for
load growth in Avista s power cost adjustment. According to page 46 ofthe
Commission s Order No. 29602 in Case No. A VU-04-, the current level is $36.
dollars per MWh.
DO YOU HAVE ANY ADDITIONAL COMMENTS FOR THE
COMMISSION THAT DEAL WITH THE LOAD GROWTH ADJUSTMENT?
Yes. The load growth adjustment is a "two-edged sword.That is
when loads are growing, the adjustment reduces the level of the PCA surcharge.
Conversely, when loads decrease, the load growth adjustment will increase the PCA rate
over what it would otherwise be. The load growth adjustment is comprised of two
components: 1) the estimate of fuel value, and 2) the change in loads. The Company is
advocating a significant lowering of the value of the load growth adjustment. Should the
Company embark on an aggressive conservation program it potentially could reduce load
growth. In that case a high load growth adjustment value would tend to increase the peA
surcharge and allow the Company to charge higher rates. At a minimum, load growth
could be moderated and the impact of the load growth adjustment would be lessened.
This fact logically fits with the marginal approach originally approved by the
Commission. To the extent that the Company can avoid using its higher cost units, the
greater the savings in power supply costs, and therefore a smaller offset is needed.
Reading (Di)
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IPC-06-
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DOES THIS CONCLUDE YOUR TESTIMONY?
Yes, it does.
Reading (Di)
ICIP
IPC-06-
- 19 -
Present position
Education
Professional
and business
history
Don C. Reading
151
Exhibit No. 201
IPC - E-O6-
ICIP
Don C. Reading
Consulting Economist with Ben Johnson Associates, Inc.
, Economics - Utah State University
, Economics - University of Oregon
Ph., Economics - Utah State University
Idaho Public Utilities Commission:
1981-86 Economist/Director of Policy and Administration
Teaching:
1980-81 Associate Professor, University of Hawaii-Hilo
1970-80 Associate and Assistant Professor, Idaho State University
1968-70 Assistant Professor, Middle Tennessee State University
Dr. Reading provides expert testimony concerning economic and
regulatory issues. He has testified on more than 25 occasions before
utility regulatory commissions in Alaska, California, Colorado , the District
of Columbia, Idaho , Nevada, Texas, Utah , and Washington.
His areas of expertise include demand forecasting, long-range planning,
price elasticity, marginal pricing, production-simulation modeling, and
econometric modeling. He has also provided expert testimony in cases
concerning loss of income resulting from wrongful death , injury, or
employment discrimination.
Dr. Reading has more than 30 years experience in the field of economics.
He has participated in the development of indices reflecting economic
trends , GNP growth rates , foreign exchange markets, the money supply,
stockmarket levels, and inflation. He has analyzed such public policy
issues as the minimum wage , federal spending and taxation , and
import/export balances. Dr. Reading is one of four economists providing
yearly forecasts of statewide personal income to the State of Idaho for
purposes of establishing state personal income tax rates.
Dr. Reading s areas of expertise in the field of energy include demand
forecasting, long-range planning, price elasticity, marginal and average
cost pricing, production-simulation modeling, and econometric modeling.
Among his recent cases was an electric rate design analysis for the
Industrial Customers of Idaho Power.
While at Idaho State University, Dr. Reading performed demographic
studies using a cohort/survival model and several economic impact
152
Don C. Reading Exhibit No. 201
IPC - E-O6-
ICIP
studies using input/output analysis. He has also provided expert
testimony in cases concerning loss of income resulting from wrongful
death , injury, or employment discrimination.
Among Dr. Reading s current projects are a FERC hydropower
relicensing study (for the Skokomish Indian Tribe) and an analysis of
Northern States Power s North Dakota rate design proposals affecting
large industrial customers (for J.R. Simplot Company). Dr. Reading has
also recently completed an analysis for the Idaho Governor s Office of the
impact on the Northwest Power Grid of various plans to increase salmon
runs in the Columbia River Basin.
Publications
The Economic Impact of Steel head Fishing and the Return of Salmon
Fishing in Idaho, Idaho Fish and Wildlife Foundation, September, 1997.
Cost Savings from Nuclear Regulatory Reform , Southern Economic
Journal , March , 1997 , with R. Canterbery and B. Johnson.
A Visitor Analysis for a Birds of Prey Public Attraction, Peregrine Fund
Inc., November, 1988.
Investigation of a Capitalization Rate for Idaho Hydroelectric Projects
Idaho State Tax Commission, June, 1988.
Post-PURPA Views " In Proceedings of the NARUC Biennial Regulatory
Conference, 1983.
An Input-Output Analysis of the Impact from Proposed Mining in the
Challis Area (with R. Davies). Public Policy Research Center, Idaho State
University, February 1980.
Phosphate and Southeast: A Socio Economic Analysis (with J. Eyre, et
al). Government Research Institute of Idaho State University and the
Southeast Idaho Council of Governments, August 1975.
Estimating General Fund Revenues of the State of Idaho (with S.
Ghazanfar and D. Holley). Center for Business and Economic Research
Boise State University, June 1975.
A Note on the Distribution of Federal Expenditures: An Interstate
Comparison , 1933-1939 and 1961-1965." In The American Economist
Vol. XVIII , No.2 (Fall 1974), pp. 125-128.
New Deal Activity and the States, 1933-1939." In Journal of Economic
History, Vol. XXXIII (December 1973), pp. 792-810.
153 - 167
THIS PAGES INTENTIONALLY LEFT BLANK
168
Dr. Reading isMR. RICHARDSON:Thank you.
now available for cross-examination.
COMMISSIONER SMITH:Thank you.
Mr. Eddie, do you have any questions?
I do not have any questions.MR. EDDIE:
COMMISSIONER SMITH:Mr. Woodbury?
Thank you, Madam Chair.MR. WOODBURY:
CROSS-EXAMINATION
BY MR. WOODBURY:
Good afternoon , Dr. Reading.On page 8 of your
testimony, you identified the issue before the Commission as
whether the load growth adjustment should be calculated based on
the marginal costs of serving new loads or based on the embedded
cost of serving loads.
When
--
with respect to the embedded cost,
you are talking about for existing customers as opposed to new
load and distinguishing between those two?
That would be for new load.
Okay.If the intent of the Commission was that power
supply costs associated with changes in load be factored out of
the PCA as evidenced from their order language, is that intent
best accomplished by a load growth adj ustment based on an
embedded cost or marginal cost?
169
As I stated in my testimony, I believe marginal cost
as I interpreted the Commission s original intent.
Is it your understanding that the Commission uses
historic test years in Idaho Power s general rate cases?
Yes.
And by historic test years, is the Company between
rate cases restricted to recovering just it's historic
normalized costs embedded in rates?
Yes.
Isn t tracking growth-related power supply costs
through the PCA contrary to the purpose of using a historic
rather than a forecasted test year?
I think I heard a phrase there.Could you repeat?
Would you repeat the question, please?
Isn t tracking growth-related power supply cost
through the PCA contrary to the purpose of using a historic
rather than a forecasted test year?
I guess I would answer that as saying it is addendum
As explained in the Commission s original order, whento it.
the Commission went to making rates on a normalized test year
you know , taking the average of 64 or 78 or whatever the number
of water years was at that particular time -- they recognized,
as has been discussed here earlier, that Idaho Power s resources
were sufficiently impacted by changes in snow pack and stream
flow; that it would be more equitable to the Company and the
170
customers to have an adj ustment between rate cases for those
changes in stream flows.So I don t think it's contrary, I
think it's a recognition of the kind of resources and the kind
of utility Idaho Power is to treat both the Company and the
customers more fairly.
Than k you.
MR. WOODBURY:Madam Chair , no further
questions.
COMMISSIONER SMITH:Mr. Kline?
MR. KLINE:Thank you, Madam Chair.
CROSS- EXAMINAT ION
BY MR. KLINE:
Dr. Reading, I would like to direct your attention to
page 16 of your testimony.And on page 16 you discusses three
proXles that you are recommending for a way of measuring
marginal costs; is that correct?
I think I've picked the marginal cost studies byYes.
the Company as the preferred of the , but
Yeah.
--
there are three ways to do it.
m sorry.You mentioned three, and we have already
discussed the first and the third, so I just want to talk about
the second one.In your second proxy, you propose to use the
171
adjustable portion of Idaho Power s avoided costs for the
surrogate of water resource; is that correct?
Yeah.That would be a method that could be used.
And it's your second proxy; correct?
Right.I guess if I had to rank them , I would put it
in third place.
The adj ustable portion that we re talking about here
is based on the fuel and variable OLM costs for the
surrogate-avoided resource, which is currently a combined cycle
combustion turban; correct?
Yes.
And a combined-cycle combustion turbine, of course, is
a base load resource, is it not?
Yes.
And Idaho Power has not constructed a combined-cycle
combustion turbo; is that correct?
That's correct.And that's one of the reasons I put
it in third place.
In the past the Commission has used a coal-fired plant
as the surrogate avoided resources, have they not?
Yes.
If the next surrogate avoided resource that the
Commission chooses is a coal plant, and it has the typical coal
plant fuel cost of around $15-17 , I take it from your testimony
you would still think that was the good proxy for Idaho Power
172
marginal cost?
It would be a reasonable proxy for those kinds of
As I said I would pick it as the third unit
--
theplants.
I guess I would add if it's the marginal plantthird choice.
that the utility is constructing.
MR. KLINE:That's all I've got.
Do you have questions fromCOMMISSIONER SMITH:
the Commission?
COMMISSIONER HANSEN:No.
COMMISSIONER KJELLANDER:No.
Any redirect?COMMISSIONER SMITH:
I don t, Madam Chair.Thank you,MR. THOMPSON:
Dr. Reading.
The Northwest Energy Coalition willMR. EDDIE:
call Peter Weiss.
PETER WEISS,
produced as a witness as the instance of the Joint Applicants,
being first duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MR. EDDIE:
Mr. Weiss, will you state your name and spell your
last name for the record, please?
173
Steven Weiss, W- E- I -S-S.
Madam Chair, with yourMR. EDDIE:
indulgence I would ask that you spread the testimony, the direct
and rebuttal, of Mr. Weiss.
COMMISSIONER SMITH:(Nods head.
Are you the same Steven Weiss that caused to be filed
16 pages of direct testimony together with two exhibits in this
case?
Yes.
Wi th respect to the direct testimony that you filed,
do you have any supplemental comments or changes you would like
to make at this time?
Throughout this testimony, I have used examplesYes.
of rates and prices and so on starting on page 6 of my direct
And I just want to make it clear that first of all,testimony.
the rate that I used, the 6.5 cents for the residential rate, as
was pointed out in rebuttal by Mr. Said, probably was too high.
I was reading
--
I included the customer charge
--
fixed
customer charge.But I just want to make it clear that the
numbers I am using in my entire testimony are just illustrative
And that whether it's 6.5 or 6.1 or as was said hereexamples.
9 I think was the average because there is a summer and winter
rate, doesn t really for the point of my discussion.These are
illustrative examples.If the Commission was to accept our
recommendations, they would have round them in actual numbers.
174
Is it fair to say that you (inaudible) to the
Commission , and the figures are simply illustrative of that?
Yes.
And do these changes affect your recommendation to the
Commission here?
No.
Did you also cause to be pre-filed in this caseOkay.
six pages of rebuttal testimony together with one exhibit?
And you have no changes that testimony at this time?
No.
Madam Chair, with that I moveMR. EDDIE:
that the direct and rebuttal testimony of Steven Weiss be spread
upon the record as well as Exhibits 301 , 302, and 303 be marked
for identification.
COMMISSIONER SMITH:Is there any
objections?
(No response.
If not, it is so spreadCOMMISSIONER SMITH:
and the exhibits marked for identification.
(The following pre-filed direct
testimony of Steven Weiss is spread upon the record.
..,
175
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Steven Weiss. I am employed by the NW Energy Coalition, 219 First
Ave. South, Suite 100, Seattle, W A 98104.
WHAT ARE YOUR POSITION AND RESPONSIBILITIES?
I am a Senior Policy Associate and frequently represent the Coalition in regulatory
proceedings with the Bonneville Power Administration and in the State of Oregon. I
am also an advocate for clean and affordable energy in many other forums including
the NW Power and Conservation Council, Columbia Grid and the Oregon
Legislature.
PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND
PROFESSIONAL EXPERIENCE.
I received a Masters in Science Education from Bucknell University in 1976 and
Bachelor of Arts in Physics and Math from the University of California at Berkeley in
1968. Previous professional experience includes employment as Assistant Professor
at Clarion State College in Pennsylvania from 1975-, and I was elected to the
Board of Salem Electric (Co-op) four times from 1982-94. I also owned and operated
a retail bicycle shop from 1980-96. I have been employed by the Coalition since
1994 and have participated in numerous Oregon, BP A and regional policy forums and
rate cases. I also co-authored Oregon s electricity restructuring law (SB 1149). My
resume is included as Exhibit 301.
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HA VE YOU APPEARED BEFORE UTILITY REGULATORY COMMISSIONS IN
OTHER PROCEEDINGS?
Yes, I have represented the Coalition in numerous dockets, including rulemakings.
Examples in Oregon include Northwest Natural's filings regarding its Weather
Adjusted Rate Mechanism (UG 152) and decoupling (UG 143), POliland General
Electric s decoupling filing (UE 126), and Cascade Natural Gas Corporation
Conservation Alliance Plan, inclusive of a decoupling mechanism (UG 167). In
Washington, I served as a witness for the Coalition in the 2004 Puget Sound Energy
(PSE) rate case , focusing on rate design issues; and in the ongoing PSE gas
decoupling rate case (UG-060267 & UE-060266). Also I have represented the
Coalition in ~1lImerous Integrated Resource Planning Processes, as well as at
workshops and conferences over the past dozen years.
PLEASE SUMMARIZE THE CONTENTS OF YOUR TESTIMONY.
