20081024Reading Direct.pdf

RECEIVED
2008 OCT 24 . PH 3: 43
, lytJiO PUDUC
UTILI fitS COMMISSION
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
N THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR AUTHORITY ) CASE NO. IPC-E-08-10
TO INCREASE ITS RATES AND CHARGES FOR )
ELECTRIC SERVICE TO ELECTRIC )
CUSTOMERS IN THE STATE OF IDAHO )
)
DIRECT TESTIMONY AND EXHIBITS OF
DR. DON READING
ON BEHALF OF
INDUSTRIAL CUSTOMERS OF IDAHO POWER
OCTOBER 24, 2008
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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 Hil
Road, Boise, Idaho.
HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR QUALIFICATIONS
AND BACKGROUND?
Yes. Exhibit 201 serves that purose.
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS CASE?
I have been retained by the Industrial Customers of Idaho Power (ICIP) to review Idaho
Power's (IPC, Company) application for authority to increase its rates and charges for
electric service. Specifically I examine the Company's rate allocations that are derived
from its preferred cost of service (COS) study. I propose changes to Idaho Power's COS
that brings cost assignments closer the Company's load profile as a capacity constrained
utility rather than as an energy constrained utility. I also address the Company's use of a
projected test year and recommend an approach the Commission may tae that would
satisfy some of the goals sought by the Company while addressing some of the problems
inherent with a forecasted test year. I discuss the Company's recommended inclusion of
construction work in progress (CWIP) in this case and recommend the Commission reject
its inclusion in base rates. I also give a brief update on the status of our virtual peaking
discussions with Idaho Power.
Cost of Service
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DR. READING, TURNING TO YOUR EXAMINATION OF IDAHO POWER'S
COST OF SERVICE STUDY -- COULD YOU PLEASE BRIEFLY REVIEW THE
COMPANY'S APPROACH?
Yes. Staff witness Tatum presents three separate cost of service studies; Base Case,
Modified Base Case, and 3 CPI12 CPo The Company's preferred approach, as it was in
the last case (IPC-E-07-08), is the 3 CPI12 CP study. This approach is being
recommended because the Company believes it is the most effective method of allocating
production plant costs consistent with the costs imposed by each given customer class.
(Tatu, Di. pages 51,52.)
DO YOU HAVE ANY GENERA OBSERVATIONS?
Yes. I have two general observations. First, Mr. Tatum states that the Base Case is
consistent with the "Normalized" method fied in the last rate proceeding. That rate
proceeding, IPC-E-07-08, was settled and thus the cost of service study was not litigated
in that case. Therefore, when comparing the Company's proposed COS with past filings,
the base of comparison should be the last one filed by the Company and approved by the
Commission in case No. IPC-E-03-13.
Second, as indicated by Company Exhbit 69, a disproportionate share of the
overa119.89% proposed increase requested by Idaho Power falls on high load factor
customers under all three COS cases presented by the Company (irrigation service being
the one exception of a low load factor costuer having å significant increase in revenue
requirement). The indicated increases for all three studies presented for residential
customers range from 2.01 % (Base Case) to 3.71 % (3 CP/12/ CP). On the other hand, the
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1 range of increases for Schedule 19 and the Special Contract customers is 15.21 %
2 (Schedule 19, Modified Base Case) to 32.61 % (JR Simplot, Base Case).
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4 Q. WHY DO YOU POINT OUT THAT THE COST OF SERVICE STUDY FILED BY
5 THE COMPANY SHOULD LOOK TO CASE IPC-E-03-13 AS THE BASE CASE
6 FOR COMPARISON TO THE CURRNT CASE?
7 A. As I testified above, Idaho Power's last general rate case was settled. In the Settlement
8 Agreement the paries agreed that the cost of service study filed in that case would not be
9 precedent setting. The Commission recognized that fact in its order approving the
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12 The paries also agreed that the underlyingcost-of-service model fied by the
13 Company in this proceeding will not constitute precedent in any subsequent
14 general rate case. The paries specifically recognize that any par s failure to
15 specifically object to the Company s cost-of-service analysis in this case will not
16 constitute a waiver in any futue general rate case proceeding. (Idaho Public
17 Commission Order 30035, IPC-E-05-28, page 5.)
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19 The COS filed in the last case also allocated the major share of the proposed rate increase
2 0 to the high load factor customers. A hint of the reason for this disproportionate share for
21 high load factor customers is found in Company witness Brilz IPC-E-05-28 Direct
22 Testimony fied in that case.
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WHAT REASONS DID MS. BRILZ GIVE FOR THE DISPROPORTIONATELY
HIGHER ALLOCATIONS TO HIGH LOAD FACTOR CUSTOMERS FOUND IN
THE COMPANY'S COST OF SERVICE STUDIES?
In her filed testimony she stated,
Since the conclusion of the Company's last general rate case it has been
determined that the deficit months of June, July, August, November, and
December used in the 2003 marginal cost analysis were primarily determined by
firm generation supply acquisition need rater than determination of months in
which a peak-hour deficiency occured. The deficit months of January, May,
June, July, August, September, November, and December used in the curent
marginal cost analysis are directly tied to peak-hour deficiency months identified
in the 2004 IRP.
And,
The use of eight deficit months (Januar, May, June, July, August, September,
November, and December) in the curent marginal cost analysis results in
weighting factors that attribute more generation capacity cost responsibility to
customer classes with usage throughout most of the year. (Direct Testimony,
Maggie Brilz, IPC-E-05-28, page 21,22.)
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The effect of extending the number of months used in the marginal cost study from 5 to 8
months spreads the costs of generation to customer classes with high use over a greater
number of months.
THE COMPANY HAS INCREASED THE NUMBER OF MONTHS TO WHICH
IT IS APPLYING CAPACITY COSTS. WHAT HAVE BEEN THE TRENDS IN
THE MARGINAL COST OF CAPACITY AND ENERGY FOR IDAHO POWER
SINCE THE IPC-E-03-13 GENERAL RATE CASE?
