19901210Vol IV Hearing.pdf

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/7799
ORIClrlAL
Or:f'i:iv¡:n ix
BEFORE THE IDAHO PUBLIC UTILITIESILE~iSsiN
90 DEC 16 Pll 'l 15
)
) DAHO PUBUC
) llTìLlTlES COMMISSION) .
) CASE NO. IPC-E-90-8
)
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IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR A
CERTIFICATE OF PUBLIC CONVEN-
IENCE AND NECESSITY FOR THE
RATE BASING OF THE MILNER
HYDROELECTRIC PROJEÇT, OR IN
THE ALTERNATIVE, A DETERMINATION
OF EXEMPT STATUS FOR THE MILNER
HYDROELECTRIC PROJECT.
BEFORE
,
COMMISSIONER DEAN J. MILLER (Presiding)
COMMISSIONER RALPH NELSON
COMMISSIONER PERRY SWISHER
PLACE:Commission Hearing Room
472 West Washington
Boise, Idaho
DATE:November 28, 1990
VOLUME IV - Pages 296 - 392
7..EORICKCOURT REPORTING
537 W. Bannock P.O. Box 578
Suite 205 Boise, Idaho 83701
[phone]'-./
. . . We offer .. BaData
Microtranscription™ by
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APPEARANCES
For the Staff:BRAD M. PURDY, Esq.
Deputy Attorney General
412 West Washington
Boise, Idaho 83120
For Idaho Power
Company:
EVANS, KEANE, KOONTZ, BOYD
SIMKO &: RIPLEY
by LARRY D. RIPLEY, Esq.
Idaho First Plaza-Suite 1101
101 South Capitol Boulevard
Boise, Idaho 83702
For the Industr ial
Customers of Idaho
Power Company:
DAVIS WRIGHT TREMAINE
by GRANT E. TANNER, Esq.
1300 S.W. Fifth Avenue
Suite 2300
Portland, Oregon 92701-and-
DAVIS WRIGHT TREMAINE
by PETER J. RICHARDSON, Esq.
400 Jefferson Place
350 North Ninth Street
Boise, Idaho 83102
For I daho ConsumerAffairs, Inc.:HAROLD C. MILES
316 Fifteenth Avenue South
Nampa, Idaho 83651
HEDRICK COURT REPORTING
P.O. Box 578, Boise, ID 83701
APPEARANCES
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1 I N D E X
3 EXAMINATION BY PAGEWITNESS
4 Thomas Faull
(Staff)
Mr. Purdy (Direct)
Prefiled Testimony
Mr. Miles (Cross)
Mr. Richardson (Cross)
Mr. Ripley (Cross)
Commissioner Swisher
Commissioner Nelson
Commissioner Miller
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15 EXHIBITS
297
299
323
330
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371
380
388
18 FOR THE STAFF:
PAGE17NUMBER
16
19 Qualifications of Thomas G. Faull,
P.E. of the Idaho Public Utilities
Commission (4 pages)
Premarked
Premarked
Premarked
101.
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21 IPCo Average Hydro Var iable Costs
(2 pages)
102.
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103.Three-page exhibit sponsored by
Thomas Faul 123
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HEDRICK COURT REPORTING
P.O. Box 578, Boise, ID 83701
INDEX/
EXHIBITS
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BOISE, IDAHO, WEDNESDAY, NOVEMBER 28, 1990, 9:30 A. M.
COMMISSIONER MILLER: Good morning, let's
resume our hear ing in Case IPC-E-90-8 and have the record
show that all parties who were present yesterday are
present in the hearing room today as well.
Last evening we ended with the question
before us of how to treat the transcripts in the two
cases, whether the cases are considered consolidated or
not consolidated. What the Commission I think would
propose to do is in its decision making in the Swan Falls
case we would take into account and have before us the
transcript of the Milner case as well; so that any matters
that were discussed in the Milner case could be considered
essentially in the Swan Falls case. This would eliminate,
I think, the necessity for repeating in the record of the
Swan Falls case topics that were covered in the Milner
case and which party would 1 ike to have in the record in
the Swan Falls case.