My testimony is arranged as follows: (1) I first discuss how traditional ratemaking
impacts the utility s (and customers ) incentives and risks between rate cases. (2)
Second I describe the effect on Idaho Power s net revenues resulting from each new
kWh and each new customer hookup. (3) I then discuss how the policy implications
of the peA cannot be discussed in a vacuum. On this point, I believe the peA issues
at stake here are linked to the outcome of the decoupling proposal in IPC- E-04-l5 (a
proposal that essentially guarantees that Idaho Power s recovery of fixed costs for
existing customers regardless of changes in their loads, and would allow the
Company s fixed cost recovery to grow along with growth in customer numbers). (4)
. Finally, I will make a proposal that, assuming a decoupling mechanism is approved in
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IPC-04-, will lead to a revenue-neutral proposal regarding new customer
numbers while providing an incentive for IPC to encourage reduced usage per
customer. By modifying Idaho Power s proposal in this case, and approving a
decoupling mechanism in IPC-04-, the Commission would both maintain
traditional shared risks, while also creating a strong incentive for the utility to fully
obtain and advocate for conservation and efficiency improvements, which are by far
the least-cost resources available to customers. Cunently Idaho Power likely enjoys
net positive revenues from load growth, providing both a disincentive to the
Company to promote conservation and an unwarranted windfall unrelated to its
actions. To reflect that fact in the peA, a Load Growth Adjustment must be added
but the methodology must be different than presently used. The scope of my
testimony does not include a specific recommended amount, but does provide an
example of how that could be developed.
I. Traditional Ratemaking
WHAT INCENTIVES AND DISINCENTIVES ARE EMBEDDED IN
TRADITIONAL UTILITY REGULATION AND WHAT EFFECT DO THEY
HA VE?
Utilities have traditionally been regulated based on their costs, including an
opportunity to earn a reasonable rate of return. In periodic rate cases, a review of
revenue and cost levels occurs , and rates determined such that the utility can earn that
rate of return. But just as important an element of regulation is how the rate structure
and any trackers, affects the Company betvveen rate cases. This is known as
Regulatory Lag. For it is between rate cases that any reduction in costs and/or
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increase in revenues go straight to the utility s bottom line. Thus the incentives
provided by the rate structllre are important motivators for utility actions.
Regulatory lag, in my opinion, is one of the most imp0l1ant considerations
regulators should be aware of when designing or approving rates. On the cost side
regulatory lag is largely beneficial for customers because it provides the utility the
incentive to reduce costs and improve productivity, which are then incorporated into
lower,rates.in the next rate case.' But on the revenue side, the issue is more
complicated. That is because regulatory lag can produce utility incentives that are at
cross-purposes with customer interests, promote unabated load growth and lead
ultimately to higher costs.
WHAT FACTORS INFLUENCE REVENUES BETWEEN RATE CASES?
Broadly, two factors are important: (a) changes in revenue per customer from load
changes; and, (b) changes in the number of customers. To understand the utility
incentives, it is necessary to determine what the financial impact to the utility is from
increases or decreases in these two factors. Revenue per customer between rate cases
has two determinants: First is change in usage per cust0l11,er multiplied by the
marginal rate for that customer. Second is change in the number of customers.
All ratemaIeing regulation provides utilities with incentives or disincentives to
behave in a certain manner. By focusing on how the addition (or reduction) of one
Ie Wh of load or one new customer affects the utility s bottom line between rate cases
one can describe those incentives and disincentives. In addition, one can see if the
rate structure causes undeserved increases or decreases in a utility s net revenues that
I This is not an unalloyed benefit. Many regulators also require utilities to have in place strong service quality
and reliability standards to ensure that cost-cutting is not over done.
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are unrelated to the utility s actions. Such a result is simply an undeserved loss or
windfall to the utility, and even if symmetric (i., equally likely to benefit
shareholders or customers over the long term) may increase net revenue volatility
unnecessarily.2 Ideally, utilities should be rewarded based on how well they meet
their customers ' energy service needs , but that is not always the case. Sometimes the
utility s incentive is to encourage load growth even though cost-effective
conservation would be less costly to customers. (This issue is thoroughly covered in
the decoupling discussion in IPC-04-, so I will not repeat it here.) And
sometimes the utility is rewarded or punished with windfall profits or losses unrelated
to its activities. Thus it is impOliant to examine the issue closely in order to have a
result that is fair to all parties and in the public interest
II. The Effect of Marginal Changes in Load and Customer Count
WHAT HAPPENS TO IPC'S NET REVENUES UNDER CURRENT POLICY
WHEN LOAD INCREASES BY 1 KWH?
For this discussion, I first assume that this increase in load is not accompanied by a
higher customer count and that it is a residential load (and, of course, decoupling has
not been implemented). Perhaps someone adds a battery charger after the rate case
has set load levels. Below I address a scenario where the load groWth occurs from
the addition of a customer.
2 For example, changes in weather, totally out of the utility s control, can produce volatility
in its returns that serve no purpose other than simply raising its cost of capital-a co:,t that
must eventually be paid by customers. A weathel' decoupling mechanism , however, can
reduce that volatility.
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A number of things determine how much IPC's net revenue changes. First, its
revenues increase by about 6.5~, because that is how much extra the customer pays
for the kWh.3 But its costs also increase, and this is where it gets a little complicated.
To serve this new load, Idaho Power must either purchase the electricity from the
market (or forego the same amount of money from reduced sales). Let's assume for
discussion a market price of 4~ ($40IMWh-note: all prices per MWH have been
converted to cents/kWh in this discussion). While a portion of those costs would
covered by the peA, I will put aside the peA for the moment and focus on what it
really costs the Company.
. In addition to the 4~ for additional power, the Company also incurs some
incremental "fixed" costs. While the embedded costs of its hydro and coal facilities
won t change, each additional increment of load will incur an incremental cost for
additional O&M, bigger or more numerous transformers, substations, etc., that
kWh's share if incremental distribution costs. But, for the most part, these
distribution costs will not increase between rate cases , especially in this scenario
where the load growth is not associated with a new customer. The system is built
robustly enough that incremental load growth in existing neighborhoods will not
increase distribution and O&M costs much. The "robustness" (i.e. the headroom
available to accommodate load growth) has already been included in the capital costs
of the system, which will not change. Larger distribution costs, such as new
substatioi1s and larger transformers may eventually be needed if average loads
increase substantially, but their costs will be added into rate base at the next rate case.
3 I have assumed that the additional kWh is priced at the higher, marginal block rate.
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So though I camlOt precisely say how much new distribution costs the new kWh will
cause, it lllost likely is less than 5t. An exact number is not important for my point.
My point is that it is very likely that the costs of serving the new kWh will not
match the added revenue from that kWh. In my example, the additional costs totaled
5t while the additional revenue was 5t. In this likely situation, the Company
will see an increase in its net revenue of2t and thus have a powerful incentive to
encourage increased load and to be less-than-enthusiastic about conservation.
WHAT HAPPENS TO IDAHO POWER'S NET REVENUES WHEN IT ADDS A
NEW CUSTOMER?
I will assume for this example that this is a residential customer, and his or her load is
exactly the same as the average of all other customers.
This customer s load also pays about 5t for each kWh. (Not exactly true
due to Idaho Power s 2-block rate plus the customer charge, but close enough for this
discussion.) For each kWh used by this customer, Idaho Power s power cost is about
4t as in the previous example. But because this is a new hook-up, the Company
added distribution costs are higher than in that case. The Company has to string wire
install a new meter and perhaps a (pOliion of) a new transformer-all between rate
cases. Ignoring any construction costs paid by the new customer due to IPC's line
extension policy, perhaps this costs 2t per kwh for the average new customer. IPC
therefore receives 5t in net revenues. So now, the mismatch between cost and
revenue is less than the first scenario (0.5t on each new kWh compared to 2t). That
would reduce the utility s incentive to increase loads from new customers compared
to the previous example, but it would still exist.
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PLEASE SUMMARIZE YOUR CONCLUSION THUS FAR.
Putting aside regulatory treatment of all this, I draw two conclusions. (a) If the
incremental cost of increased load or increased customers does not match the
incremental net revenue produced, the utility will have incentives that mayor may not
be in the public interest; and, (b) the critical numbers one must look out to understand
what is really happening are the incremental costs (and revenues) of new load and
new customers , not the embedded costs.
PLEASE EXPLAIN THE CURRENT REGULATORY TREATMENT OF THE
TWO SCENARIOS DISCUSSED ABOVE.
The two regulatory mechanisms that bear on this issue are the PCA and any
decoupling mechanism that might be approved. I will stmi with the peA.
The first thing to point out is that the peA is not affected by customer count.
Therefore the peA impact is the same for any increase in load regardless of whether
it came from an existing or new customer--'-the PCA only adjusts the power cost
impact, but does not address the different distribution cost impacts of the two
scenarios. Therefore, the PCA cannot provide an appropriate regulatory impact for
both scenarios at the same time, since the peA treats these two scenarios-though
they have quite different net revenue impacts - as if they were the same. Second, the
PCA formula depends on embedded costs. The added base rate revenue from each
additional kWh is pmotly allocated toward peA costs (about 0.7~ and the rest to non-
peA costs). Yet it is clear that the incremental power cost to serve the new load is
higher, in the 4~ or more range, and the incremental fixed cost is different in the two
scenarios (and certainly much less than the embedded fixed cost).
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In short, the PCA adjustment is not linked to the actual incremental changes
in costs and revenues that I went through above. Only by extraordinary luck could it
avoid a result that either rewards or punishes IPC for new loads and/or new customers
due to the almost inevitable mismatch between the increll1ental costs and revenues
that result from growing loads. The result-ei'ther a reward or a penalty-becomes
the incentive to either encourage or discourage load growth. I believe it is poor
public policy to have this key result driven by the arbitrary and essentially random
differences between the incremental costs of serving new loads and customers.
Currently the PCA reduces the amount the utility can recover from its
additional power costs by abotlt 1~/kwh (using the current $16.84/MWh load growth
adjustment minus the $6.71/MWh embedded peA cost). Gregory Said's direct
testimony (p. 12) describes a "penalty" of around 1.16~/kWh using older numbers
but the calculation is the same. As I estimated above, without the peA the
Company s actual net revenues increase by 2~/kWh for load growth of existing
customers, so including the PCA would probably result in the Company still having a
positive incentive of 1 ~/kWh to increase load. But for new customers, the PCA
would penalize the Company through a net revenue loss of 0.5~/kWh. Clearly this is
a bizarre result. IPC is proposing to remove this "penalty," which would 'mean all
load growth would benefit the Company.
DO YOU AGREE WITH THE CaMP ANY THAT THE PRESENT peA
PENALIZES IDAHO POWER FOR LOAD GROWTH?
Seen in isolation, it would seem that way. However, the peA only deals with the cost
of new power, not the cost of incremental distribution nor the effect of increased
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revenue. In addition there is another reason to suspect that it is not really a penalty.
If it really were true that the Company was not allowed to recover a significant
amount of money because of load growth, one would expect it to be aggressively
pursuing conservation. Sadly, that is not really the case.
DOES IDAHO POWER'S INVESTMENT IN DEMAND-SIDE MANAGEMENT
OVER THE LAST DECADE EVINCE A COMPANY THAT SUFFERS A
PENALTY FROM GROWING LOADS?
No. Idaho Power has been very slow to implement demand-side management, even
in the face of growing loads. Idaho Power s system load in its 1994 rate case was
about 14.5 million MWh's. The Company s system load increased over the next six
(6) years up to a high point of about 15.8 million MWh's in 2000-2001. Over that
same six (6) year period, Idaho Power s spending on demand-side management
dropped precipitously from about $6.19 million in 1995 down to about $1.7 million in
2000 and 2001. In response to the energy crisis of 2000-0 1 , system loads dropped
before resuming their growth. See Exhibits 302 at pages 2, 5 (Idaho Power Response
to Production Requests).
WHY DO YOU BELIEVE THOSE FACTS ARE IMPORTANT?
The fact that Idaho Power dis-invested in DSM in the late 1990's in the face of
growing loads indicates that the Company is not penalized enough by the Load
Growth Adjustment in the peA, as indicated in the Direct Testimony of Gregory Said
(page 12)to overcome the underlying marginal increase in the net revenues it
receives from adding load. If there was a detectable penalty in the peA (as part of
Idaho Power s overall rate design), the Company was behaving irrationally.
Weiss, Steven - Di
NW Energy Coalition
185
IS IDAHO POWER INVESTING IN ENOUGH DSM TODAY?
NW Energy Coalition believes the Idaho Power is rapidly improving its DSM
program. I understand that the Company s draft 2006 Integrated Resource Plan
proposes to further accelerate DSM program investments nearly up to the
approximately levels ofDSM potential estimated by the NOlihwest Power and
Conservation Council in 2004. That said, the Company s actually estimated savings
are still very low (3.25 MWa in 2004, and 4.71 MWa in 2005 , both including
estimated savings from programs run by Northwest Energy Efficiency Alliance).
Exhibit 302 at page 9. I am certain those savings will accelerate rapidly in coming
years, but they are still low compared to other Northwest utilities. It is NW Energy
Coalition s position that all cost-effective DSM resources should be acquired before
supply resources are acquired. Very simply, there is no easier, cheaper, or cleaner
way to keep both rates and customer bills low.
GIVEN THIS WEAK RECORD ON CONSERVATION, IS THE COMPANY
BEHAVING IRRATIONALLY?
No. As I noted above, even with the PCA's "penalty," the Company likely has an
incentive to promote load growth, especially by existing customers. Therefore it is
serving its shareholders well by having a lukewarm attitude toward conservation
even though it is compensated completely for its conservation costs.
WHAT IS YOUR CONCLUSION REGARDING THE PCA?
The PCA, as presently designed, can never result in rates that are exactly "right" in
balancing the impact of new load on the Company. But because of that mismatch, it
is never neutral. Instead it provides an incentive (for or against load growth)
Weiss, Steven - Di
NW Energy Coalition
186
depending on the level of the load growth adjustment. If the Commission wishes to
provide Idaho Power an incentive toward conservation by providing a penalty, it
should do so directly. I do not believe the Commission should address this impOliant
policy issue obliquely through the load growth adjustment.
WHAT WOULD BE A BETTER DESIGN FOR A PCA ADJUSTMENT?
A better design would be ensure the peA has a neutral impact by reflecting as close
as possible the actual incremental changes in costs and revenues that load growth and
new customer growth creates. That is, the PCA should reimburse the Company for
(90% 4 of) the incremental cost of new power, less the incremental revenues received
from the customer, rather than relying on embedded costs that have little relation to
the actual net revenue impacts. That calculation would necessarily be different for the
two scenarios examined-load growth from existing customers versus load growth
from new customers-because they have different incremental revenues. Therefore
there would be two different peA adjustments: one for load growth from existing
customers, and the other for load growth from new customers.This design is
neutral to the Company in that it does not provide any incentive or disincentive to
encourage load growth. If the Commission wishes to provide an incentive for the
Company to reduce load growth, it should do so directly, and not rely upon this
opaque mechanism to achieve that policy result.
IS YOUR SUGGESTION FOR MANY DIFFERENT ADJUSTMENT FACTORS
TOO COMPLICATED?