There have been dramatic shifts in the costs of capacity and energy for the Company in
the 5 years since case IPC-E-03-13 was fied. Marginal generation capacity costs have
dropped by 45% from $90.71 per KW to $50.00 per KW. The monthly amounts are
shown on my Exhibit No. 202. While capacity costs have dropped, marginal power
supply costs over the same 5 year period increased dramatically by 114%, from $33.38 to
$71.46 per MWh. The increase has been especially large in July and August with
curently estimated marginal costs of $99.66 and $81.85 per MWh respectively. My
Exhibit 203 displays monthly maginal power supply costs over the last 4 filed general
rate cases.
HOW DO YOU EXPLAIN THE SIGNIFICANT DROP IN MARGINAL
CAPACITY COSTS COUPLED WITH THE DRAMATIC INCREASE IN
MARGINAL ENERGY COSTS?
It appears to be the fuction of two interrelated factors. Natural gas prices have increased
since the filing ofthe general rate case in 2003, and the Company has added gas peakng
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resources. The capacity costs of a gas peaking unit on a per KW basis are relatively lower
than other generating resources. The trade off for these lower capacity costs is higher fuel
costs and hence higher energy costs. The higher gas prices have also driven the cost of
purchasing off system power to higher levels.
IDAHO POWER HAS A RESOURCE STACK WITH MIX OF DIFFERENT
TYPES OF RESOURCES. WHAT HAVE BEEN THE CHANGES IN THE COST
OF ENERGY ON A NORMALIZED BASIS OVER THE PAST 5 YEARS?
As shown on my Exhibit 204, energy costs have increase from a variety of resources.
Both Bridger and Valmy, with essentially the same output since 2005, have experienced
increased energy production costs by $35 milion. The two gas fired units in the
Company's resource stack have power supply costs of$81.96 per MWh for Bennett
Mountain and $195.53 per MWh for Danskin. The cost of off system purchases have
increased from $39.9 per MWh in case IPC-E-03-13 to $58.8 per MWh in the curent
case. The value of off system sales has also increased, but by a lesser amount, from $20.9
per MWh in 2003 to $45.6 per MWh. It should be emphasized the curent case values
are based on projections by the Company.
YOU HAVE DEMONSTRATED THE INCREASES IN ENERGY COSTS OVER
THE PAST 5 YEARS FOR IDAHO POWER. IS THIS A CAUSE OF HIGH
LOAD FACTOR CUSTOMERS BEING ASSIGNED THE MAJOR SHARE OF
THE PROPOSED RATE INCREASE?
Yes. The paradoxical aspect of this increase in energy costs relative to capacity costs is
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the fact that Idaho Power has changed from a energy constrained utility to a capacity
constrained utilty over the past 15 years. Ths shift has been driven primarily by the
growth in the residential and small commercial classes over the past dozen years. This is
the reason the Company has constrcted 260 MW s of gas peaking units as its latest
resources. These higher energy costs are reflected in the Company's cost of service
studies which pass on higher energy costs to high load factor customers. However for a
utility that is capacity constrained, higher price signals should be sent to those customer
classes that have the lowest load factors. The results of Idaho Power's cost of service
studies does just the opposite by charging a disproportional share to customers that have
high load factors.
AS YOU POINTED OUT ABOVE, THE RESIDENTIAL CLASS, (AND TO A
LESSER EXTENT THE SMALL COMMERCIAL CUSTOMER CLASS) IS
RECEIVING THE LOWEST PERCENTAGE INCREASE, WHILE THE HIGH
LOAD FACTOR CUSTOMERS ARE RECEIVING THE HIGHEST. WHAT
DOES THIS SAY ABOUT PRICE SIGNALS TO CUSTOMERS?
It sends the wrong price signals, because the result of the Company's COS allocates more
costs to energy than to capacity, which is reflected in the Company's proposed rates. The
recommended rate increase for Schedule 19 and Special Contract customers is 2.4 times
higher than for the residential class. Yet the Company has been adding peaking resources
to meet the increasing demand during peak periods that is being driven largely by
residential customer growth.
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HAVE YOU FOUND ANOTHER CAUSE WITHIN THE COMPANY'S COST OF
SERVICE STUDIES THAT HAVE SHIFTED COSTS FROM RESIDENTIAL
AND SMALL COMMERCIAL CUSTOMERS TO HIGH LOAD FACTOR
CUSTOMERS?
Yes. As outlined in Company witness Tatum's testimony one of the changes to come out
of the three cost-of-service workshops was a method of "normalizing" class coincident
peak demands.
The surogate demand normalization methodology uses the five-year median
demand ratios from the load research sample applied to the normalized monthly
energy values for each customer class to determine the coincident peak demands
by class. This methodology reduces the effect of any atypical demand ratios that
might exist in a given test year due to unusual weather conditions. (Tatum, p. 11.)
The Company calculates system coincident demand factors for each customer class for
each month. These coincident demand factors are derived by finding the kW demand at
the system peak hour divided by the average kW demand for the month. These are
calculated for each of the years 2003 through 2007, then the median value over the 5 year
period is selected for each month for each customer class. One would expect the pattern
of median values for the customer classes to be somewhat similar given typical or
atypical years.
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DID YOU FIND SIMILAR PATTERNS AMONG CUSTOMER CLASSES WHEN
YOU EXAMINED THE PATTERN OF THE SYSTEM COINCIDENT DEMAND
FACTORS?
No. For the residential class six of the median values for these factors occur in 2003 with
another four being found in 2004. On the other hand, for Schedule 19, eight of the
median system coincident factors occur in 2006 with another two in 2007. Other
customer classes show varing patterns over the five year period of median system
coincident demand factors. This anomaly produces the effect that for some classes the
cost of service values are being determined weighted for load patterns that occured four
or five years ago while for other classes this weighting effect occurs in more recent years.
DID YOU EXAMINE HOW THE PATTERN YOU JUST DESCRIBED ABOVE
COULD IMPACT COST OF SERVICE VALUES AMONG CUSTOMER
CLASSES?