Then in the event that any party took an
appeal from the decision in the Swan Falls case, the
reporter's transcript for purposes of appeal would include
the Milner transcript. That's our thought on how to
approach this. Would that be acceptable to everyone?
296
HEDRICK COURT REPORTING
P.O. Box 578, Boise, ID 83701
COLLOQUY
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MR. RIPLEY: Yes, sir.
MR. PURDY: Yes.
COMMISSIONER MILLER: Mr. Richardson?
MR. RICHARDSON: Yes, Mr. Chairman.
COMMISSIONER MILLER: Let's plan on handling
it in that fashion, then; so I think that brings us, then,
to the Staff case.
MR. PURDY: Thank you. The Staff would call
Mr. Tom Faull.
THOMAS FAULL,
produced as a witness at the instance of the Staff, having
been first duly sworn, was examined and testified as
follows:
DIRECT EXAMINATION
BY MR. PURDY:
Q Would you please state your name?
A My name is Tom Faull.
Q Are you the same Tom Faul 1 who has filed
direct testimony in this case consisting of 24 pages and
Exhibi ts 101 through 103?
A Yes, I am.
Q And do you have any changes to your direct
297
HEDRICK COURT REPORTING
P.O. Box 578, Boise, ID 83701
FAULL (Di)Staff
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1 testimony, Mr. Faull?
2 A Yes, on Page 5, Line 4, the last set of
3 letters in that is the unit megawatt hours and that unit
4 should have been megawatt hours per year to indicate
5 annual generat ion as opposed to gene rat ion for some other
6 period.
7 Q So following the figure 186,395 megawatt
8 hours, that should be per year?
9 A Yeah.
10 Q Aside from that, if I were to ask you the
same quest ions today as contained in your direct
12 testimony, would your answers be substantially the same?
13 A Yes, they would.
MR. PURDY: With that, I guess I'd ask that14
15 the direct test imony of Mr. Faull be spread upon the
record as if read and that Exhibi tsl0l through 103 be16
17 identified for the record.
18 COMMISSIONER MILLER: So ordered.
19 (The following prefiled testimony of
20 Mr. Thomas Faul 1 is spread upon the record.)
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298
HEDRICK COURT REPORTING
P.O. Box 578, Boise, ID 83701
FAULL (Di)
Staff
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Q. Please state your name and business
address for the record.
A. My name is Thomas Faull and my business
address is 472 West Washington Street, Boise, Idaho.
Q. By whom are you employed and in what
capaci ty?
A. I am employed by the Idaho Public
Utilities Commission as a Public utilitìes Engìneer.
Q. Have you included a statement of your
qualifications in this testimony?
A. Yes. Exhibit No. 101 is a statement of
my qua i i f icat ions.
Q. What is the purpose of your test imony?
A. The purpose of my testimony is to discuss
the cost effectiveness of Idaho Power Company's (¡PCo' s)
proposed project, to provide an engineering opinion as
to the appropriateness of the project, and to recommend
Commission action relative to the project.
Q. Why is it important to know the cost
effectiveness of a project when determining whether or
not to grant it a Certificate for the present Public
Necessity and Convenience (Certificate)?
A. Although the basic criterion for granting
a Certificate is "need for power" l the criteria for
determining the applicabi Ii ty of a Certificate to a
IPC-E-90-8
11/9/90 FAULL (Di)Staff 1299
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specific resource should include the cost of generation
from that resource relative to other potential
resources.
Q. What is the starting point for analyzing
the cost effectiveness of this project?
A. First, one must attempt to quantify the
construction cost of the project, then translate that
cost into a unit cost of generating energy.
Q. What do you estimate the cost of this
project will be?
A. Rather than estimating the construction
cost of the project, I have accepted IPCo' s proposed
cap on capital costs of $63,350,600 as a maximum (or
worst-case) cost. Then, from that I estimate the 46
year levelized cost to ratepayers for this project will
be $62. 73/MWh.
Q. In his testimony Mr. Keen stated that he
estimated the cost of energy from this project to be
52.93 mills /kWh ($52. 93/MWh) based on 60 years of water
data or 37.80 mills/kWh ($37.80/MWh) based on 20 years
of water data. Can you explain the differences between
his estimates and yours?