4 If the Commission wishes to provide a stronger incentive to the Company to make smmi
purchases between ratecases, it could lower this percentage.s These two would apply to residential customers. Different adjustments would also have
be used for the other customer classes.
Weiss , Steven - Di
NW Energy Coalition
..,
187
I don t believe that two factors for each customer class is all that complicated.
However, a second best solution is to set the load growth adjustment rate such that the
PCA results in an adjustment that reflects the average incremental change that load
growth causes for each class, and not differentiate between new and existing
customers. There should still be a different adjustment for each other customer class
however, as the incremental cost changes for commercial and industrial load
increases are quite different than for residential customers.
COULD YOU PROVIDE AN EXAMPLE USING THE NUMBERS YOU HAVE
BEEN USING SO FAR?
Yes. Please note that this example does not assume a decoupling adjustment. I
assumed that a new kWh to serve an existing residential customer was acquired at a
cost of 4~. That new kWh produced incremental revenues for the Company of 6~
(rate of 6.5~ minus the incremental increase in distribution costs of 0.5~). Without a
PCA, the utility would enjoy a windfall of2~. Therefore the load growth adjustment
must be set at a level that produces a refund to customers of 2~ (this would calculate
to $26.71/MWh, or $20/MWh plus the $6.71/MWh embedded peA amount). Using
this amount as the adjustment makes the Company neutral in regard to load groWth
from existing customers. A different load groWth adjustment can similarly be
designed for the case of load growth due to a new customer hoohlP. Using my
example, it would be $11.71 ($5 + $6.71).
COULD THE COMMISSION USE YOUR DESIGN TO SHIFT LOAD GROWTH
RISK TO THE COMPANY?
Weiss, Steven - Di
NW Energy Coalition
188
15.
Yes. If the Commission wanted the PCA to provide a stronger incentive to the utility
for pursuing conservation, it could raise the load growth adjustment higher so as to
penalize the company when load growth occurs. Another effective way to motivate
the Company that we favor is to set concrete DSM targets and benchmarks connected
to rewards and penalties.
THE SECOND MECHANISM THAT HAS AN IMP ACT ON THIS ISSUE IS
DECOUPLING. HOW DOES DECOUPLING AFFECT THE TWO SCENARIOS?
While the peA addresses changes in power costs between rate cases, decoupling
addresses changes in fixed costs. Under the decoupling proposal being discllssed in
IPC-04-, revenue changes between rate cases resulting from loads being higher
or lower than normal for existing customers are adjusted to provide the Company
with the same embedded fixed costs per customer as approved in the most recent rate
case. As such, the mechanism is neutral in relation to existing customers and
provides neither an incentive nor disincentive for IPC to encourage load growth (or
promote conservation). In addition, the proposed decoupling mechanism would also
maintain that same average level of embedded non-power related costs for new load
created by new hookups regardless of their usage level. However, the incremental
non-power costs of serving a new customer are most likely lower than the embedded
cost imputed to existing customers of about 3.25~/kwh.6 That is because the
incremental cost of serving a new customer is just the cost of additional distribution.
There is no additional impact to the other embedded costs of the system such as
6 The non-power costs of about $138 million are divided into average usage of about 4.5 billion kWh. I
obtained these figures from the direct testimony of Mike Youngblood in the decoupling docket (IPC-O4-15)
pp.
14-J 6.
Weiss, Steven - 01
NW Energy Coalition
189
generation costs and other debt. Thus, the Company will receive a windfall from new
customers (regardless of their usage) by recovering average embedded fixed costs
rather than the much smaller incremental amount. So while the mechanism does
indeed remove the incentive to encourage load growth, it is not neutral. It provides
an incentive to hook up more customers. (A discussion of whether or not this is a
desired outcome is not part of this proceeding, however.)
MODIFYING THE DECOUPLING PROPOSAL IS NOT A SUBJECT OF THIS
DOCKET, HOW IS IT RELEVANT TO THIS DISCUSSION?
It is important for the Commission to understand the coill1ection between the peA
discussion and the decoupling discussion. The incentive the Company will see, and
the overall fairness of the rates, depends on how they are both designed.
In summary, it is necessary to look at the complete package. It is impossible
to understand how the PCA and decoupling mechanisms will reward or penalize
Idaho Power for pursuing and encouraging conservation without looking at their
combined effects on marginal changes in load.
DOES THE COALITION HAVE A RECOMMENDATION?
Yes.
We recommend that the peA be redesigned so that it is based on the different
incremental costs of load growth caused by existing customers versus load
growth caused by new customers, thus making it neutral to the Company and
customers. In the alternative, the load growth adjustment should be set to come
as close to that result as possible. I have provided an example of how that could
be done. All thatis missing to do the calculation are estimates of the incremental
Weiss, Steven - Di
NW Energy Coalition
190
costs of serving new load and new customers based on Idaho Power s system
data. Staff and the Company are best equipped to identify those numbers.
To provide the Company with a clear incentive to encourage conservation: (a)
decoupling should be approved in order to remove the disincentive on the
revenue side; and, (b) either: (i) raise the load growth adjustment another $10.
or so from the number determined in #1 above to pl'ovide a clear incentive for
conservation; or, (ii) use direct conservation targets and benchmarks with
incentives and penalties.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
Weiss, Steven - Di
NW Energy Coalition
Current Position
Experience
191
Steven Weiss
Senior Policy Associate, NW Energy Coalition
1995 - Present NW Energy Coalition
Senior Policy Associate
Sr. member of the policy team implementing NWEC's policy goals relating to a clean
and affordable energy future.
Areas of responsibility include Bonneville Power Administration, Oregon PUC
Oregon Legislature, NW Power Planning Council, Grid West/Columbia Grid" Oregon
Advisory Committee on Energy (low-income issues), occasional DC lobbying.
Seattle, WA
1993-1995 Clients: NW Energy Coalition, OR Dept. of Energy, W A Utilities
and Transportation Commission
Consultant
Policy development and advocacy on Regional energy issues.
Published newsletter on BPA's Power Sales Contract Negotiations.
1984-1996 Salem Electric Co-op
Director - Elected to four 3-year terms
. Chair, 1989-
. Initiated, or major co-sponsor of the following initiatives:
Inverted residential rates
Salem, OR
. Low-mcome energy assistance program
Efficient appliance rebates, recycling rebates, at-cost CFLs, etc.
Salem Electric "Building Code" which gives builders incentives for efficient building
practices.
Integrated Resource Planning.
Representative to NWPP A, PPC, NRECA
1980-1996
Owner - 2 stores
Staff of 8
Sales of $450 000 annually
Salem, ORBicycle Doctors bicycle shops
1971-1985
nstructor/Professor
. 1971-1977 Physics Instructor, Bucknell University
1977- I 979 Assistant Professor, Clarion State College. Research and teaching on
campus demonstration high school.
. 1980-1985 Math/statistics instructor (part-time), Chemeketa Community College
Salem, OR
Exhibit No. 301
192
2003-Present
Board of Directors
Elected to Citizens ' Utility Board board of directors , 2002 and 2005
Prepared testimony and participated as key Witness for NW Energy Coalition:
Regulatory and other 1996, 200 I , 2002, 2006 Boill1eville Power Administration ratecases
Policy Experience Numerous BP A proceedings including Power Function Review, Resource Adequacy
Forum, Comprehensive Review, Subscription process, Regional Dialogue, etc.
1998, 2000 2003, 2006 PacifiCorp and Portland General Electric Integrated Resource
Planning dockets.
1996 docket on purchase ofPGE by Enron
1999 docket on purchase of Pacifi Corp by Scottish Power
2001 PGE decoupling docket
2001 PacifiCorp and PGE restructuring dockets following passage ofSB1149
2002 UM 1 066 docket on Regulatory Policies affecting resource development
2002 NW Natural dockets establishing decoupling, public purpose charges
2004 Puget Power gas and electric docket on rate design
2005 Oregon dockets on competitive bidding, and Least Cost PlaIll1ll1g reqUIrements
2004~5 Oregon dockets instituting decouplinglpublic purposes for Cascade Natural
Gas
Lead negotiator for NW Energy Coalition:
1996 BP A contract negotiations on tiered rates
Development of Grid West (RTO)
2001 BPA's "Safety-Net" rate adjustments
2002-05 BPA's Regional Dialogue
Education 1968 BA Physics and Math, Univ. of California, Berkeley
1975 MS Education, Bucknell Univ., Lewisburg, Pennsylvania
1997 , 1999 Oregon Legislative sessions -- Co-authored and lobbied to pass SB 1149
Accomplishments Oregon s electricity restructuring law.
with NW Energy Co-founded the Fair and Clean Energy Coalition, Oregon public interest lobbying
Coalition coalition
Expert witness in numerous Oregon PUC dockets and rulemakings, including
proposals to decouple PGE and NW Natural's distribution rates, least-cost plans, etc.
Expel1 witness in BP A rate caSes, including developing rate adjustment mechanisms
now pm1 of the agency s rates.
Environmental representative to GridWest development group. Filed testimony and
comments to FERC on RTO West and other transmission and market issues.
Serve on Governor s Advisory Committee on Energy which advises Oregon agencies
on low-Income issues. Served on Portfolio Advisory Committee which develops
portfolio choices for Oregon consumers under SB 114~. Serve on Energy Trust of
Oregon s Conservation Advisory Council.
Provide analysis and coordination with salmon advocates and tribes relating to
energy/salmon issues.
Exhibit No. 301
BARTON L. KLINE ISB #1526
MONICA B. MOEN ISB #5734
Idaho Power Company
O. Box 70
Boise, Idaho 83707
Phone: [phone]
FAX: [phone]
bkline
(g)
idahopower.com
mmoen (fj) idahopower.com
Attorneys for Idaho Power Company
Express Mail Address
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION OF
IDAHO POWER COMPANY FOR
MODIFICATION OF THE LOAD
GROWTH ADJUSTMENT RATEWITHIN THE POWER COST
ADJUSTMENT METHODOLOGY
CASE NO. IPC-06-
193
IDAHO POWER COMPANY'
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF NW
ENERGY COALITION TO IDAHO
POWER COMPANY
COMES NOW , Idaho Power Company ("Idaho Power" or "the Company") and , in
response to the First Production Requests of NW Energy Coalition to Idaho Power
Company dated August 8. 2006 , herewith submits the following information: .
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page
Friday, September 15, 2006.max
EXH'B'T
3v)..
194
REQUEST FOR PRODUCTION NO.
Please state Idaho Power company s normalized system loads for each year
starting with year' 1995 through 2005.
RESPONSE TO REQUEST FOR PRODUCTION NO.
Idaho Power company s normalized system loads for 1995 through 2005 in MWh'
are as follows:
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
14656029
15141574
15180588
14758836
15240817
15837958
15759779
14276689
14193837
14536634
14819152
The response to this request was prepared by Gregory W. Said , Manager of
Revenue Requirement, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 2
Friday, September 15, 2006.max
195
REQUEST FOR PRODUCTION NO.
Please explain the basis for Witness Greg Said's use of normalized system load to
calculate the current embedded PCA-related cost of serving load (which he states to be
$6.81/MWh), as oppo$ed to using normalized firm system sales to calculate the same
figure..
RESPONSE TO REQUEST FOR PRODUCTION NO.
The Load Change Adjustment, as calculated in the Company s PCA Deferral
Report is based upon the change from Normalized System Load to Actual System
Load. It would be inappropriate to use an adjustment rate based upOn sales unless the
growth measured was also based upon sales, i.e. a sales change adjustment rather
than a load change adjustment. Please also see the Company response to Staff
Request for Production No.
The response to this request was prepared by Gregory W. Said, Manager of
Revenue Requirement, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Comrany-
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 3
Friday, September 15, 2006.max
196
REQUEST FOR PRODUCTION NO.
Please state Idaho Power Company s current average unit cost of serving load
growth.
RESPONSE TO REQUEST FOR PRODUCTION NO.
From the Company s perspective average unit cost is synonymous with embedded
cost. As stated in Mr. Said's testimony, the current embedded PCA related cost of
serving load is $6.81 per MWh.
The response to this request was prepared by Gregory W. Said, Manager of
Revenue Requirement, Idaho Power Company, in consultation with Barton L. Kline
Senior Attorney, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 4
Friday, September 15, 2006.max
197
REQUEST FOR PRODUCTION NO.
Please state Idaho Power Company s total amount of spending on demand-side
management ("DSM") programs or initiatives (including payments to the Northwest
Energy Efficiency Alliance ("NEEA") for each year starting with year 1995 through 2005.
RESPONSE TO REQUEST FOR PRODUCTION NO.
The following table details Idaho Power Company s total amount of spending on
demand-side management ("DSM") programs or initiatives (including payments to the
Northwest Energy Efficiency Alliance ("the Alliance )) for each year starting with year 1995
through 2005 as provided in the Company s respective DSM Annual Reports (previously
termed Conservation Plan) filed with the Commission.
Total System
(nominal $)
1880 $6 186 558
1996 $4 350 128
1997 $3 189 173
1998 $2 681 668
1999 $2 127 840
2000 $1 609 217
2001 $1 694 314
2002 $2 143,103
2003 $2,482 972
2004 $3 707 280
2005 $6,700 973
Notes:
Expenses are reported on a cash basis.
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline , Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THI::: FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 5
Friday, September 15 , 2006.max
198
REQUEST FOR PRODUCTION NO.
Please state an estimate of Idaho Power Company s expected total amount of
spending on DSM programs or initiatives (including payments to NEEA) in 2006.
RESPONSE TO REQUEST FOR PRODUCTION NO.
Idaho Power Company s expected total amount of spending on DSM programs or
initiatives (including payments to the Alliance) in 2006 -is $12 670 000.
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSl:: 10 rHEFIRST PRODUCTION REQUEST
OF Nw ENERGY COALITION TO IDAHO POWER COMPANY - Page 6
Friday, September 15, 2006.max
199
REQUEST FOR PRODUCTION NO.
Please state the total amount collected by Idaho Power Company under Schedule
91 ("Energy Efficiency Rider") for each year starting with year 2002 through 2005.
RESPONSE TO REQUEST FOR PRODUCTION NO.
The total amount collected by Idaho Power Company under Schedule 91 ("Energy
Efficiency Rider") on a system basis for each year starting with year 2002 through 2005 is
provided in the following table.
Idaho Power Company
DSM Rider Funds - GL Account 254201 & 254202
Idaho & Oregon Yearly Data from 2002-2005
2002 2003 2004 2005 2002-2005 Total
761 727.43 12,575 298.44
105,269.200 885.
866 997.776 183.