Yes. Rather than using the median values for the system coincident demand factors I
substituted in the 2007 values and ran the 3 CPI12 CP model with no other changes. Use
of 2007 system coincident demand factors, rather than the five year median values,
produced some significant shifts among some customer classes. In general there was a
shift of costs away from the higher load factor customer classes to the lower load factor
classes. The residential class revenue deficiency increased nearly $5 milion meaning the
percent increase in rates went from 3.71 % to 6.26%. (see Exhbit 205) While the Large
General Service class percent increase in rates dropped to 2.12% from 9.16%, and
Schedule 19's increase was reduced from 15.87% to 14.97%. These results appear to
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assign cost responsibility more in line with what one would expect given the growth in
Idaho Power's system over the last 15 years. These results should be viewed as
preliminar. The Company's Cost of Service method requires several steps of transferrng
large amounts of data to make this change. We are working with the Company to verify
these steps have been made correctly. To the extent the results presented here var from
the Company's, we will adopt the Company's verification of these results and file revised
exhibits.
BY RECOMMENDING THE USE OF THE 2007 VALUES FOR SYSTEM
COINCIDENT DEMAND FACTORS RATHER THAN THE MEDIAN ARE YOU
SAYING COINCIDENT KW SHOULD NOT BE NORMLIZED IN SOME
MANNER TO ACCOUNT FOR ATYPICAL YEARS?
No. I think the Company and the cost of service workshop paricipants were addressing
this as a potential problem. However the experience of using the median method as
described above has lead to anomalous results. For this case, the use of 2007 yields
results that are more consistent with what one would expect given the Company's load
patterns. I would recommend the Company and the parties work together to find a
method of normalizing k W coincident demand factors.
DO YOU HAVE OTHER RECOMMENDATIONS THAT WOULD HELP
REMEDY THE PARADOXICAL RESULTS OF THE COMPANY'S COST OF
SERVICE STUDIES?
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I have two additional recommended changes to the cost of service method used by the
Company. The cost of service results described below are based on changes from the
Company's recommended 3 CPI12 CP Case. The other two changes are:
1) I recommend that the weightings for customer classes be set at full marginal
cost rather than the average of marginal and imbedded weightings used by the
Company. This will more accurately reflect the costs that are being incured by
the Company because marginal costs best represent the costs of additional
capacity and energy from needed additional resources. See my Exhibit 206.
2) I also recommend that the Company's hydro resources be allocated between
demand/energy to 75% capacity and 25% energy rather than the system average
split that is curently used by Idaho Power. This is more in line with standard cost
allocations and are the same values used by Rocky Mountain Power in both its
curent and last rate case before the Commission. See my Exhibit 207.
The results of these three modifications to the Company's approach are detailed in
Exhibits 205, 206 and 207. I will outline each change separately below, and then
sumarize them in combination with one another.
DR. READING PLEASE TURN TO YOUR FIRST MODIFICATION OF THE
COST OF SERVICE STUDY PRESENTED BY THE COMPANY. WHY DO YOU
BELIEVE FULL MARGINAL COST WEIGHTING REFLECTS THE
COMPANY'S COSTS BETTER THAN ACTUAL VALUES?
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As explained above, one of the problems with the class cost allocations that result from
the Company's cost of service studies is that cost allocations are not reflected in the rates
for those customer classes that drve costs on Idaho Power's system. Exhibits 202 and
203 depict the marginal costs of capacity and energy indicate the dramatic differences in
cost over the different months of the year. Full marginal cost weightings then wil reflect
more fuly these difference among customer classes and thus better reflect the costs each
custom class is placing on the system.
WHAT ARE THE RESULTS OF THIS MODIFICATION TO THE COMPANY'S
3 CPt 12 CP MODEL?
It should be noted before I discuss the results of these cost of service modifications, that
all the values are based on the Company receiving its ful proposed increase of 9.89%. A
different overall rate increase will change the percentage change for each customer class
in ratio with that overall rate change.
As shown in Exhibit 206, weighting customer classes at full marginal cost, in
general, lowers the percent increase on high load factor customers (Large General
Service, Schedule 19, special contracts). Cost allocations to the residential and irrigation
classes are increased slightly. The other classes remain about the same. This result tends
to move the cost of service away from high load factor customers but it does not send a
price signal to the residential class which is a major cause of the Company's increasing
need for capacity.
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COULD YOU PLEASE EXPLAIN THE THIRD MODIFICATION YOU ARE
RECOMMENDING BE MADE TO THE COST OF SERVICE STUDY
PRESENTED BY THE COMPANY?
On page 5 of his direct testimony Company witness Tatu states,
Demand related costs are investments in generation, transmission, and a portion of
the distribution plant and the associated operation and maintenance expenses
necessar to accommodate the maximum demand imposed on the Company's
system. Energy related costs are generally the variable costs associated with the
operation of the generating plants, such as fueL. However, due to the hydro
production capability of the Company, a portion of the hydro and thermal
generating plant investment has historically been classified as energy-related.
(Tatu, Di. p. 5)
He goes on to say,
Q. What did you use as your primar guide in classifying costs as either customer-
, demand-, or energy related?
A. I used the Electric Utility Cost Allocation Manual published by the National
Association of Regulatory Utilty Commissioners as my primar guide to the
classification of customer-, demand-, and energy-related costs. (page 6.)
According to the NARUC Cost Allocation Manual, hydro facilities are usually treated as
capacity. Mr. Tatu is correct that 'traditionally' the Company has treated, and the
Commission has accepted, the allocation of the Company's hydro resources to energy.
When the Company was energy constrained, rather than capacity constrained, this made
sense. However now that Idaho Power is capacity constrained rather than energy
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constrained, and it is adding additional resources which reduces its reliance on hydro
resources, it now makes sense to allocate its hydro resources more to capacity rather than
energy.
WHAT is YOUR RECOMMENDATION FOR THE ASSIGNMENT OF HYDRO
RESOURCES BETWEEN ENERGY AND CAPACITY?
A reasonable method of allocating Idaho Power's hydro resources between capacity and
energy is to assign 75% capacity and 25% energy. This is the allocation used by
PacifiCorp in its cost of service study in its last and curent rate cases, "Production and
transmission plant and non-fuel related expenses are classified as 75 percent demand
related and 25 percent energy related" (PAC-E-07-05, Rocky Mountain Power, Mark E.