A. Yes. There are several differences.
Fi rst, I did not consider the case of 20
water years. In Order No. 20924 (Case No. U-1006-265)
IPC-E-90-8
11/9/90 FAULL (Di)Staff 2300
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the Commission ordered IPCo to use the most recent 20
years of water data for retail ratemaking purposes,
rather than all available water data. This methodology
resulted from statistical evidence supporting 20 years
of data being the best predict9r of the flow in the
year immediately following that period, and was based
on the assumption that retail rates are set relatively
often. Thus it was determined that 20 water years is
the best predictor for short term analyses such as
those that apply to retai 1 rates. However, for a long
term analysis such as determining the value of genera-
tion from a resource with a 46 year life, one should
use a larger data base -- in this case, 60 years of
water data. The average of stream f lows over this
period are lower than over the 20 years used by
Mr. Keen, which reduces the estimate of annual average
generation and increases estimates of energy cost.
Second, Order No. 23357 (Case No.
IPC-E-89-11) established the following capital struc-
ture for determining the cost of long term generating
resources on IPCo' s system.
IPC-E-90-8
11/9/90 FAULL (Di)Staff 3301
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çompoiit.C-O~Ratljl
Debt 10.30%50%Preferred 10.29%10%
Common 13.17%40%
Weighted Cost 11.447%
I used this capital structure in my
analysis, rather than the capital structure used by
Mr. Keen, which was:
ÇQ.Qll ~Ratio
Debt 10.00%50%Preferred 9.50%10%
Common 12.25%40%
Weighted Cost 10.857%
Using the larger cost of capital
increases the estimated cost of generation.
Third, Mr. Keen used an estimated annual
Operations and Maintenance (O&M) cost of $272,217. My
analysis of IPCo' s historic operating costs for the
years 1985 through 1989 indicate that the appropriate
O&M cost estimate for a project of this size is $14/kW.
That yields an annual O&M cost of $815,780 in 1992
dollars, which is the value I used in my estimate for
this project's cost. This change also increases my
estimated cost of generation over Mr. Keen's estimate.
IPC-E-90-8
11/9/90
FAULL (Di)Staff 4302
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Fourth, Mr. Keen used an annual average
generation of 194,700 MWh in his analysis. However,
IPCo indicated in the FERC license application that I
yelrthe actual expected generation would be 186,395 MWh per
because of uni t unavai labi li ty. Therefore, I used
186,395 MWh/yr in iny cost analysis for this project,
which further increased my estimate over Mr. Keen's.
Fifth, Order No. 23357 determined that
the appropriate escalation rate for determining the
cost of resources on IPCo' s system is 4.5% per year.
This is the escalation rate I used in my analysis,
rather than the 4. ~% per year used by Mr. Keen, again
resulting in a higher estimate than Mr. Keen' s.
I must also note that both Mr. Keen and
I used 0.7381% of capital cost as the property tax
rate for our analyses, even though Order No. 23357
required i. 0% as the property tax rate for the
Surrogate Avoidable Resource (SAR) of the avoided cost
determination. I accepted Mr. Keen's rate because I
assume that IPCo is much more capable of accurately
estimating the property tax rate of hydro plants in
Idaho than any of the pa rt ies were of est imat ing the
property tax rate of a coal fired plant in Wyoming.
Q. Can you further explain the analysis you
did to estimate annual O&M costs?
IPC-E-90-811/9/90 FAULL (Di)Staff 5303
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A. Yes. Using pp. 406-A through 407-B of
IPCo's FERC Form 1, I determined the rated capaci ty,
net generation, and variable operating cost for each
year from 1985 through 1989, inclusive, for each of
IPCo's 14 major existing hydro electric plants. Using
Consuiner Price Index (CPI) data and the escalation
rates required in Order No. 23357 for future years, I
adjusted the cost data to 1992 dollars. I then
computed the cost per kW of rated capacity for each
year for each plant. After a subjective determination
that the variation from year to year of the costs per
kW of capacity was acceptable, I averaged the 5 years
of data for each plant. I then graphed the cost per
kW relative to the rated capaci ty. The resul ting graph
is included as Exhibit No. 102, and the data from which
Exhibit No. 102 was derived are included as Exhibit No.