101,742.42 101 742.
3,475.475.
105 217.105 217.
Idaho Rider
Funding
Interest
Idaho Total
577,984.
063.
592 048,77
587,753.98 . 2 647,832.
044.19 '. 39,507.40
629 798.17 2,687 339.
Oregon Rider
Funding
Interest
Oregon Total
**Oregon Rider approved in August 2005. In August 2005, $141 089.64 was transferred into the rider account from a
dcfCrITaI account. Year end available funding balance wa~ $246,307.14.
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 7
Friday, September 15, 2006.max
200
REQUEST FOR PRODUCTION NO.
Please state an estimate of Idaho Power Company s expected total collections
under the Energy Efficiency Rider in 2006.
RESPONSE TO REQUEST FOR PRODUCTION NO.
Idaho Power Company's expected total collections under the Energy Efficiency
Riders in Idaho and Oregon in 2006 is approximately $8 740 979 based upon forecasted
normalized sales. Idaho customers are expected to provide approximately $8 334,415
and $406 564 is expected from Oregon customers.
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 8
Friday, September 15, 2006.max
REQUEST FOR PRODUCTION NO.
201
Please state the total amount of estimated energy savings (expressed as average
megawatts) Idaho Power Company and its customers have achieved as a result of DSM
programs (including any savingsj achieved as a result of NEEA programs) for each year
statting with year 1995 through 2005.
RESPONSE TO REQUEST FOR PRODUCTION NO.
The following table details the total amount of estimated energy savings
(expressed as average megawatts) Idaho Power Company and its customers have
achieved as a result of DSM programs (including any savings achieved as a result of
Alliance programs) for each year starting with year 1995 through 2005 as provided in the
company s respective DSM Annual Reports (previously termed ConseNation Plan) filed
with the Commission.
Year
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
005
Annual Energy
. Savings
excluding
Alliance
(Mwa
2.42
Alliance
Reported
Energy
Savings *
(Mwa)
29**
Total
Annual
Energy
Savings
(Mwa)
Noles:
Alliance Savings not available prior to 2004. The Alliance savings based on regional load allocation
percentage of 6.5%.
Preliminary estimate from the Alliance, February 24 2006
IDAHO POWER COMPANY'S RESPONSE TO THE: f-IHST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 9
Friday, September 15, 2006.max
202
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 10
Friday, September 15, 2006.max
203
REQUEST FOR PRODUCTION NO.
Please state the total amount of estimated energy savings (expressed as average
megawatts) Idaho Power Company and its customers are expected to achieve as a result
of DSM programs (including any savings achieved as a result of NEEA programs) in
2006.
RESPONSE TO REQUEST FOR PRODUCTION NO.
Idaho Power Company and its customers are expected to achieve energy savings
of approximately 3.6 average megawatts in 2006 as a r~sult of DSM programs. This
estimate does not include savings achieved as a result of Alliance programs as such
estimate is not available to Idaho Power at this time.
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline , Senior Attorney, Idaho Power
Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page
Friday, September 15, 2006.max
204
REQUEST FOR PRODUCTION NO. 10:
Please provide any studies , reports , memoranda, or similar analyses which
estimate the potential energy or peak demand savings which may be achievable through
DSM programs in Idaho Power s service territory.
RESPONSE TO REQUEST FOR PRODUCTION NO.1 0:
Idaho Power objects to this request on the grounds that it does not specify any
timeframe for producing studies , reports , etc.This objection notwithstanding, the
enclosed CD contains copies of the studies, reports, etc. addressing the Company
most recent estimates of DSM potential.
The response to this request was prepared by Tim Tatum, Senior Analyst, Idaho
Power Company, in consultation with Barton L. Kline, Senior Attorney, Idaho Power
Company.
DATED this 5th day of September, 2006, at Boise , Idaho.
(lJci Y-:--
BARTOJ L. KLINE
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF NW ENERGY COALITION TO IDAHO POWER COMPANY - Page 12
Friday, September 15, 2006,max
. Q,
A..
205
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Steven Weiss. I am employed by the NW Energy Coalition
Coalition ), 219 First Ave. South, Suite 100, Seattle, W A 98104.
HAVE YOU TESTIFIED BEFORE IN THIS PROCEEDING?
Yes. I provided direct testimony.
WHAT IS THE SUBJECT OF YOUR REBUTTAL?
I will respond to the direct testimony of Mr. Reading (Industrial Customers of Idaho
Power, or "ICIP") and Mr. Hessing of the Commission Staffwho address the
testimony of Mr. Said (Idaho Power).
WHAT ARE THE POSITIONS OF THESE PARTIES?
Mr. Reading and Mr. Hessing take similar positions in this docket: that the load
growth adjustment should continue to be based on the marginal cost of power. Mr.
Said, on the other hand, believes that the adjustment should be based on the
embedded cost of serving load, because to do otherwise unfairly penalizes the
Company. Mr. Reading summarizes the issue at the page 2 (line 22) through page 3
(line 1) of his direct testimony: "The basic question being presented to the
Commission is whether the calculation of the load growth adjustment rate should be
changed from a marginal basis to an average basis.
WHATARE THE UNDERLYING REASONS FOR THEIR POSITIONS?
Staff and ICIP make a strong case that the Commission s intent of the load growth
adjustment was to limit the PCA such that it allows the recovery of unpredictable
changes in power supply costs between rate cases due to variations in hydro output
Weiss, Di-Reb
NW Energy Coalition
205a
and fuel costs incurred to serve existing loads. Their position is that the PCA-related
costs of load growth however, should be absorbed by the Company Until those costs
are included in the base rates through a general rate case. To accomplish this goal
Staff and ICIP assert the load growth adjustment must be based on marginal costs, so
that the costs of load growth are completely removed from the PCA and therefore not
recovered by the Company.
Mr. Said, for Idaho Power, also makes a strong case that whatever the intent
of the original peA, the Company should not be penalized "
.. .
for serving new
customer loads while at the same time the Company has an obligation to serve those
customers." (page 11, lines 19-21) He continues that
, "
Just as the Company has no
discretion with regard to QF pricing, the Company also has no discretion not to serve
new customer loads." To accomplish this goal, he argues that the Company should
recover all (subject to 90%110% sharing per the PCA) of the incremental power costs
of serving new load, so the load growth adjustment should include only the embedded
power cost in the rate.
WHAT IS YOUR VIEW OF THESE TWO POSITIONS?
I see these positions as bookends. If adopted, the StafflICIP proposal to set the
adjustment at today s true marginal costs (in the range of$40/MWh) - probably-
would result in Idaho Power losing money as a result of load growth, while the
Company s position-probably-would result in a windfall of revenues above actual
costs.
WHAT IS YOUR CONCERN WITH THE COMMISSION CHOOSING ONE OF
THESE TWO POSITIONS?
Weiss, Di-Reb
NW Energy Coalition
205b
First, there is an equity concern. The mechanism should strive to be neutral and not
unjustly benefit either customers or shareholders. But the Commission is well-aware
of this issue. My second concern was the subject of my direct testimony where I
stressed that
In periodic rate cases, a review of revenue and cost levels occurs, and rates
determined such that the utility can earn that rate of return. But just as
important an element of regulation is how the rate structure, and any trackers
affects the Company between rate cases. (p. 3)
In other words, the Commission s treatment of the load growth adjustment will likely
affect the Company s attitude toward load growth-and thus its attitude toward
conservation. This concern, in my opinion, should be an important criterion for the
Commission s consideration because the Company s attitude toward conservation
should not be addressed obliquely through a complex component of an annual rate
adjuster.
IN THE QUESTION BEFORE LAST, WHY DID YOU EMPHASIZE THE WORD
PROBABL Y"
Because whether load growth benefits or harms the Company is an empirical matter
not a theoretical on , and it depends upon a number of facts. As I explained in detail
in my direct testimony, new load creates both new revenues and new costs. It is not
always readily visible whether the new revenues outweigh the new costs. The only
way that can be determined is by ascertaining the incremental costs and revenues of
the new load. And generally speaking, the incremental costs are usually different
than the amounts embedded in rates.
ARE THERE OTHER COMPLICATIONS?
Weiss, Di-Reb
NW Energy Coalition
205c
Yes. For one thing, the incremental costs ofload growth are different for new load
from an existing customer versus new load from a new customer. For example
according to Idaho Power s response to production requests in this case, the
incremental fixed costs of serving new customers added between the Company s two
most recent rate cases are much higher than the fixed costs per existing customer in
the rate cases. In the IPC-03-13 and -05-28 rate cases, the Company in~icates that
total fixed costs per existing customer were about $395/customer and $422/customer
respectively. The incremental fixed costs of serving customers added to the system
between rate cases is about $7911customer, according to the Company s response.
See Exhibit 303 (Idaho Power response to production requests). The incremental
costs of serving load growth caused by a new customer are higher than the costs for
serving an existing customer due to a number of factors, including line extensions, a
new meter, etc. Second, the incremental costs are customer-specific (or at least class-
specific). Third, Idaho Power s line extension policy will also affect how much
revenue new customers provide. FinaIty, the incremental revenues received from
additional load may be adjusted depending upon the outcome of IPC-04-
(evaluating disincentives to conservation programs).
WHAT CAN YOU CONCLUDE FROM THESE COMPLICATIONS?
Together, these factors do not make it obvious whether any particular KWh of new
load will benefit or hurt the Company s bottom line without further analysis.
Therefore, it is not clear what the Company s incentives will be regarding load
growth of any particular customer class, or between existing and new customers.
Weiss, Di-Reb
. NW Energy Coalition
205d
WHAT PRINCIPLES, THEREFORE, DO YOU BELIEVE THE COMMISSION
SHOULD ADHERE TO IN DETERMINING THIS ISSUE?
It is the Coalition s opinion that:
(1)The Commission should not use the PCA to set conservation policy, because
IPC- E-04-15 case is addressing that issue precisely. In other words, the
Commission should not attempt to set the growth adjustment mechanism too
high (towards the Staffs bookend) as a substitute for a comprehensive
conservation policy.
(2)The correct policy position in this case, when taken together with the outcome
in IPC-04-, should be one where the Company is neutral toward load
growth, neither harmed nor benefited.
Following these principles would be consistent with the goal of decoupling: to
remove the incentive to promote load growth.
HOW WOULD YOU RECOMMEND THE COMMISSION PROCEED?
I would recommend a two-step process. First, the Commission should decide what
goal it is attempting to pursue in this proceeding. The StafflICIP position is that
power costs incurred to serve load growth should not be dealt with in the PCA at all
but should only be addressed via general rate cases. This position is certainly in line
with the original intent of the peA. However, it has the serious unintended
consequence of failing to address the incentive or disincentive that policy would give
the Company between rate cases. With regard to Idaho Power s position, the
Commission should decide whether the Company should recover power costs
incurred to serve load growth on the same basis as it recovers power costs incurred to
Weiss, Di-Reb
NW Energy Coalition
205e
serve system loads reviewed in the most recent rate case. These competing positions
each could potentially undermine the intent of the IPC-O4-15 docket, by creating
incentives that decoupling should neutralize.
The third choice is one that the Coalition recommends. It is that the combined
outcome of this proceeding and IPC-04-15 should result in rate designs that, as
close as possible, make the Company neutral toward changes in load.
WHAT WOULD BE THE SECOND STEP?
Implementation. Assuming that the Commission chose the third option, above, the
Commission would require the Company to develop class-specific incremental net
revenues (net of incremental costs) received from new loads. Each class would have
at least two results: (1) net revenues due to new load from existing customers, and
(2) net revenues due to new load from new customers. In developing these numbers
the Company would have to take into account both the outcome of the decoupling
docket, and its line extension policies. These incremental net revenues would then
become the load growth adjustments the Company would use in calculating its PCA.
I provided examples of this calculation in my direct testimony. The result would be a
. mechanism that would recover neither too much nor too little revenue through the
PCA, and therefore neither benefit nor harm the Company. This, in my opinion is the
only result that would be consistent with a rate design policy of ensuring th
Company s neutrality toward changing loads and changing customer numbers.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
Weiss, Di-Reb
NW Energy Coalition
205f
BARTON L KLINE ISB #1526
LISA D. NORDSTROM ISB #5733
Idaho Power Company
O. Box 70
Boise, Idaho 83707
Phone: [phone]
FAX: [phone]
bkline CW idahopower.com
mmoenCWidahopower.com
Attorneys for Idaho Power Company
Express Mail Address
1221 West Idaho Street
Boise, Idaho 83702
.Y' '
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION OF
. IDAHO POWER COMPANY FOR
MODIFICATION OF THE LOAD
GROWTH ADJUSTMENT RATE WITHIN THE POWER COST
ADJUSTMENT METHODOLOGY
CASE NO. IPC-O6-
IDAHO POWER COMPANY'
RESPONSE TO THE SECOND
PRODUCTION REQUEST OF NW
ENERGY COALITION
COMES NOW, Idaho Power Company ("Idaho Power" or "the Company") and, in
response to the Second Production Request of NW' Energy Coalition to Idaho Power
Company dated September 29, 2006, herewith submits the following information:
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF NW ENERGY COALITION - 1
EXHIBIT
~v3
Thursday, October 19, 2006 (2).max
205g
REQUEST FOR PRODUCTION NO. 11:
" "
Please provide actual-or in their absence, best "estimates-of the average fixed
costs per customer that the Company incurs to serve new customers for each of the three
(3) most recent years that are available. Please break down these costs by customer
class for each class that would be affected by the PCA mechanism at issue in this docket.
RESPONSE TO REQUEST FOR PRODUCTION NO. 11:
Actual fixed costs by customer class are not determined on a regular basis. The
Company's best estimate of the average fixed costs per customer would be derived by
completing a cost-of-service study. The cost-at-service study is one part ot the
analyses completed in preparing for a general rate case. The information from the
cost-at-service studies for the Company s two most recent general rate cases, IPC-
03-13 and IPC-O5-, will provide the Company's "best estimate" for the fixed costs perJ'
customer in the most recent years.
The table below shows the number ot customers and the class fixed costs for
each of the last two general rate case filings. The difference between the two rate
cases would be the Company's best estimate of the average fixed costs per customer
thafthe Company incurs to serve new customers in recent years.
Residential
Customers
Class Fixed Costs
IPC.E.O3-13 IPC.O5-28 Change
334,917 359 802 24 885
$132 442 770 $152,131,314 $19,688,544Incremental Fixed Cost per New Customer $791.