Tucker, Di-4). It is my understanding this capacity/energy split was established by the
various states served by PacifiCorp.
There are a variety of ways hydro facilities can be allocated. These would range
from 100% demand related to some mixtue between demand and energy. I believe the
allocation of 75% to capacity and 25% to energy is reasonable for hydro plants. The
NARUC Cost Allocation Manual states, "Most hydro capacity today is being used for
peaking puroses, and its costs therefore are properly classified as demand-related."
(Electric Utility Cost Allocation Manual, NARUC, 1967, footnote page 33.) Whle the
Company has numerous ru-of-river facilties the major hydro complex is Hells Canyon
that Idaho Power uses for peaking.
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WHAT is THE RESULT OF YOUR RECOMMENDATION FOR THE
ASSIGNMENT OF HYDRO RESOURCES BEING 75% CAPACITY AND 25%
. ENERGY?
Exhibit 207 displays the results of allocating the Company's hydro resources 75% to
capacity and 25% to energy. This modification produces approximately the same result
as reclassifying PURPA projects at the system average between capacity and energy.
With this change, the revenue requirement for high load factor customers is lowered with
the residential class being assigned a slightly higher increase. In addition, as was tre
with the other two recommended changes, irrigation customers receive a higher percent
Increase.
YOU HAVE INDICATED WHAT THE RESULTS ARE FOR EACH OF YOUR
THREE RECOMMENDED CHANGES INDEPENDENTLY. WHAT is THE
IMPACT IF ALL THREE ARE IMPLEMENTED?
These results are shown in Exhibit 208. When the three modifications are made
simultaeously the high load factor customers revenue deficiency are lowered
significantly and the percentage increase for irrigation customers increases slightly from
28.54% to 29.09%. The residential class's revenue deficiency increases by $9.3 milion
for a rate increase of 8.52%.
YOU HAVE DESCRIBED THREE CHANGES TO THE COMPANY'S COST OF
SERVICE METHOD. ARE YOU ADVOCATING THESE CHANGES BE
IMPLEMENTED BY THE COMMISSION?
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Yes. The modifications I have recommended align cost responsibility more in line with
the Company's changing load growth patterns. These changes will also better provide
price signals to the customer classes that are creating costs through system load growth.
The results of these changes also increase the revenue requirement for the irrgation class
only slightly. The irrigation class has the misfortune of having the need for power during
sumer on peak that is when the Company's system needs are growing the fastest.
Irrigation load is not growing. Yet due to increasing residential and commercial demand,
their cost allocations are increasing due to their relatively high sumer use.
Reading Test Year Testimony
Dr. Reading, have you read the testimony and reviewed the exhibits of Company
witness Lori Smith?
Yes. Ms. Smith used the Company's actual financial results for calendar 2007 as a
foundation to project the calendar 2008 test year used by Idaho Power for its proposed
rates in this case. She develops the 2008 forecasted test year by adjusting 2007 values for
operating expenses and rate base. Thee and five year compound growth rates are used to
forecast investments of the Company that are less than $2 milion. In addition certain
items are anualized as if they were in existence the full test year.
Why is the Company using a fully forecasted test year in this case?
According to Ms. Smith,
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In order to meet the legal requirement that rates be fair, just, reasonable, and
sufficient, the Commission must establish a test year that most closely reflects the
investment and expense levels that will exist at the time new rates are
implemented. At this time, the Company believes that a 2008 test year best
satisfies that requirement. (Smith Direct, pgs 18,19.)
It is understandable why the Company wants rates that most closely match their costs and
revenues during the period in which those rates will be in effect.
Are you saying you support the utilty basing rates on a forecasted test year?
No. As I stated in my fied testimony in the Company's last rate case (IPC-E-07-08) that
I was, and remain, opposed to the forecasted test year for both theoretical and practical
reasons:
One of the pilars of ratemakng is that ratepayers should only shoulder the burden
of 'known and measurable' costs. Projections, by definition, are a presumption
about futue events. The standard approach for a forecasted test year, and the one
used by the Company, is to make projections base on historical data and the
adjusted for expected changes. (Reading Direct Testimony, IPC-E-07-07, p. 5.)
In reality the assumptions and projections made by the Company mayor may not in fact
come true, yet ratepayers wil be paying as if the projections were true.
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You said you also have practical reasons for opposing a forecasted test year, could
you briefly outline those concerns?
Yes, in my direct testimony in case IPC-E-07-08 I quoted the well-known regulatory
expert James Bonbright:
In the first place, the commission's staff must audit the utility's books. For
ratemaking puroses, only just and reasonable expenses are allowed; only used
and useful propert is permitted in the rate base. In the second place, the
commission must have a basis for estimating future revenue requirements. This
estimate is one of the most difficult problems in a rate case. A commission is
setting rates for the futue but it has only past experience (expenses, revenues,
demand conditions) to use as a guide. (James Bonbright, with Albert Danelsen
and David Kamerschen, Principles of Public Utility Rates, 2nd Ed., March, 1988.)
I want to complement the Company for its efforts and communication with the Staff and
Interveners in the development of the forecasted test year in this case. The Company met
with Staff and Interveners in a workshop and outlined their approach. The Company has
worked hard to simplify the projection process and explain the foundation and
methodologies used to determine the values in the 2008 test year.
Are you saying you support the Company's projected 2008 test year as filed?
No, but due the timing of this case I am recommending a procedure that can accomplish
some ofthe goals of the Company and alleviate some of the problems with a forecasted
Reading, Di
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3 Q.
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20 A.
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test year outlined above.
Could you please discuss how you formed your recommendation for dealing witli
the forecasted test year in this docket?
This case was filed on June 27, 2008 with the technical hearing set for the end of
December 2008. The proposed rate suspension period wil end Januar 27, 2009 with the
Commission able to suspend for an additional 60 days for good cause. I, of course, do
not know what the Commission will do. However given the timing of the technical
hearing the Commission will need some time to decide the case. Therefore it is
reasonable to assume the final order would be issued sometime in mid-Januar.