103.
As can be seen from Exhibi t No. 102, the
data yield a relatively smooth curve, except for one
significant hydro plant, so it is reasonable to inter-
polate between data points provided there is a reason-
able explanation for the aberrant plant. The aberrant
plant is Swan Falls, which is substantially more
expensive to operate than would be expected in
comparison to IPCo' s other plants. Although I didn' t
IPC-E-90-811/9/90 FAULL (Di)Staff 6304
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confirm it, I assumed that the excessive cost of Swan
Falls is due to its remote location and antiquated
control system. Thus, it is apparent from the graph
(Exhibit No. 102) and the data from which it was
developed (Exhibi t No. 103) that one should expect
IPCo to experience O&M costs of about $14/kW for a 58
MW hydro plant. This is the rate I used in my
analysis. It must be noted, however, that because the
Milner Plant will be an integral part of a complex
irrigation system, it would not be unreasonable to
assume that its operating costs might be relatively
higher than IPCo' sother plants, as compared herein.
Q. According to Order No. 23357, the maximum
avoided cost rate available to Qualifying Facilities
(QFs) in Idaho (as defined under the Public Utility
Regulatory Policies Act of 1978 (PURPA) J corning on
line in 1992 is $57. 53/MWh. In light of this, do you
consider your estimated cost of $62. 73/MWh to represent
a cost effective proj ect for IPCo' s ratepayers, at
least as compared to avoided cost rates?
A. Yes, I do. For at least three reasons,
the published avoided cost rates are not appropriate
for direct comparison to a cost estimate of a specific
project. First, the computer model that computes the
published avoided cost rate assumes a "first deficit
J
IPC-E-90-811/9/90
FAULL (Di)Staff 7305
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year" (i.e. year of new resource need) of 1993 for
IPCo. I currently believe that, as clearly explained
in IPCo's petition for reconsideration in Case No.
IPC-E-89-11, the correct first deficit year should
have been 1994. Based on the assumption that the
Commission will authorize this change, I have deter-
mined that the comparable avoided cost rate (without
"tilting") would be $50.40/MWh.
Second, the published rates include an
adjustable portion of $8. 78/MWh that will be adjusted
in the future based on actual operating costs of the
Colstrip coal fired generating plant. For direct
comparison to an actual project the adjustable portion
should be assumed to escalate at the same rate as
comparable costs associated with the actual project.
When this adjustment is made the comparable 20 year
avoided cost rate (without "tilting") is $60. 12/MWh.
Third, even as adjusted above, the
published avoided cost rates apply only to projects
with a 20 year availability to IPCo. Although there
have been numerous arguments made about the unfairness
of limiting QF contracts and their rates to 20 years,
nonetheless, from a ratepayer viewpoint IPCo's 46 year
project should be compared to 46 years of avoidable
costs. That is, when IPCo builds a resource with a 46
IPC-E-90-811/9/90
FAULL (Di)Staff 8306
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year life ratepayers can reasonably expect that they
will have access to the energy from that resource for
the full 46 years, so other resource costs can be
avoided for the full 46 years.
Using the SAR methodology specified by
the Commission, assuming a new SAR will be built at
the end of the 35 year life of the first SAR, assuming
a first deficit year of 1994, assuming that the adjust-
able ~ortion will escalate, and assuming an on-line
year of 1992 yields an avoided cost of $65. 28/MWh.
Taking into account the seasonali ty weighting of
avoided costs relative to the availability of the
Milner Plant reduces the value of the avoided costs
applicable at Milner to $61.35/MWh. This is the
appropriate avoided cost rate to use for determining
the cost effectiveness of the Mi lner Plant.
Thus, the Milner Plant, with an estimated
cost of $62. 73/MWh is cost effective wi thin reasonable
limits of estimating accuracy. (62.73/61.35 - 102.2%)
Q. You indicate that there has been a
Petition for Reconsideration of Order No. 23357 filed
that could affect the "first deficit year" of the
avoided cost computation. Are there any other issues
pertinent to that petition that might affect the
avoided cost rate comparable to the Milner Plant?