Small Commercial
Customers
Class Fixed Costs
IPC-E-O3-13 IPC-E-O5-28 Change618 34,310 692
$11 545.342 $13.435.685 $1 890,344Incremental Fixed Cost per New Customer $2 731.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF NW ENERGY COALITION - 2
Thursday, October 19, 2006 (2).max
205h
Large Commercial'IPC-E-O3-IPC-E-O5-Change
Customers 213 17,587 374
Class Fixed Costs $45,408,159 $56,109,964 $10,701 205
Incremental Fixed Cost per New Customer $28,612.
Industrial IPC-E-O3-IPC-E-O5-Change
Customers 116 116
Class Fixed Co$ts $17,611,901 $22 696,177 $5,084,276Incremental FIxed Cost per New Customer N/A
Irrigation IPC-E-O3-IPC-E-05-28 Change
Customers 737 15,085 348
Class Fixed Costs $52 606 270 $51 362,375 ($1,243,896)
Incremental Fixed Cost per New Customer ($3,574.41)
Total Company IPC-E-O3-13 IPC-E-O5-28 Change
Customers 400 601 426,899 26,299
Class Fixed Costs $259.615,042 $295,735 516 $36,120,473
Incremental Fixed Cost per New Customer $1,373.
These computations are based on net investment after customer contributions in
aid of construction.
The response to this request was prepared by Mike Youngblood, Pricing Analyst
J' "
, Idaho Power Company, in consultation with Lisa D. Nordstrom, Attorney II, Idaho
Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF NW ENERGY COALITION - 3
Thursday, October 19, 2006 (2).max
205i
REQUEST FOR PRODUCTION NO. 12:
Please provide the same information requested in the previous question net of any
line extension revenues. In calculating the line extension revenues per customer per
year, assume an appropriate amortization time period.
RESPONSE TO REQUEST FOR PRODUCTION NO. 12:
The question references line extension revenues which the Company believes is
a reference to customer contributions in aid of construction. Such contributions are
direct offsets to investment for ratemaking purposes. Please see Response to Request
for Production No. 11.
The response to this request was prepared by Mike Youngblood, Pricing Analyst
, Idaho Power Company, in consultation with Lisa D. Nordstrom, Attorney II, Idaho..J"' ,'
Power Company.. ti
DATED this /.2 day of October, 2006, at Boise, Idaho.
iltit~
LISA D. NaRDS ROM
Attomey for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUESTOF NW ENERGY COALITION. 4
Thursday, October 19, 2006 (2).max
206
Wi th that, Mr. Weiss is available forMR. EDDIE:
cross.
COMMISSIONER SMITH:Mr. Woodbury, do you
have any questions?
Thank you, Madam Chair.MR. WOODBURY:
CROS S - EXAMINAT I ON
BY MR. WOODBURY:
Good afternoon Mr.Weiss.
Good afternoon.
appears from your testimony that you have reviewed
the Commission s PCA methodology order?
(Nods head in an affirmative response.
24806?
Yes.
Did you understand theIs that a correct assumption?
PCA mechanism approved by the Commission to have a limited
purpose?
It seems to.There was argument by the Company that
there was some differences, but I think the clear language
the language is pretty clear that it had a fairly narrow
purpose, yes.
You state in your rebuttal on page 3 that the
Commission s treatment of load growth adj ustment will likely
207
affect the Company s attitude toward load growth and its
atti tude toward conservation.You state on page 5 that the
Staff Industrial Customers ' position is that the power costs
incurred to serve load growth should not be recovered in the
And you conclude that this position is certainly more inPCA.
line with the original intent of the PCA?
Yes.
I agree that we should be conscience of unattended
consequences of Commission s order and track mechanisms.But
you state that -- let's just say -- assuming this original
intent carries forward, what is your perception of how this will
affect the Company I S attitude toward load growth?
Well, as I attempted to explain with examples in my
testimony, the Commission in its decoupling -- and I know this
is not a decoupling docket.But in the decoupling docket, there
seems to be a purpose of that
--
a public interest goal to have
the Company be neutral to load growth so that it is not punished
if it helps conservation.Now , what I see that we re advocating
Tha t the PCA loadthat the same type of approach be used here:
growth adjustment should be set so that the Company is again
And what I pointed out, there is twoneutral to load growth.
types of load growth that occur that really have different
impacts.One is --
--
existing customers?
-- existing customers and new customers, yes.
208
And ifexisting customers, the fixed costs are pretty much set.
existing customers used an extra kwh , the additional fixed cost
should be zero if you really cost it fixed cost.There might be
some tiny, small , incremental cost.But in general the
additional rate, kwh rate, that that existing customer will pay
about 5.9 cents can be used to help offset the added cost of
going out and purchasing power.And so in that sense, the
Company, if it's given
--
if the Company s proposal , for
instance, is accepted and even the Staff's proposal still at
cents or so, still has a benefit to the Company of load growth
of existing customers.Now , for new customers, because the
extra revenue would get is more than the cost they are having to
pay for new power
--
for new customers the situation may be
qui te different and is probably quite different in a daily
request we got from the Company they say that new customers
because you have to add a meter and you have to extend a line
and you have many more additional costs than simply going out
and buying the power
--
that the additional costs that a
--
the
addi tional revenue that a customer, a new customer produces, may
be on a net actually negative or zero
--
that is, the additional
And if thekwh generates additional revenue of about 5.9 cents.
cost of the new line and the power and the meter and the extra
service and the new transformer and all those things add up to
9 or more then the Company actually receives no new revenue
from that
--
no new net revenue.And so in that case they have
209
So the situation isto eat the entire cost of the power cost.
qui te different for those two things.And our argument is to
make the Company neutral , you can t use one load growth
adj ustment.You have to use one load growth adj ustment for
existing customers and a different one for new customer load
growth.And together you want a policy that leaves the Company
neutral as seems to be the Commission
--
or at least many
parties ' goal in the decoupling case.
Okay.
Sorry for that long explanation.
Do I understand your position to be that if the
Commission were to go forward factoring PCA out that the Company
would be more favorably inclined toward existing customers as
opposed to new customers?
Again, the actualYes.That's what it looks like.
But I think it's pretty clearnumber
--
these aren t actuals.
For new customers, it's probablyfor existing customers.
It's on the edge whether a new customer s in kwhmarginal.
actually helps the Company or not.
At you state if inThe conclusion that you arrive:
fact this were a penalty in place on the way to PCA presently
operates
--
and to the extent that the Company says that it
that is in intui ti ve
--
that perhaps would be investing more in
And so your conclusion is thatDSM and it is not doing that.
company is not being penalized enough?Is that what you are
210
saying?
mean the
feel that the Company
word penalized goes a little too far.
should be neutral, not be penali zed.
shouldn t be punished for load growth , but it should be neutral
to load growth.And so right now we think at least for existing
customers that they are benefitting from load growth.And
that's one of the reasons why they haven t invested very
strongly.They claim
--
the Company s claim that when loads
grow , they are eating.That's basically their testimony; and,
therefore, they have to have a lower load growth adj ustment
number.If that were true they would be doing
--
they would
madly doing conservation.Except for the last year or so when
they ve ramped up, and that's very good, they haven t done gang
busters on conservation.So they must be making money on load
growth.
MR. WOODBURY:Okay.Thank you, Mr. Weiss.
Madam Chair , no further questions.
COMMISSIONER SMITH:Questions, Mr. Thompson?
MR. THOMPSON:The Industrial Customers have no
questions for Mr. Weiss.
COMMISSONER SMITH:Mr. Kline?
MR. KLINE:I do have a couple of questions,
Madam Chairman.
CROSS-EXAMINATION
211
BY MR. KLINE:
Mr. Weiss, m -- I guess a little bit confused.
I need to ask a few questions to make sure I understand the
Coali tion ' s position at the end here.I would like you to take
a look at your rebuttal testimony on page And on the top of
the page there , you summarize the Coalition s position on the
correct policy to come out of this proceeding.And looking on
line 4 there, you say the Commission should not use the PCA to
set conservation policy because the 04-15 case
--
and that's the
decoupling; correct?
Yes.
--
is addressing that issue precisely.And then you
go on to say that the Commission should not attempt to set the
load growth adj ustment mechanism too high toward the Staff'
bookend as a substitute for a comprehensive conservation policy.
Let me go on here.And then No., we will get your principles
down and then I will have a couple of questions for you.The
second principle that you ve described there
--
and I will just
read it because it's short
--
the correct policy position in
this case when taken together with the outcome in the
IPC-E-04-15 case should be one where the Company is neutral
toward load growth , neither harmed nor benefitted.
Now , my question to you is:In order to
achieve that state of neutrality, you are proposing three things
212
as I see it.First of all, you think that the Commission in
this case should be considering what's going to come out of the
decoupling case?
Yes.
I think you are also saying we should look at the line
extension policy?
Yes.
And the third thing is to look at rate designs which
is what you kind of described in your testimony.Do all those
things need to be together
--
done together to come up with the
right decision
--
is that your testimony?
Yes, it is.So that
--
because all of those things
affect the revenues and the costs that the Company collects or
bears, you have to look at all of those factors to adj ust the
load growth
--
if the load growth is the last adjustment you are
doing.To make the Company neutral, you are going to have to
take into account all of those factors, yes.
So I would assume from that then , Mr. Weiss, that
re not going to get that done in this case.Is that your
testimony?
That is true.And my recommendation is that the
Commission would first decide that's what it wants to do because
that's a maj or issue here.But if that is, and I think it
should be something they should do, because over in Decoupling
they seem to be wanting to maintain neutrality; and then the
213
second step would be to -- probably collaborative with the
Staff , the parties in this case -- look at the actual numbers
and come up with a policy, some load growth adj ustment numbers,
that do make the Company neutral.
I believe in your testimony you also indicate that we
need to look at the Company s line extension policy as well;
correct?
Probably.Because often new load growth
--
some of
the cost of new load growth are paid for my -- through the line
extension policies.So one would have not reset it or not redo
it -- I'm not saying that, but just take into account when you
look at how a new customer revenues and costs change when a new
customer is put on the system.
MR. KLINE:Okay, I believe I understand.
Than k you.
That's all I have.
COMMISSIONER SMITH:Any questions from the
Commissioners?
(No response.
COMMISSIONER SMITH:I just have one.
CROSS-EXAMINATION
BY COMMISSIONER SMITH:
Are you engaged or involved at all in the decoupling
214
case?
m not.
THE WITNESS:Is Northwest?
It's okay.It was directed to you personally.
Oh.m involved in the Avista, puget Sound, and
Cascade Natural Gas Decoupling in Washington right now, and was
in the Northwest Natural Decoupling Case in Oregon.
In any of your discussions with the Company and during
this case, did the Decoupling case ever come up with any link
between them?
In our discussions with the Company?I didn t have
discussions with the Company preparing the testimony.
All right.Thank you.COMMISSIONER SMITH:
Any redirect, Mr. Woodbury?
MR. WOODBURY:I have no redirect.
COMMISSIONER SMITH:Thank you very much.
MR. WOODBURY:Thank you, Madam Chair.
Staff would call Keith Hessing.
KEITH HESSING,
Produced as a witness at the instance of the Joint Applicants,
being first duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
215
BY MR. WOODBURY:
Would you please state your full name and spell your
last name for the record?
My name is Keith Hessing.My last name is spelled,
H- E-S-S- I -N-G.
staff.
And to whom to you work and in what capacity?
m employed by the Idaho Public Utilities Commission
m a staff engineer.
And in that capacity did you have occasion to
prefilled in this case direct testimony consisting of 16 pages
and three exhibits, Exhibits 101 through 103?
Yes.
And have you had the opportunity to review that
testimony and those exists prior to this hearing?
Yes.
And was it necessary to make any changes or
corrections?
No.
If I were to ask you the questions set forth in your
testimony, would your answers be the same?
They would.
MR. WOODBURY:Madam Chair, I would ask that
the testimony be spread on the record as its read and exhibits
be marked.And I would present Mr. Hessing for
cross-examination.
216
COMMISSIONER SMITH:If there is no
objection, we will spread the pre-filed testimony of Mr. Hessing
upon the record as its read and identify Exhibits 101 , 102, and
103.
(The following pre-filed direct and
rebuttal testimony of Keith Hessing is spread upon the record.
217
please state your name and business address
for the record.
My name is Keith D. Hessing and my business
address is 472 West Washington Street , Boise , Idaho.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
Commission as a Public Utilities Engineer.
What is your educational and experience
background?
I am a Registered Professional Engineer in the
State of Idaho.I received a Bachelor of Science Degree in
Civil Engineering from the University of Idaho in 1974.
Since then , I worked six years for the Idaho Department of
Water Resources, and two years for Morrison-Knudsen.
have been continuously employed at the Commission since
August 1983.
As a member of the Commission Staff , my
prlmary areas of responsibility have been electric utility
power supply, revenue allocation and rate design.
What is the purpose of your testimony in this
proceeding?
I will address the Company s filing to reduce
the load growth adjustment multiplier, sometimes called the
Expense Adjustment Rate for Growth (EARG), which is used in
the Power Cost Adjustment (PCA) true up calculation.
CASE NO. IPC-06-9/14/06
HESSING, K (Di)
STAFF
218
As a member of the Commission Staff have you
worked on Idaho Power Company s annual PCA mechanism since
its inception in 1992?
Yes I have.
Wha t is the purpose of the Company s PCA?
The PCA was created to address the problem of
fluctuating water conditions that caused widely varying
power supply costs.
What does the load growth adj ustment
multiplier do in the PCA true up calculation?
When the Company s load grows between general
rate cases the power supply costs of serving that load
growth are captured in the PCA true up mechanism.All
part of those costs are removed from the mechanism by
applying the multiplier to the amount of load growth and
removlng the resulting cost from actual power supply costs
incurred.Any costs removed in this manner are not
available for deferral as part of the PCA true up and
therefore, will not be recovered in PCA rates.
Please provide an example of this calculation
and the associated adjustment.
Staff Exhibit No. 101 , pages 1 and 2, shows
the PCA true up calculations from the Company ' s last PCA
case, Case No. IPC-06-The expense adj ustment
associated with load growth for the month of April 2005
CASE NO. IPC-06-
9/14/06
HESSING , K (Di)
STAFF
219
calculated on lines 9 through 12.Lines 9 and 10 show the
actual load and the normalized load.Line 11 calculates
the load growth and line 12 is the product of the load
growth and the load growth adj ustment mul tipl ier.
( 1 , 0 02 , 52 8 MWh - 9 74 , 0 6 6 MWh = 2 8 , 4 62 MWh)(28,462 MWh x
1 6 . 8 4 $ / MWh = $ 4 7 9 , 3 0 0 )Line 12 shows the calculated
expense adjustment for April to be $479,300.This amount
is carried to line 23 where it is shown as a reduction to
actual power supply expense.Page 2 , lines 12 and 23,
shows the total adj ustment for the PCA year to be
$10 291,160.