We ask for, and received, in discovery from the Company (Idaho Power Company's
Supplemental Response to the First Production Request of the Industrial Customers of
Idaho Power, Supplemental Response for Production No.7.) on August 15, 2008 actual
financial data for the Company through June 2008 for items they projected using the 3
and 5 year compound growth rates.
Did you compare the actual first six months data for 2008 with the Company's
forecast?
Yes. I used the simplifying assumption of multiplying the six month year-to-date actual
values by two and then compared that value to the Company's full projected test year.
Exhbit 209 shows the results of that comparison. As can be seen, some of the estimates
appear to be very close while others var significantly. There can be all kinds of reasons
Reading, Di
IPC- E-08-1 0
20
1
2
3
4
5 Q.
6
7
8 A.
9
10
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13
14
15
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18 Q.
19
20
21
22
23 A.
why the first six months' expenditures and revenues would not exactly match the last half
of the year. However, the Exhibit does demonstrate how dramatically projections and
actual values can var.
You testified earlier that you have a recommendation that can resolve some of the
concerns of the Company as well as the problems you identified with using a
projected test year. What is your recommendation?
The Company should file with its rebuttl testimony, which is due on December 3rd,
actual results for the first three quarers of 2008. These updated actual results should be
used to compare to the projected test year calendar 2008. This would give a better
indication of how the Company's projections are squaring with reality. For those items
for which there is a significant difference, the Company could either make adjustments
and/or explain why those discrepancies occured. Depending on when the Commission
issues its final Order, another update could be made with actual data from those
additional month(s) that become available. This approach would mean rates would be set
using financial data that is closer to actual rather than a full 12 month projection.
DR. READING HAVE YOU REVIEWED THE TESTIMONY OF MS. MILLER
REGARDING INCLUDING THE ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION ("AFUDC") COMPONENT OF CONSTRUCTION WORK IN
PROGRESS ("CWLP") FOR THE HELLS CANYON RELICENSING PROJECT
TO BE INCLUDED IN BASE RATES?
Yes, I have. I do not believe it is appropriate to include such costs in rates in this
Reading, Di
IPC-E-08-10
21
1
2
3
4 Q.
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6
7 A.
8
9
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11 Q.
12 A.
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24
case.
WHAT AR THE PROBLEMS WITH INCLUDING THE AFUDC COMPONENT
OF CWIP ASSOCIATED WITH THE HELLS CANYON RELIC ENSING
PROJECT IN BASE RATES?
This Commission has a long stading precedent to disallowCWIP from rates. Here the
Company is asking that the AFUDC component of CWIP be included in base rates. That
is short of asking for all of the CWIP associated with this project to be included in base
rates, but it is stil asking for CWIP to be included in base rates.
WHAT AR THE PROBLEMS WITH INCLUDING CWIP IN BASE RATES?
Actually the Commission's own orders outline the reasons for disallowing CWIP from
rates. In order No. 14348 issued in Case No. 1009-96 the Commission made the
following declaration:
allowing a company to ear a retur on construction work in progress destroys the
incentive to finish that speedily, puts on the ratepayers a risk which is properly
borne by stockholders, and creates a mismatch between those who presently pay
and those who, in the future, will benefit from the electric plant when it becomes
used and usefuL. The Commission has made clear its position on this issue in
recent orders (citations omitted). We are steadfastly opposed to the inclusion of
CWIP in rate base. We find that the alternative method of providing an allowance
for fuds used during construction (AFUDC) is just and reasonable and does not
deprive the Company of anything to which it is entitled. Nothing would be served
by fuher discussion of this matter. (at page 6)
Reading, Di
IPC- E-08-1 0
22
1
2 Q.
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5 A.
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7
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11 Q.
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13 A.
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21 Q.
22
The Commission's rational is as valid today as it was back in 1978.
THE COMPANY'S REQUEST is RELATIVELY MODEST IN LIGHT OF THE
ENTIRETY OF THE HELLS CANYON RELIC ENSING COSTS. WHY THE
STRONG OPPOSITION?
Because this is just the tip of the iceberg, if you will. Company policy witness Gale
testified that the Company is embarking on a plan of construction projects that is only
comparable to the time it built the Hells Canyon Complex. He noted that the Company is
planing on spending almost one bilion dollars in the near term on construction projects
without including the Gateway West Transmission Project or the Hemingway-Boardman
line. (Gale Di at page 19.)
WOULD NOT SUCH A LARGE CONSTRUCTION PLAN SUGGEST THAT THE
COMPANY WILL NEED TO PUT CWIP IN RATES?
Yes and no. Certainly the Company wil raise the argument that putting CWIP in rates
reduces futue rate increases, generates internal cash flow and reduces the cost of electric
plant when it does become used and usefuL. However, the Company's planed future
developments are not certain to come on line and are also not certin to come on line
when planed. The risk of failure to develop and the risk of delay is placed entirely on
the ratepayer side of the ledger when a utility is allowed to place CWIP in rates. Idaho
has had ambitious constrction plans in the past that have not come on line and the
ratepayers were protected from paying the costs of those dry hole prospects.
DO YOU HAVE ANY SPECIFIC PROJECTS IN MIND THAT WERE PLANNED
BUT NOT CONSTRUCTED?
Reading, Di
IPC-E-08-10
23
1 A.
2
3
4
5
6
7
8
9 Q.
10
11
12 A.
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15 Q.
16 A.
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23 Q.
Certainly. In the early 1990s Idaho Power was actively pursing a major transmission
project to construct a large transmission line from Southern Idao to Las Vegas, Nevada.
It spent milions of dollars on planing, permitting and engineering that project. It
subsequently abandoned the project and only recently sold its rights to build it to a third
par. Had it put those costs in rates back in the 1990s those ratepayers would have paid
for a project that not only did not benefit them at the time of payment, but did not benefit
Idaho Power's ratepayers at alL. That ilustrates my concern here. Placing CWIP in
rates is simply too speculative of a risk to put on the ratepayers.
IDAHO POWER'S FUTURE CONSTRUCTION PLANS CALL FOR
INCREASING ITS RATEBASE BY A SUBSTANTIAL AMOUNT, WOULD NOT
ALLOWING CWIP IN RATES ALLOW IT TO PROCEED WITH LESS COST?
The unprecedented level of construction spending Idaho Power is planing may call for
an unprecedented response. However, simply slipping the precedent of allowing CWIP in
rates in this case is not the way to go about fashioning that response.
PLEASE EXPLAIN.
If all of Idaho Power's planned projects come to frition, we could easily see a doubling
of its rate base and unprecedented rate increases for the ratepayers. I understad that
Idaho Power may need some assistace from the Commission and the ratepayers in terms
of assurance of recovery of its prudently incured costs and we would be willng to sit
down with them to fashion a response short of a blanet granting of CWIP. I don't have
any specific suggestions at this time, but would be open to a compromise down the road
as these possible constrction projects become more reaL.
WHAT DO YOU MEAN 'MORE REAL'?
Reading, Di
IPC-E-08-10
24
1 A.
2
3
4
5
6
7
8
9
10 Q.
11
12
13 A.
14
15
16
17
18
19
20 Q.
21
22
23 A.
As the U.S. and, indeed, the global economies curently appear to be hurling toward a
major recession, ambitious construction projects that require large quantities of debt may
be mothballed for reasons other than lack of CWIP in rates. There is a possibilty of
major loss of load due to the weak economy that would make proceeding with some
projects less than prudent. As of the time that I am wrting this testimony the economy is
in one of the most uncertin states I have ever seen it. I don't think now is the time to
hard wire CWIP to rates until we have more clarity on each specific project and the costs
associated with each specific project.
WHAT is THE STATUS OF THE VIRTUAL PEAKING RESOURCE YOU
ADDRESSED IN IDAHO POWER'S LAST RATE CASE?
I understad that Idaho Power has contacted some entities with emergency back up
generators to determine interest in their ruing in parallel with the Company's system.
The Company has also done some very preliminar studies of the costs associated with
such a program. I believe they have taken these steps in response to this Commission's
urging - although in discussions with Company offcials they report that Idaho Power has
looked at this sort of a peak shaving program at least ten years ago.
WHAT HAS THE COMPANY LEARNED FROM ITS STUDIES AND
DISCUSSIONS?
I believe the Company leared what it set out to lear.
Reading, Di
IPC-E-08-10
25
1
2 Q.
3
4 A.
5
6
7
8
9
10
11
12
13 Q.
14
15
16
17 A.
18
19
20
21 Q.
22
PLEASE EXPLAIN
The Company has been, to say the least, less than enthusiastic about implementing a
shared interest in customer owned generation for puroses of meeting peak or providing
stand-by reserves. Why, I do not know. We can speculate as to the reason for its
lukewar response to the possibilty of creating a virtual peaking unit at its load center,
but that would not be productive at this junctue. I believe the Company's lack of
enthusiasm for the program was a large driver in its conclusions that energy from such a
program would be much more expensive than building new gas fired peaking units. It did
conclude, however, that capacity would be much less expensive.
is THE FACT THAT ENERGY FROM A VIRTUAL PEAKING PROGRAM is
MORE EXPENSIVE THAN FROM A TRAITIONAL GAS PEAKER A FATAL
FLAW?
Apparently from the Company's viewpoint it is. Although, with its casual approach to
this program, we can conclude that creativity was not encouraged within the Company's
team that was looking into the possibility of a virtual peaking program.
PLEASE EXPLAIN.
Reading, Di
IPC-E-08-10
26
1 A.
2
3
4
5
6
7
8
9
10
11 Q.
12
13
14
15 A.
16
17
18
19
20
21 Q.
22
23
The reason energy from customer owned back up generation is so much more expensive
than energy from the company's own gas fire peakers, is because the Company assumed
diesel fuel would be used in the customer owned unts. The Company failed to explore
ways to work with new customers prior to installation of back up generation to have those
generators connect to the gas line rather than building diesel generators. If that were
done, the cost of energy for the back up generators would equal the cost of energy for the
Company owned generators, while the cost of capacity would be a fraction of the cost of
capacity from the Company's plants. Also using gas eliminates most environmental
concerns and dramatically reduces the additional expense of the interconnection.
SO ARE YOU SUGGESTING THE COMPANY BE DIRECTED TO
IMPLEMENT A VIRTUAL PEAKING PLANT PROGRAM FOR NEW
INSTALLATIONS?
Yes. On a going forward basis the Company should be directed to exercise its best efforts
to work with its customers who are installng new customer-owned back up generation to
enlist them in the virtal peaking program. If the Company, which had looked at this type
of a program at least ten years ago, had implemented it then, I am sure it would now have
a valuable addition to its arsenal for meeting that very expensive summer peak.
AR THERE OTHER UTILITIES THAT HAVE IMPLEMENTED PROGRAMS
THAT GRADUALLY REDUCE THEIR SYSTEM PEAK?
Reading, Di
IPC-E-08-10
27
1 A.
2
3
4
5
6
7
8
9
10
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12 Q.
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15 A.
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17
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21
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23
Interestingly, and unexpectedly, one only need to look at United Water to find an example
of a reluctant utility that was required to implement a successful peak shaving program.
This Commission initiated the concept of requiring United Water (then Boise Water) to
encourage the instalation of dual irrigation systems in those new subdivisions where
irrigation surface water was available. The tool the Commssion used was a puntive
hook-up fee for customers who did not comply. Although the regulatory tool ran afoul of
the prohibition against discriminatory rates - Boise City picked up the ball and made such
a program mandatory though its zoning regulations. As a result of ths Commission's
initiative, United Water's sumer peak is much less now than it would have been without
dual irrigation systems being installed as a matter of course.
WHAT is THE LESSON TO BE LEARED FROM THE BOISE WATER
EXPERIENCE?
Utilities have an incentive to build and own their own resources. Programs that reduce
their ability to build new plant (gas fired peakers or surace water treatment plants) reduce
their abilty to add to stockholder value. However, that also creates a tension between the
customer goal of having rates as low as possible. Here I believe Idaho Power has been
caught up at the intersection of those two competing interests. The lesson to be leared is
that the virtal peaking program can clearly be par of the solution, but only if this
Commission wants it to be, because Idaho Power is obviously not going to tae the
initiative.