What does the Commission need to decide in
thi s proceeding?
There are two parts to the decision that the
commission is being asked to make in this case.The first
part is a matter of policy.Should Idaho Power Company be
allowed to recover the variable costs of power supply
associated with load growth that occur between general rate
cases through the PCA mechanism?The second question
follows.What is the appropriate load growth adjustment
multiplier that accomplishes the policy decision?
Please provide some history and background
information on Idaho Power s PCA mechanism.
Prior to PCA implementation , if the Company
load grew , the Company sold the additional energy at
CASE NO. IPC-06-
9/14/06
HESSING, K (Di)
STAFF
220
approved retail rates and the Company incurred costs in
serving the new load.The revenues and costs associated
wi th serving load growth were not necessarily balanced.
costs exceeded revenues, the Company could file a general
rate case to increase rates to cover the costs on a
prospective basis.I f the cost of serving load growth did
not exceed the costs embedded in rates, no rate increase
would be justified.
Please discuss Idaho Power Company s initial
PCA filing.
Idaho Power Company filed for a PCA in 1992
and it was approved and implemented in 1993 with some
modification.Idaho Power s 1992 PCA filing was made to
address the problem of fluctuating water conditions that
caused widely varying power supply costs.When water
condi tions were poor , power supply costs were higher than
what was authorized for recovery in rates.A general rate
case provided no relief from high power supply costs
associated with below normal water conditions since water
condi tions and power supply costs are normalized in a
general rate case.
Staff observed that in the Company s original
PCA proposal ! variations from the normalized costs of power
supply were due to water conditions and power supply cost
increases caused by load growth.Staff believed that load
CASE NO. IPC-E- 06 - 89/14/06
HESSING! K (Di)
STAFF
221
growth costs could be significant and that load growth
costs were not the kind of costs that the PCA should
recover.Staff proposed a load growth adj ustment mechanism
in the PCA that removed actual power supply costs
associated with load growth by multiplying the amount of
load growth by the marginal cost of power supply and
subtracting the result from actual power supply costs.
Staff approximated the marginal cost of power supply as
16.84 $/MWh which was the average of the variable costs of
Valmy and Boardman, the Company s two highest operating
cost resources at that time.In that case Staff also
argued that without the adjustment the Company would double
recover the normalized cost of power supply h€cause it was
included in base rates and in actual booked power supply
costs that accumulated in the PCA true up mechanism.
The Commission accepted Staff's load growth
adj ustment to the PCA in its final Order.
We find that the net power supply costs
associated with serving differences in load
between normal and actual should be removed
from the PCA. We adopt the method proposed by
Staf f for making this adj ustment; it was the
only method proposed. We agree with Staff that
Idaho Power s proposal unduly broadens the scope
of this proceeding, which is simply to devise a
mechanism for the recovery of power supply costs
that include the sum of fuel costs, non- firm
energy purchases and CSPP costs less revenues
from non-firm energy sales and FMC secondary
sales. Idaho Power s proposed PCA allows it to
double recover fuel costs associated with load
growth which , essentially, offsets the cost
of constructing additional plant. We recognize
CASE NO. IPC-E- 06 - 8
9/14/06
HESSING , K (Di)
STAFF
222
and support the Company s right to recover
costs associated with prudent plant additions.
Our decision to not allow a PCA mechanism to
recover costs to offset legitimate plant costs
caused by load growth in no way prevents the
Company from recovering these costs in traditional
ratemaking proceedings. A PCA is not intended
to replace the prudency review process inherent
in a general rate case. (Order No. 24806 , pg. 20,
Emphasis added) .
The load growth adj ustment has been made in
every PCA true up calculation since the PCA was
established.Staff's intent from the initial PCA cas~ was
to update the load growth adj ustment mul tipl ier to reflect
the average marginal cost of power supply as part of each
general rate case.So doing would continue to remove the
variable power supply costs associated with load growth
that accumulate in the PCA at the marginal cost of
supplying power.
Please discuss Staff's reVlew of the power
supply cost load growth issue the next time it came up.
The Company s next general rate case was Case
No. IPC-94-In that case Staff used the difference in
power supply costs from two different power supply model
runs to determine the marginal cost of power supply.The
only difference in the two power supply model runs was that
the second run was designed to meet an incrementally larger
load.From those results a marginal cost of power supply
of 16.22 $/MWh was calculated.(Case No. IPC-03-
Hessing Direct, pg. 21 , line 7).This result was
CASE NO. IPC-06-9/14/06
HESSING, K (Di)
STAFF
223
sufficiently close to the 16.84 $/MWh already in use that
Staff proposed no change in the marginal cost multiplier by
entering no testimony concerning this issue.No other
party proposed that the multiplier change.The case
contained no testimony concerning the multiplier.
The power supply cost associated with load
growth was an issue in the Company s next general rate
case.Please discuss the case in that context.
The Company s next general rate case was the
IPC-E- 03 -13 Case filed nearly 10 years later.In that case
the Company proposed to reduce the multiplier , that it
called the Expense Adjustment Rate for Growth or EARG, to
13.98 or 7.30 $/MWh based on two different interpretations
of the purpose of the adj ustment .In that case Staff did
not use its own calculation of the marginal cost of power
supply but used the "Marginal Cost of Energy " from Idaho
Power s response to Request No.3 0 of the Idaho Irrigation
Pumpers Association.The amount from the study was 27.
$/MWh which became 29.41 $/MWh when 8.9% losses were
included.Based on those results Staff proposed a 29.
$/MWh marginal cost multiplier.(Case No. IPC-03-
Hessing Direct , pg. 20 , line 16)
The Commission did not decide the magnitude of
the multiplier in that case but set the issue aside along
with several other issues to be settled by the parties.
CASE NO. IPC-06-9/14/06 HESSING, K (Di)
STAFF
224
the give and take of settlement negotiations the multiplier
stayed at 16.84 $/MWh but was, by specific settlement
language, to be reevaluated in the next general rate case.
The settlement was accepted by the Commission.
Please discuss the power supply cost of load
growth issue that was part of the Company s most recent
general rate case.
The Company s next general rate case was Case
No. IPC-05-28.This entire case was settled and the
settlement was accepted by the Commission.During
settlement discussions the Staff and Company differed
substantially on the magnitude of the PCA load growth
adj ustment mul tiplier.The settlement called for a
separate proceeding t6 decide the issue.This is that
proceeding.
Are Idaho s other regulated electric utilities
allowed to track and defer differences between normal and
actual power supply costs associated with load growth that
occur between general rate cases for later recovery?
Rocky Mountain Power has no PCA and no
tracking mechanism that allows it to track and recover
these costs between rate cases.Avista Utilities has a PCA
that is very similar to Idaho Power Its purpose is to
track hydro conditions as they affect power supply costs.
By Commission, Order Avista removes power supply costs
CASE NO. IPC-06-
9/14/06
HESSING, K (Di)
STAFF
225
associated with load growth that occur between rate cases
by multiplying load growth by the marginal cost of power
supply and subtracting that amount from actual power supply
costs.In Case No. AVU-E- 04 -1 the Commission established
the load growth adjustment multiplier as 36.38 $/MWh.
(Order No. 29602 , pg. 46)
Do you believe that Idaho Power Company should
be allowed to recover the power supply costs of load growth
through the PCA mechanism between rate cases?
No, I do not.Staff's position is the same as
it was in the initial PCA case previously discussed in this
testimony.It is also clear that the Commission ordered
PCA that went into effect in 1993 was very specifically
designed to remove the power supply costs of load growth.
Was the Company required to absorb the power
supply costs of load growth between rate cases prior to PCA
approval?
The Commission s decision to remove loadYes.
growth costs leaves the Company in the same position that
it was in prior to the PCA.The Company receives revenue
from sales of the growing load and has costs associated
wi th serving the new load.If costs are more than revenues
the Company can do what it has always done, make a rate
filing to recover the difference prospectively.
Do any other costs, established during a rate
CASE NO. IPC-06-
9/14/06
HESSING, K (Di)
STAFF
226
case using a historic test year, vary in between rate
cases?
Yes.Cost differences occur in virtually
hundreds of utility accounts and must be trued up in a
general rate case unless special treatment is approved by
the Commission.
I s ther~ another reason that you oppose
recoverlng the costs of load growth between rate cases?
Yes.It does not always follow that the costs
of serving new load exceed the revenues derived from
supplying new load.Generation and transmission
investments are made in large increments.A single
generation or transmission proj ect may supply tens of
thousands of new customers.This means that some of the
costs that may be included in base rates are not incurred
when load grows yet the Company receives revenue from the
application of existing rates that may more than cover
these embedded costs.
I s there a long- standing reason why the actual
costs associated with individual accounts or groups of
accounts are not simply tracked through with annual rate
adjustments between general rate cases?
In any given year the costs associatedYes.
with some accounts may increase while the costs associated
wi th other accounts may decrease.It is not fair or
CASE NO. IPC-06-
9/14/06
HESSING , K (Di)
STAFF
227
reasonable to exclusively select one group of costs or the
other.The only fair way to establish rates is to look at
all the utilities costs together as is done in a general
rate case.
Is there another difference between the
variable power supply costs associated with load growth and
the variable power supply cost associated with fluctuating
water conditions?
Yes.Load growth related power supply costs
are addressed in a general rate case but power supply costs
associated with abnormal water conditions are not.In a
general rate case abnormal water conditions and their
associted costs are normalized out.
Do you .have another concern with allowing the
Company to recover the variable cost of power supply
associated with load growth between rate cases?
This concern pits demand side managementYes.
(DSM) programs against the two very different revenue
streams that the Company could realize depending on the
Commission s decision in this case.I would submit that
the Company s incentive to grow load , or the disincentive
for effective demand side management, is greatly increased
when the Company receives the retail revenue from increased
load and PCA reimbursement for power supply costs on the
margin as opposed to just the retail revenue.In the first
CASE NO. IPC-06-
9/14/06
HESSING, K (Di)
STAFF
228
case, for example, the Company could receive 84 $/MWh (8.
~ /kWh)This could occur if retailfor growing load.
revenue were 55 $/MWh and the marginal cost of power supply
were 41 $/MWh which becomes 29 $/MWh when it is
jurisdictionally allocated and shared before becoming a PCA
rate ((41-81) *941*90=29) .This scenario assumes that
the Commission s decision in this case allows the Company
to recover load growth power supply costs on the margin
between rate cases.If the Commission does not allow this
recovery then the Company receives only the retail revenue
of 55 $/MWh.The incentive for growing load, not
implementing effective DSM, is substantial if the Company
receives 84 $ /MWh in revenues from load growth.
Does the Company currently have another filing
before the Commission that is intended to remove the DSM
disincentive that you have just described?
The Company does currently have another filing
before the Commission , Case No. IPC-E- 04 -15, aimed at
removing DSM disincentives , but it does not address the DSM
disincentive that would be created in this case by the
Company s proposal.In fact , because this other filing
looks at use per customer, it is quite possible for PCA
load to grow and use per customer to decline in which case
the Company would receive additional revenues between rate
cases from both adj ustment mechanisms.
CASE NO. IPC-06-
9/14/06
HESSING 1 K (Di)
STAFF
229
What are the rate choices that the Commission
could make for the load growth multiplier?
If the Commission decides to allow the Company
to recover the variable cost of power supply associated
wi th load growth between rate cases, then only the embedded
variable cost of power supply should be subtracted from
actual power supply costs in the PCA mechanism.This is
what the Company proposes to do with its 6.81 $/MWh
multiplier.The application of this mul tiplier prevents
the double counting of embedded power supply costs.
If it is the Commission s decision to not
allow the Company to recover the variable power supply
costs associated with load growth through the PCA between
general rate cases I then the adj ustment should be made
using the variable cost of power supply on the margin.
Staff's most recent calculation of this amount is 40.
$/MWh.The application of this multiplier prevents the
double counting of embedded power supply costs and also
prevents the PCA recovery of the power supply costs
associated with load growth between rate cases.The
calculation of this number is shown on Staff Exhibit No.
102.The number comes from two power supply model runs
that differ by an increment of load.The base run is the
model run presented by the Company in its most recent
general rate case, Case No. IPC-05-28.
CASE NO. IPC-06-
9/14/06
HESSING, K (Di)
STAFF
230
Do the Company s proposed number and the
Staff's proposed number come from the same power supply
mode 1 ?
Yes.Both numbers come from the Company
Aurora power supply model.
Have you prepared an Exhibit that estimates
the impacts of the various load growth adjustment
multipliers?
Yes I have.Staff Exhibit No.1 03 shows
estimated annual load growth adjustments assuming a 40 MWa
growth in load.Column (3) shows the annual adjustment at
the current load growth adjustment rate of 16.84 $/MWh to
be $5.9 million per year, Column (4) shows the adjustment
at the Company proposed rate of 6.81 $/MWh to be $2.
million per year and Column (5) shows the amount of the
adjustment at the Staff proposed rate of 40.87 $/MWh to be
$14.3 million per year.This load growth adj ustment amount
is cumulative between general rate cases until the base
load is reestablished.For example, under Staff'
proposal , the adjustment is estimated to be $28.6 million
if the Company goes two years between general rate cases.
Because these amounts can get quite large in a very few
years, especially if Staff's load growth adj ustment rate is
accepted , this could be a significant factor affecting the
frequency of Company rate case filings.
CASE NO. IPC-06-
9/14/06
HESSING, K (Di)
STAFF
231
A portion of the PCA rate that the Commission
puts in place each year comes from the PCA forecast.How
lS the PCA forecast affected by the Company s proposal?
The Company is not proposing to change the
forecast.Therefore, stream flow runoff forecasts would
continue to be used to predict variations from normal power
supply costs that would be expected under th~ normalized
load.The problem is that under the Company s proposal the
true up portion of the PCA is not tracking power supply
costs under normalized load conditions but power supply
costs under actual load conditions which includes the power
supply costs associated with load growth that accumulate at
the marginal cost of power supply.The result is that when
load grows normal water conditions produce an increase in
PCA rates and , gobd water conditions that should produce
PCA rate reductions, could actually produce rate ' increases.
This occurs because the true up mechanism is capturing
costs associated with load growth rather than water
condi tions.The problem grows with time between general
rate cases because load growth costs accumulate from year
to year as previously discussed.Under the Company
proposal the PCA forecast based on water conditions would
never be accurate and the customer prlce signal value of
the forecast is significantly reduced if not completely
lost.