Reading, Di
IPC-E-08-10
28
1 Q.
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DOES THIS END YOUR TESTIMONY AS OF OCTOBER 24, 2008?
A. Yes.
Reading, Di
iPC- E-08-1 0
29
1
2 CERTIFICATE OF SERVICE
3
4 I hereby certify that on the 24th day of October, 2008, I served the foregoing DIRECT
5 TESTIMONY OF DR. DON READING in Case NO. IPC-E-08-10 to the following as indicated
6 below:
7
Baron L. Kline
Lisa D. Nordstrom
Donovan E. Walker
Idaho Power Company
1221 W. Idaho St. (83702)
POBox 70
Boise, ID 83707-0070
E-mail: bklineßYidahopower.com
InordstromßYidahopower.com
dwalkerßYidahopower.com
i Hand Delivery
_ U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
JohnR. Gale
Vice President, Regulatory Affairs
Idaho Power Company
1221 W. Idaho St. (83702)
PO Box 70
Boise, ID 83707-0070
E-mail: rgaleßYidahopower.com
2L Hand Delivery
_ U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
Jean Jewell
Commission Secretar
472 W. Washington (83702)
PO Box 83720
Boise, ID 83720-0074
E-mail: jean.jewellßYpuc.idaho.gov
X Hand Delivery
_ U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
Randall C. Budge
Eric L. Olsen
Racine, Olson, Nye, Budge
& Bailey, Chartered
201 E. Center
POBox 1391
Pocatello, ID 83204-1391
E-mail: rcbßYracinelaw.net
eloßYracinelaw.net
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
Reading, Di
IPC- E-08-1 0
30
Anthony Yanel
29814 Lake Road
Bay Vilage, OH 44140
E-mail: yanel(fattbi.com
Michael Kurz, Esq.
Kur J. Boehm, Esq.
Boehm, Kurz & Lowr
36 E. Seventh Street, Suite 1510
Cincinnati, OH 45202
E-mail: mkurz(fBKLlawfrm.com
kboehm(fBKLlawfrm.com
Kevin Higgins
Energy Strategies, LLC
Parkside Towers
215 S. State Street, Suite 200
Salt Lake City, UT 84111
e-mail: khiggins(fenergystrat.com
Brad M. Purdy
Attorney at Law
2019 N. 17th Street
Boise, ID 83702
E-mail: bmpurdy(fhotmail.com
LotH. Cooke
Arhur Perr Bruder
United States Departent of Energy
1000 Independence Ave., SW
Washington, DC 20585
E-mail: Lot.cooke(fhq.doe.gov
Arhur.bruder(fhq.doe.gov
Dwight Etheridge
Exeter Associates, Inc.
5565 Sterrett Place
Suite 310
Columbia, MD 21044
E-mail: detheridge(fexeterassociates.com
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
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_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
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_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
Reading, Di
iPC- E-08-l 0
31
Conley E. Ward
Michael C. Creamer
Givens Pursley LLP
601 W. Banock Street
PO Box 2720
Boise, ID 83701-2720
E-mail: cew(fgivenspursley.com
Denns E. Peseau, Ph.D.
Utilty Resources, Inc.
1500 Libert Street SE, Suite 250
Salem, OR 97302
E-mail: dpeseau(fexcite.com
Weldon Stutzman
Neil Price
Deputy Attorneys General
472 W. Washington (83702)
PO Box 83720
Boise, ID 83720-0074
E-mail: weldon.stutzman(fpuc.idaho.gov
NeiL. priceßYuc.idaho.gov
Ken Miler
Clean Energy Program Director
Snake River Allance
PO Box 1731
Boise, ID 83701
E-mail: kmiler(fsnakeri verallance.org
1
2
3
4
5
6
7
8
9
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
_ Hand Delivery
g U.S. Mail, postage pre-paid
Facsimile
Electronic Mail
~CUf\~S
Nina M. Curtis
Reading, Di
IPC-E-08-l0
32
1 II
Reading, Di
iPC- E-08-l 0
33
Don C. Readig
Don C. Reading
Present position
Vice President and Consultig Economist
Education B.S., Economics C Utah State University
M.S., Economics C University of Oregon
fhD., Economics C Utah State University
HonorsaneJ
award~
Omicron Delta Epsilon, NSF Fellowship
Professionæ
and busines~
history
Ben Johnson Associates, Inc.:
1989 ---- Vice President
1986 ---- Consultig Economist
daho Public Utities Commssion:
1981-86 Economist/Director of Policy and Admstration
Teachig:
1980-81 Associate Professor, University of Hawai-Hio
1970-80 Associate and Assistant Professor, Idaho State University
1968-70 Assistant Professor, Middle Tennessee State University
Firm experienct Dr. Reading provides expert testiony concerng economic and reguatory issues.
He has testified on more than 35 occasions before utity reguatory commssions in
Alaska, Calfornia, Colorado, the Distrct of Columbia, Hawai, Idaho, Nevada,
North Dakota, Texas, Utah, Wyomig, and Washigton.
Dr. Reading has more than 30 years experience in the field of economics. He has
participated in the development of indices reflectig economic trends, GNP growt
ates, foreig exchange markets, the money supply, stock market levels, and
inflation. He has analyzed such public policy issues as the mium wage, federal
spendig and taxation, and import/ export balances. Dr. Readig is one of four
economists providig yearly forecasts of statewide personal income to the State of
Idaho for puroses of establishig state personal income tax rates.
n the field of telecommuncations, Dr. Readig has provided expert testiony on
the issues of margial cost, price elasticity, and measured servce. Dr. Readig
prepared a state-specific study of the price elasticity of demand for local telephone
servce in Idaho and recently conducted research for, and diected the preparation
of, a report to the Idaho legislatue regardig the status of telecommunications
competition in that state.
Exhbit 201
Reag, Di
IPC-E-08-l0
Don C. Readig
lOr. Readig's areas of expertise in the field of electrc power include demand
forecastig, long-range plannig, price elasticity, marginal and average cost pricig,
production-simulation modelig, and econometrc modelig. Among his recent
cases was an electric rate design analysis for the Industral Customers of Idaho
~ower. Dr. Readig is cuently a consultant to the Idaho Legislatue=s Commttee
pn Electrc Restrctug.
Since 1999 Dr. Readig has been affilated with the Cliate Impact Group (CIG) at
the University of Washigton. His work with the CIG has involved an analysis of
ite impact of Global Warmg on the hydo facilties on the Snake River. It also
¡icludes an investigation into water markets in the Northwest and Florida. In
r,ddition he has analyzed the economics of snowmakig for ski area's impacted by
Global Warmig.
IAmong Dr. Readig's recent projects are a FERC hydropower relicensing study (for
the Skokomish Indian Tribe) and an analysis of Northern States Power's North
lOakota rate desig proposals affectig large industral customers (for J.R. Simplot
Company). Dr. Readig has also performed analysis for the Idaho Governor's
Office of the impact on the Northwest Power Grid of various plans to increase
salon runs in the Columbia River Basin.
lOr. Reading has prepared econometrc forecasts for the Southeast Idaho Counci of
Governments and the Revenue Projection Commttee of the Idaho State
!Legislatue. He has also been a member of several Nortwest Power Plannig
Council Statistical Advisory Commttees and was vice chaian of the Governor's
~conomic Research Council in Idaho
~e at Idaho State University, Dr. Reading performed demographic studies using
cohort/ survval model and several economic impact studies using input/ output
analysis. He has also provided expert testiony in cases concerning loss of income
esultig from wrongfu death, injur, or employment discriation. He is
currently a adjunct professor of economics at Boise State University (Idaho
econòmic history, urban/regional economics and labor economic.)
Dr. Readig has recently completed a public interest water rights transfer case. He
has also just completed an economic impact analysis of the 2001 salon season in
Idaho.
Don C. Readig
Publicatiom "Energiing Idaho", Idaho Issues Onlie, Boise State University, Fal 2006.
~. boises tate. edu/history / issues online/ fal006 _issues / index.h tt
Ifhe Economic Impact of the 2001 Salon Season In Idaho, Idaho Fish and
¡Wildlfe Foundation, April 2003.
Ifhe Economic Impact of a Restored Salon Fishery in Idaho, Idaho Fish and
¡Wildlfe Foundation, Apri, 1999.
Ifhe Economic Impact of Steelhead Fishig and the Retu of Salon Fishig in
~daho, Idaho Fish and Wildlfe Foundation, September, 1997.
~Cost Savigs from Nuclear Resources Reform: An Econometrc Modelê (with E.
~ay Canterbery and Ben Johnson) Southern Economic Journal, Spring 1996.
iA Visitor Analysis for a Birds of Prey Public Attraction, Peregre Fund, Inc.,
November, 1988.
~nvestigation of a Capitalation Rate for Idaho Hydroelectric Projects, Idaho State
Ifax Commssion, June, 1988.
"Post-PURPA Views," In Proceedigs of the NARUC Biennial Reguatory
Conference, 1983.
iAn Input-Output Analysis of the Impact from Proposed Miing in the Chals Area
(with R. Davies). Public Policy Research Center, Idaho State University, Februar
1980.
¡Phosphate and Southeast: A Socio Economic Anafysis (with J. Eyre, et al). Governent
~esearch Institute of Idaho State University and the Southeast Idaho Council of
Governments, August 1975.
!tstimating 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 Expenditues: An Interstate Comparison,
I
~33-1939 and 1961-1965." In The American Economist,
01. XVIII, No.2 (Fal 1974), pp. 125-128.
I
"New Deal Activity and the States, 1933-1939." In Journal of Economic History, VoL.
iXII, December 1973, pp. 792-810.
December
November
October
September
August
February
January
Marginal Generation Capacity Costs
July
June
May
April
March
0.00 25.0015.00 20.005.00 10.00
.IPC-E-03-13 .IPC-E-07-08. IPC-E-05-28 IiIPC-E-08-10
Exhbit 202Rea Ding,
IPC-E-08-10
Decem ber
N ovem ber
o ct 0 b e r
Septem ber
Aug u st
July
J un e
May
April
Marc h
February
January
MarginalPowerSupply Costs
0.00 20.00 60.00 80.00 1 00 .00 1 20 .00 1 40 .0040.00
.1 P C - E - 03 -1 3 .IPC-E -05-28 .IPC-E-07-08 IIIPC-E-08-10
Exhbit 203
Reang, Di
IPC-E-08- i 0
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PROJECT TEST YEAR COMPARD TO six MONTHS ACTUAL
Y-T-D Projected Y-T-D
Actuals Test Year Actuals Percent
Description June 2008 2008 times 2 of Actual
REVENUES
Tota other operati revenues...$19,383,561 $38,855,834 $38,767,122 100.2%
Oter Revenues (Acct415): Tota $419,699 $1,022,527 $839,398 121.8%
Net income (eargs to Idao Power Company).....($1,064,296)$6,828,651 ($2,128,593)-320.8%
EXPENSES
Oter Expees (Acct 416): Total $212,566 $632,354 $425,132 148.7%
Total electc operation & maten exp.$151,631,416 $295,910,705 $303,262,832 97.6%
Tota proper insurance.......................................$1,532,063 $3,196,433 $3,064,126 104.3%
Total reguatory commssion expenses...........$2,239,059 $6,617,258 $4,478,118 147.8%
Amort., Adj, Gaioss Reguatory Assets ($22,236)($32,881)($44,472)73.9%
DEFFERED PROGRAS
IPUC Order 27660 / 27722 / 28041.......... ......................
Oter Tota............................ ....................... ...................
$6,485,237
$1,646,243
$12,970,474
$3,292,486
$4,863,935
$1,378,360
37.5%
41.9%
source: Idaho Power Company's Supplementa Response to the First Production Request
of the Industral Customers ofidaho Power, Supplemental Response for Production No.7.
Exbbit209
Reang, Di
IPC-E-08-10