CASE NO. IPC-06-
9/14/06
HESSING , K (Di)
STAFF
232
Does the Staff's position establish a bright
line that identifies the purpose of the PCA?
Yes it does.It establishes the primary
purpose of the PCA as a mechanism that tracks abnormal
power supply costs primarily associated with variations in
water conditions and market prices for a Commission
approved normalized fixed load.
What is the situation if the Company
position is accepted by the Commission?
Acceptance of the Company s position
establishes a precedent for the recovery of costs between
rate cases that could otherwise be captured in a general
rate case and addressed with all other costs.
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NO. IPC-06-
9/14/06
HESSING , K (Di)
STAFF
DESCRIPTION
3 PCA Revenue
4 Normalized Idaho Jurisd. Sales
5 Forecast Rate
6 Revenue
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted
10 Normalized Firm Load
11 Load Chan
12 Expense Adjustment (cg)16.84)
14 Non-QF PCA
15 ACTUAL:
16 BPA Water Option Agreement
17 Cloud Seeding Program
18 Fuel Expense - Coal
19 Fuel Expense - Danskin
20 Fuel Expense - Bennett Mountain
21 Non-Firm Purchases
22 Surplus Sales
23 Ex ense Ad ustment (cg)16.24 Sub-Total
26 BASE:
27 Fuel Expense - Coal
28 Fuel Expense - Danskin
29 Fuel Expense - Bennett Mountain
30 Non-Firm Purchases
31 Surplus Sales
32 Sur lus Sales Adder33 Sub-Total
35 Change From Base
36 Deferral (Shared and Aliocated)
38 QF Deferral
39 Actual (includes Net Metering)
40 Base
42 Change From Base
43 Deferral (Allocated)
45 Intervenor Funding
46 Credit From IDACORP Energy
47 Settlement Agreement (ON 29600)
48 Bennett Mtn. Credit (ON 29790)
49 Total Deferral (-6+36+43+45+46+47+48;
51 Principal Balances
52 Beginning Balance
53 Amount Deferred
54 Ending Balance
56 Interest Balances
57 Accrual thru Prior Month
58 Interest cg) 2% per Year
59 Prior Month's Interest Ad
60 Total Current Month Interest
61 interest Accrued to Date
62 Balance (True-Up & Interest)
64 True-Up of the True-
65 True-Up Revenues66 True Up Rates67 Actual Idaho Sales68 Total
70 Beginning Balance
71 Adjustments per ON 2979372 Fuel Expense Adjustment73 Intervenor Funding
74 Irri ation Lost Revenues ON 2966975 Sub-Total
76 Interest cg) 2% per Year
77 Revenue Applied to Interest
78 Revenue Applied to Balance
79 True-Up of the True-Up Balance
Units
MWh
mlKWh
TRUE-UP CALCULATIONS FOR 2005 - 2006
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-06-
Commission Decision
2005
APR
862,931
2.499
156,465
MWh
MWh
MWh
002 528
974 066
28,462
(479 300)
788
527,289
333 725
098 341
(5,434 762)
479 300
103 080
108 200
264 800
000
187 500)
786 500)
889 580
528 585
131 025
815 766
(684 741 )
(644 341)
(166 667)
(804 167)
756 946
756 946
756 946
757 003
2005
MAY
881 064
2.499
201,779
020 216
142 316
122 100
056 164
256 201
516 168
114 958
169 001
500 338
(18 370 968)
056 164
(758 138)
800 600
278 500
664 100
(6,566 900)
176 300
934,438)
638 276)
605 364
160 399
(555 035)
(522 288)
(166 667)
(804 167)
333 176)
756 946
333 176
576 230)
262
231
287
569 943)
2005
JUN
002,040
288
296 748
272 295
258 858
13,437
(226 279)
878 317
114 108
654,700
234 832
(14 206 066)
226 279
6,449 612
344,900
275 700
931 000
558 900)
992 700
1,456 912
233 859
359 151
508 847
(149 696)
(140 864)
(166 667)
(804 167)
986)
178 571 )
576 230)
178 571
754 801 )
287
627)
627)
660
751 141)
2005
JUL
185 074
288
081 597
641 692
1,491 793
149 899
524 299)
168 717
191,888
1,480 609
198 870
(11 376 337)
524 299
139,448
714 800
279 600
335 100
385,400)
944 100
195 348
9,481 340
810 850
702 897
107 953
101 584
(166 667)
(804 167)
986)
526 508
754 801)
526 508
228 293)
660
591)
595)
935
234 228)
2005
AUG
303,702
288
590 274
538 801
1,424 633
114 168
922 589)
963 765
274
450 682
146 513
360 602)
922 589
368 042
721 300
280 000
842 900
371 000)
473 200
894 842
767 542
6,490 347
6,422 258
089
071
(166 667)
(804 167)
986)
266 520
228 293)
266 520
038 227
935)
714)
145
569)
504
028 722
2005
SEPT
164 116
288
991 729
190 787
179 173
11,614
(195 580)
093 240
(639 672)
(875 540)
710,413
(12 538 689)
195 580
554 171
8,446 500
264 800
480 800
702 300)
3,489 800
064 371
135 916
038 841
081 395
(42,554)
(40,D43)
(166 667)
(804 167)
986)
(870 676)
038 227
870 676
167 551
504)
064
105
959
545
163 005
~lkWh
kWh
3707 0.3707 0.4024 0.4024 0.4024 0.4024
840 704 656 939 127 871 1 054 848 703 1 325 929 728 1 309 551 663 1 137 579,165
164 039 3 002 187 2 701 380 2 176,780 2,406 699 2 173 844
921 564
(250 506)
671 058
118
118
102 921
568 138
Note: Negative amounts indicate benefit to ratepayers
U\kh",i"",,"O607\Com,~y C".\TRUE UPS & RATES 9/12/2006 KDH
568 138
(45 675)
13,482 882
005 345
342
342
923 845
081 500
081 500
081 500
73,469
73,469
627 910
453 589
41,453 589
453 589
089
089
107 691
345 898
345 898
345 898
576
576
341 123
004 775
004 775
004 775
61,675
675
112 169
892 606
233
2005
OCT
925 105
288
966 850
051 573
055 943
370
591
374 911
285 872
783
7,4 77 ,280
(13 902 800)
591
315 636
727 700
272,300
700
982 500)
053 200
737 564)
(1,471 543)
068 572
792 830
(724 258)
(681 526)
(166 667)
(804 167)
986)
094 739)
167 551
094 739
927 189)
545)
613
603
943
928 131)
0.4024
975 839 218
1,723 273
892 606
892 606
154
154
665 118
227,488
Exhibit No. 101
Case No. IPC-06-
K. Hessing, Staff
9/14/06 Page 1 of
DESCRIPTION
3 PCA Revenue
4 Normalized Idaho Jurlsd. Sales
5 Forecast Rate
6 Revenue
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted
10 Normalized Firm Load
11 Load Chan
12 Expense Adjustment ((QJ16.84)
14 Non-QF PCA
15 ACTUAL:
16 BPA Water Option Agreement
17 Cloud Seeding Program
18 Fuel Expense - Coal
19 Fuel Expense - Danskin
20 Fuel Expense - Bennett Mountain
21 Non-Firm Purchases
22 Surplus Sales
23 Ex ense Ad ustment ((QJ16.
24 Sub-Total
26 BASE:
27 Fuel Expense - Coal
28 Fuel Expense- Danskin
29 Fuel Expense - Bennett Mountain
30 Non-Firm Purchases
31 Surplus Sales
32 Sur lus Sales Adder
33 Sub-Total
35 Change From Base
36 Deferral (Shared and Allocated)
38 OF Deferral
39 Actual (includes Net Metering)
40 Base
42 Change From Base
43 Deferral (Allocated)
45 Intervenor Funding
46 Credit From IDACORP Energy
47 Settlement Agreement (ON 29600)
48 Bennett Mtn. Credit (ON 29790)
49 Total Deferral (-6+36+43+45+46+47+48)
51 Principal Balances
52 Beginning Balance
53 Amount Deferred
54 Ending Balance
56 Interest Balances
57 Accrual thru Prior Month
58 Interest (QJ 2% per Year
59 Prior Month's Interest Ad
60 Total Current Month Interest
61 Interest Accrued to Date
62 Balance (True-Up & Interest)
64 True-Up of the True-
65 True-Up Revenues66 True Up Rates67 Actual Idaho Sales68 Total
70 Beginning Balance
71 Adjustments per ON 2979372 Fuei Expense Adjustment73 Intervenor Funding
74 Irri ation Lost Revenues ON 29669
75 Sub-Total
76 Interest (QJ 2% per Year
77 Revenue Applied to Interest
78 Revenue Applied to Balance
79 True-Up of the True-Up Balance
TRUE-UP CALCULATIONS FOR 2005 - 2006
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-06-
Commission Decision
Units
MWh
mlKWh
2005
NOV
885 609
288
797,491
MWh
MWh
MWh
137 344
079 817
527
(968 755)
798 142
377 898
759
196 111
728 267)
968 755
675 887
8,445 200
264 700
610 900
(1,414 700)
906 100
769 787
192 633
095 280
204 739
(109,459)
(103 001)
(166 667)
(804 167)
986)
682 679)
927 189)
682 679
609 867)
(943)
212)
212)
155
619 022)
2005
DEC
965 920
288
141 865
354 735
220,489
134 246
260 703)
414 022
902 700
314 726
523 632
754 148
(15 037 170)
260 703
611 354
727 000
272 800
884 100
357,300)
526 600
084 754
315 978
315 598
193 531
122 067
114 865
(166 666)
(804 167)
986)
314 159
609 867)
314 159
704 291
155)
(11 016)
(11 036)
191
684 100
2006
JAN
043 993
288
4,476 642
244 146
207 127
019
(623,400)
140 182
468 720
885
790
190 694
(33,421 590)
623,400
175 719)
8,460 000
272 500
397 900
811 600)
318 800
(5,494 519)
653 308)
792,655
164 012
628 643
591 553
(804 167)
986)
346 550)
704 291
346 550
642 258)
(20 191)
174
175
016
656 274)
2006
FEB
968 236
288
151 796
124 755
032 883
872
547 124)
137 597
178 162
089
480
292 649
(32,412 950)
547 124
(12 263 097)
371 000
257 500
700
681 800)
400
(12 298 497)
(10,415 597)
707,472
073 610
633 862
596 464
(804 167)
986)
(14 779 081)
642 258)
779 081
(20,421 340)
(14 016)
(9,404)
(9,403)
23,419
(20 444,758)
~lkWh
kWh
0.4024 0.4024 0.4024 0.4024
890,496,444 1 005,408 010 1 078 920 738 1 016 643 093
568 690 1 889 864 1 988 372 1 739 243
227,488
227,488
379
379
513 310
714 178
Note: Negative amounts indicate benefit to ratepayers
Ulkhmio'pcoO6O7\Comp"" C.,,'TRUE UPS & RATES 9112/2006 KDH
714 178
714 178
857
857
837 007
877 170
877 170
877 170
795
795
938 577
938 593
938 593
938 593
564
564
692 679
245 915
2006
MAR
909 048
288
897 998
139 815
040,475
340
672 886)
102 305
762 059
0)6
205 921
12,443 565
(37,458 046)
672 886
(17 588 065)
282 200
273,400
700
074 900)
(441 600)
(17 146,465)
(14 521 342)
2,497 723
292 773
204 950
192 858
(804 167)
986)
(19 034 634)
(20,421 340)
034 634
(39,455 973)
(23,419)
(34 036)
276
(34 312)
730
(39 513 704)
234
TOTALS
096 838
751 234
14,718 687
107 573
611 114
(10 291 160)
108 094
100 632 189
992,041
995 540
188 243 754
(211 248 247)
291 160
72,432,211
149,400
256600
376 900
(63 094 800)
688 100
744 111
955 787
912,878
46,413 057
(500,179)
(470 669)
500 000)
650 000)
(39 858)
(39,455 973)
39,455 973
(57,488)
242
(57 730)
(39 513 704)
0.4024
954 795 701 12 529 844 990
776 360 26 310 731
245 915
245 915
743
43,743
732 617
513 298
416 271,416
(250 506)
(45 675)
13,482 882
429,458 117
715 764
594 967
513 298
Exhibit No. 101
Case No. IPC-06-
K. Hessing, Staff
9/14/06 Page2of2
235
IDAHO POWER COMPANY
CASE NO. IPC-06-
STAFF MARGINAL COST CALCULATION
IPC-05-28 AURORA POWER SUPPLY BASE
Units Annual
IPC-05-28 Energy MWh 866 817.
IPC-05-28 Cost 975.
IPC-05-28 +10 MWa Energy MWh 954 391.
IPC-05-28 +10 MWa Cost 554.
Energy Difference MWh 573.
Cost Diffeence 578.
Marginal Cost $/MWh 40.
Exhibit No. 102
Case No. IPC-06-
K. Hessing, Staff
9/14/06
236
IDAHO POWER COMPANY
CASE NO. IPC-O6-
STAFF LOAD GROWTH ADJUSTMENT CALCULATIONS
(1)(2)(3)(4)(5)
Description Units Load Load Load
Growth Growth Growth
Adjustment Adjustment Adjustment
(ill 16.84 (ill 6.81 (ill 40.87
Load Growth Adjustment Rate $/MWh 16.40.
Load Growth Energy (40 MWa)MWh 350,400 350,400 350,400
Load Growth Adjustment 900 736 386 224 320 848
Exhibit No. 103
Case No. IPC-06-
K. Hessing, Staff
9/14/06
237
THIS PAGE INTENTIONALLY LEFT BLANK
238
MR. WOODBURY:And I present him now for
cross-examination.
COMMISSIONER SMITH:Mr. Eddie?
MR. EDDIE:Than k you.I have a few
questions.
CROSS- EXAMINATION
BY MR. EDDIE:
Mr. Hessing, is it fair to summarize your position
basically that Idaho Power should not recover costs the company
incurs to purchase fuel or power of market?
Not recover through the PCA mechanism, yes.
Would your answer to that question change if I changed
the question to ask about fixed cost?For example, if the
question was this:Should Idaho Power recover costs the company
incurs to build new substations or additions between rate cases?
I guess my answer maybe would have two parts to that.
Those kinds of fixed costs have never been part of the PCA
mechanism.And the Company earn a return on equity to deal with
risks between rate cases that deal with costs like fixed costs
that vary.
So the answer is because the costs are recovered
differently that they should be treated differently?
Well , they haven t been addressed directly in the PCA
239
mechanism.The Company has varying costs between rate cases of
And that's been recogni zed for a long time in theall kinds.
The Company earns a return on equity thatrate-making process.
deals with risks that revenues from selling
--
well, revenues
And that's all balanced when a rate case iswon I t offset costs.
held.One of the things that has come out of this hearing so
far to me is that between rate cases there are a lot of costs
that vary and there are revenues that are collected associated
And a balancing of that is something that iswi th load growth.
In between that period of timedone In a generate rate case.
they are just business risks for the Company, and they are
addressed in the return on equity.
Okay.After reading your testimony, I came up with
the assumption that Staff does support the acquisition of all
cost effective demands by the Company?
Our testimony in this case is about the PCA, which
really doesn t have a thrust of demand-side management.Because
the rates that the Company recovers when they sell kilowatt
hours or don t sell kilowatt hours affect the Company s attitude
toward demand-side programs, I think it has to be factored in.
We thinkBut those weren t considerations in our case directly.
this case is addressed at other things.But you can t ignore
the fact that saving kilowatt hours or growing load or reducing
load, those are the same things.They are opposite views of the
same thing and they affect each other.
240
Do you agree that one way that Idaho Power could avoid
the impact of the
--
if Commission if were to adopt your
recommendation, one way for them avoid impact of recommendation
would be aggressively pursue all cost-effective demand side
management?
I think that's an appropriate action for the Company
to take and the staff is interested in pursuing all cost
effective demand side management.
But in other words, they can avoid that the outcome or
the result of your recommendation would be to file general rate
cases as soon as possible?
I think generate cases deal with true-ing it up after
the fact.The return on equity, the risk that revenues won
cover costs between rate cases, deals with the other part of it.
Is the filing of frequent rate cases a goal that the
Staff is advocating as far as recommendation?
Well , I guess that may depend somewhat on what
frequent rate cases are.The nine or ten-year period that the
Company went between the 94-5 case and the 03-case think
from Staff'view was long time and things got long ways out
of balance.Now whether we have to have rate case every year
or not, I don t know that we would look forward to that, but we
get paid to work on rate cases.And if the Company chooses to
file rate cases, that often will certainly be here.
Okay.My last question deals with page 3 and onto
241
of your direct testimony.You were discussing the treatment of
load growth before the PCA went into effect.Specifically, page
4, lines 2 and The revenues and costs associated with
serving load growth were not necessarily balanced.
I see that.
Would you agree that achieving the symbalance of cost
and revenue balance between rate cases is an appropriate policy
goal for the Commission to consider?
I missed the first part of that question.Could you
ask it one more time?
Would you agree that achieving the symbalance of cost
and revenue balance between rate cases is an appropriate goal
for the Commission to consider?
I think that that's already addressed between rate
cases by the business risks of whether those two things will
balance, and that's captured in the return on equity.But as
far dollar
to pick out?
already about
fixed cost
for dollar recovery is concerned, it's difficult
And there has been much discussion in this hearing
picking out one thing or the other , whether it be
or a variable cost, and trying to match it with a
revenue from selling an additional kwh.One thing that's known
is that that's very difficult to do.And the only time you
really do it thoroughly and do it right is when you have the
advantage of looking back on that test year and matching those
things
--
those revenues and costs and balancing them.And
242
that's what a generate rate case does.
MR. EDDIE:Thank you.I have nothing
further.
THE WITNESS:Thank you.
COMMISSIONER SMITH:Mr. Thompson?
MR. THOMPSON:We have no questions for Mr.
Hessing.
COMMISSIONER SMITH:Mr. Kline?
MR. KLINE:Thank you, Madam Chair.
CROSS- EXAMINATION
BY MR. KLINE:
Mr. Hessing, I would like to start off with some
questions regarding the role that market sales and market
purchases play in the load growth adj ustment amount that you
have calculated and presented in this case.And in order to
reduce the complexity of that a little bit because we have spent
some time talking about it here today already.m hoping thi s
will make it a little less complex.I would like to pose a
hypothetical case and see if that can give us some additional
insight as to how this would work.I need you to have you make
a couple of assumptions.The first assumption is that year one
Idaho Power has just completed a new generating plant.Let'
call it Valmy And it is base load coal plant, 250 MGw.Next
243
assumption I would like you to make is that the variable cost of
Valmy 3 is $20.I think that's generally consistent with the
variable cost of a coal plant.Would you agree?
Yeah.I think that's ballpark.
Okay.
The third assumption is that Valmy 3 makes the Company
The fourth assumption is the market price is100 MGw surplus.
$41, approximately the same as the load growth adjustment that
you have computed and are proposing.At this point I would ask
you the question then , Mr. Hessing, do you agree in this
hypothetical, the difference between the $20 variable cost and
the $41 market cost is Idaho Power s opportunity cost?Is that
a --
Well, it is the difference between the embedded cost
and the market price.And if you choose to call it an
opportunity cost, I guess that's okay.
You wouldn t disagree with it though?
Not necessarily
--
no, I wouldn
Okay.
I do have one question about your assumption.You
talked about year 1, year
--
those are relative to what?
re getting there.
Okay.
Year 2 , this is the year after
--
well, still in year
one Idaho Power sells the surplus from Valmy 3 on the market and
244
it captures the opportunity cost , the $21 approximately.And
the other PCA flows that through to its customers and they get
the benefit.Now
That wouldn t happen unless you were talking about
after a rate case.
Okay.All right.That's right.All right.Now, in
year 2, Idaho Power s native load grows 10 MGw , okay?
Okay.
The variable cost is still 20, the market is still
and the opportunity cost is still 21.Now, at this time when
you got the load growing by 10 MGw , under your proposal there
would be a $ 41 load growth adj ustment credit applied to the
MGw of load growth; is that correct?
Yes.
All right.Now, assuming that we don I t change the way
that we make rates in Idaho, does the Company have the option
not to serve that 10 MGw of load growth and sell the 10 MGw at
the opportunity cost in order to avoid the loss of that $21
that's the difference between variable and market?
Well, I guess I agree that the Company does have the
obligation to serve that load.I don t know that it's a loss of
$21 because the company gets some revenues when they sell that
load.And I don t know whether that's a loss or not.
But the incremental amount that they have sold
--
just
the incrementals is what we re talking about here.
245
(Nods head.
Well, let me ask it this way:Does the Company have
the opportunity to charge the new 10 MGw $41 rather than $20?
No.The Company doesn t have that opportunity.
So I guess the next question is:Is -- other than the
retail rate recovery of those costs in sales to the 10 MGw will
Idaho Power ever get the cost $21 in opportunity costs under
Staff's proposal?
I believe that those costs
--
well, you excluded the
revenues from the retail sales.And I don t think it'
appropriate to exclude that to begin with.
Okay.
But the fact that load grows and that there are costs
associated with that, and the fact that there are revenues
recovered are a business risk of the Company.And between rate
cases -- it was that way before the PCA and that was fair then.
I believe it's fair to continue to do that now and only deal
wi th the power supply cost associated with fluctuating water
condi tions and not load growth in the PCA.
Let me ask you -- all right, let me direct your
attention now to page 2 of your testimony, lines 6 and 7 there.
And there you say the PCA was created to address the problem
wi th fluctuating water conditions.
Now , isn t it true Mr. Hessing that even in
1992 everybody acknowledged that the PCA would also address the
246
need to recover expenses associated with CSB proj ects.Isn
that correct?
Yes.The PCA
--
that was a power supply cost that was
included in the PACA at 100 percent.
And those CSB weren t related to water fluctuations,
were they?
, they weren Before they were included the PCA,
the Company had a deferral mechanism in place where they were
referred until the general rate case.And they were allowed
the company was allowed a 100 percent recovery in general rate
cases, including in the PCA mechanism basically allowed them to
be passed on an annual bases instead of a accumulated between
rate cases because they were federally mandated.
And isn t it true that this Commission actually
directed Idaho Power to come in and file a case to avoid the
increasing size of that deferral account?Do you remember that?
I don t have a personal knowledge of that.
Do you know what percentage of total power supply
costs in the PCA on a normalized bases are attributable to CSBB
expenses?
Like Mr. Said recited earlier , I think it's roughly
half.
It's about forty-six or forty-seven million dollars
for CSB and about the same for all other power supply expenses
on a normali zed basis?
247
That's my understanding, yes.
Do you know how much the non QF power supply expenses
have grown over the period say since 1992?Have you ever looked
at that?
I haven
And of course, on the non QF side it's true, isn t it,
that variations come from much more than water conditions and
changes in the power supply expense?
Water conditions are -- well, in 1992 water conditions
were the main driver.The power supply costs were a lot more
stable
--
not as much volatility and a lot lower.There are
other things that affect power supply costs other than water
condi tions, and one of them is load growth.And there are some
others too.
Coal costs?
Yeah.The Staff's adjustment was aimed in the 1992
case at the variable cost of power supply associated with load
growth because that was a big one and that was one we thought we
could address and knew how to address , and so we fashioned the
mechanism that was accepted by the Commission.
And since 1992 the Commission has approved several
other adj ustments to the PCA and how it's determined, have they
not?
There have been other things -- some have come and
They were short-term things.Whether
--
there have beengone.
248
other adj ustments that are still there.
One example is several years ago we changed the
true-up mechanism
--
or calculations to be based on sales rather
than loads.Isn t that correct?
That's correct.
And it's also true that we have added cloud-seeding
expense as a component of the PCA?
Yes.And that may not be there pass the next general
rate case because some normal amount would be included in rates.
I don t know that how that's going to work exactly, but it'
there now.
Yeah.And also it's true that we have adj usted the
rate to include the emissions credits that are currently being
flowed through; is that correct?
That's correct.
All right.So the fact is that the PCA really hasn
been frozen or stagnant since 1992.If the Commission has found
good reason to adj ust the PCA, it's done that to change it to
accommoda te new conditions?
That's true.
If the Commission looks at the record in this case and
looks at the things that have changed since 1992
--
things like
the load growth that Idaho Power is currently experiencing; the
volatili ty that it now sees in coal costs and gas costs.And if
it makes a determination that today s conditions or so much
249
different than they were in 1992, that would be consistent with
the way we have operated the PCA since the beginning, wouldn
it?
I believe that it's wi thin the Commission s authority
to make changes because of changes that have happened and
condi tions.Whether they choose to do that or where they choose
to have those addressed in the way they have been traditionally
addressed is their choice.And we re discussing those in this
case.
But it wouldn t be inconsistent with the way we have
done the PCA previous?
I believe the Commission could choose to change the
PCA to address power supply costs associated with load growth
differently than it has done in the past.
MR. KLINE:Thank you.That's all the
questions I have.
COMMISSIONER SMITH:Do we have questions
from the Commission?
COMMISSIONER HANSEN:No.
COMMISSIONER KJELLANDER:No.
CROSS-EXAMINATION
BY COMMISSIONER SMITH:
Kei th, I think
--
I thought I understand this, but now
250
not sure.So just help me with this one thing that has come
up since your discussion with Mr. Kline.Are revenues from off
system sales run through the PCA for the benefit of customers?
Net power supply cost set in generate case include
basically four accounts.And one of those accounts is 447,
which is revenues from off-system sales.Now , purchase power,
costs are there, and fuel costs for coal and gas are there also.
They are run through the PCA and always have been because the
Company, even though it has a resource that may not be used at
that particular time, may choose to purchase power.You know
there have been a lot of discussion about secondary sales
revenues and whether that's appropriate, but the Company
proposal is to exclude purchase power costs and secondary sales
revenue.And so the Company can choose to purchase power
because it's cheaper than generating its own resources.And on
the secondary sales revenue side , it's been from my view those
costs have been in the PCA A and should be in this adj ustment
calculation because secondary sales are in the mechanism and
they have been there.And the Company makes choices.Now , the
point was brought out here that the Company doesn
--
it has an
obligation to serve new load, but it doesn t have an obligation
to sell power to these people they sell power to.The
obligation the Company has with regard to secondary sales
revenue is customers are paying for that resource and a big
Company has an obligation to mitigate the cost.And so the
251
Company sells when it can and make a profit on it and that
mitigates costs.All of these things are tied together in the
PCA mechanism and need to be there in order to remove the power
supply costs associated with load growth.I don t know; I think
I got your question.
Well , I hadn t got to my question yet, which is back
to my simplistic view of simplistic regulations.But if the
revenue from the off-system sales is flown back in the PCA to
reduce the power supply and thus we benefit the customers
through their ratings, then how is the Company out anything if
the
--
in Mr. Kline s hypothetical , the off-system sales are
reduced by ten megawatts.
Well, the numbers
--
the dollars that are actually are
in the PCA mechanism , part of the differences between secondary
sales and a normalized circumstance; and the difference in
secondary sales and the difference with load growth.And
secondary sales are reduced when the company grow load, as has
been pointed out.Purchase power costs are also reduced
--
sorry, increased; and fuel costs are increased.Those things
all work together in the PCA mechanism to benefit customers or
harm customers, if you want to view it that way
--
cost
customers money.And it's Staff's belief that all of the things
need to be addressed and adj usted because they interplay.One
wi thout the other is meaningless.
COMMISSIONER SMITH:Do you have any
252
redirect, Woodbury?
MR. WOODBURY:I have no further customers.
COMMISSIONER SMITH:Thank you,
Mr. Hessing.
According to my notebook that's the end of
the witnesses.
Does any party wish the opportunity for
closing statements or to file lengthy legal briefs?
(No response.
COMMISSIONER SMITH:Well , then seeing
nothing further to come before the Commission in this hearing or
after it, I will declare that the record in this case is closed.
And the Commission will deliberate upon this and issue an order
as speedily as possible.I don t know of any time constraints
on this.
Any reason why it has to be done by a date
certain?
(No response.
COMMISSIONER SMITH:So we will get to it as
quickly as we can.
(Proceedings concluded at 2:35 p.
253
This is to certify that the foregoing is a true and correct
transcript to the best of my ability of the proceedings held IN
THE MATTER OF PETITION OF IDAHO POWER Company FOR MODIFICATION
OF THE LOAD GROWTH ADJUSTMENT FACTOR WITHIN THE POWER COST
ADJUSTMENT (PCA) METHODOLOGY commencing on Monday, October 30,
2006 at the Commission hearing Room , 472 West Washington Street
Boise, Idaho , and the original thereon for the file of the
Commission.
Accuracy of all pre-filed testimony
to this Reporter and incorporated herein
Commission is the sole responsibility of
as originally submitted
at the direction of thethe submitting parties.
~ , -.