IPC-E-90-811/9/90 FAULL (Di)Staff 9307
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A. There is a poteiitial that a mathematical
error made in Case No. WWP-E-89-6 wi 1 1 cause a change
in the estimated cost of transmission construction in
that case and that the WWP transmission cost change
will flow through to Case No. IPC-E-89-11, thus sightly
reducing the avoided cost rates comparable to the
Mi lner Plant. i would expect that change to be less
than 3% of avoided cost. Otherwise, I believe that
none of the issues pertinent to the petition for
reconsideration of Order No. 23357 will affect the
avoided cost rate that is comparable to the Milner
Plant.
Q. Suppose for a moment tha t, as a result
of this (or some future) proceeding, the estimated
cost of the Milner Project is found to be substantially
greater than your estimate or the comparable avoidable
costs are found to be substantially less than your
estimate. For example, assume that the Commission
determines that the Mi lner costs should be compared to
the interim 20-year avoided cost rates in effect prior
to Order No. 23357. Under those conditions, would you
still consider the Milner Project to be cost effective?
A. No. Under those circumstances I believe
IPCo should be limited in its recovery to an accurate
Commission determined comparable avoided cost rate.
IPC-E-90-811/9/90
FAULL (Di)Staff 10308
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Q. Other than using pre-Order No. 23357
avoided cost assumptions, are there any obvious condi-
tions that might be found appropriate for reducing the
comparable avoided cost rate for evaluating the Milner
Plant?
A. Yes. The computation of avoided cost
rates for purpose of evaluating capacity and energy to
be purchased under PURPA specifically excludes the use
of projected future purchases of QF power and demand
side resources (conservation) for estimating the first
year of power need for each utility. Although this is
appropriate for PURPA applications (as explained else-
where, including in Order No. 22636), it could easily
be argued that it is not appropriate for evaluating
the ut iIi ties' proposed resources.
This is especially true in the case of
conservation resources. The Commission has been
encouraging Idaho uti li ties to acquire cost effective
conservation resources for years, but wi th li tt le
avail. Now, when it appears that new resources are
needed, the utilities have little conservation
"on-l ine", and are essent i ally unprepa red to agg res-
sively bring such resources on line. Therefore, it
appears inéqui table to ascribe a benefi t to IPCo in
evaluating its supply side resources by ignoring the
IPC-E-90-8
11/9/90 FAULL (Di)Staff 11309
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imputing prior and future demand side resource
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utility's apparent negligence in acquiring demand side
resources.I believe the Commission should consider
acquisition to IPCo for the purpose of evaluating
proposed supply side resources, including the Milner
Plant.
Q.Wouldn't such limitations unfairly deny
IPCo from recovering prudently incurred investment
costs?
A.IPCo made its decisions, commit-No.
ments,and contracts relative to this Project without
a Certificate, even though one was clearly required
prior to beginning "construction".Furthermore, it
did so whi le fully aware of the interim avoided cost
rates, whi le arguing for future avoided cost rates
substantially less than those included in Order No.
23357, while fully aware of the Commission's position
on cost effective conservation resources, and whi Ie
fully aware of the SAR methodology ordered by the
Commission. Therefore, based on the knowledge and
assumptions that IPCo was publicly espousing at the
time it made those decisions, commitments, and
contracts relative to this Project, they appear, on
their faces, to have been imprudent. It is only as a
result of chance that the decisions have subsequently
IPC-E-90-8
11/9/90
FAULL (Di)Staff 12310
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turned out to appear marginally prudent (at least as
determined by my analyses). Therefore, if it is
determined that my analyses are in error and that the
Milner Project costs are not less than avoided costs,
IPCo should be imputed to have known that the project
was not cost effective, at leas t to the extent that
Mi lner costs exceed avoided costs us ing the assumptions
included in IPCo' s recommended avoided costs in Case
No. IPC-E-89-11 and, perhaps, imputed conservation
resource acquisitions.
Q. In your statement of purpose you said
that you would ".. .provide an engineering opinion as
to the appropriateness of the project...". What did
you mean by that?
A. I meant that in addition to providing an
analysis of the cost effectiveness of the project as
proposed by IPCo, I would provide an engineering
opinion relative to the IPCo proposa I being the most
cost effective development from the family of reason-
ably potential developments at the site -- that is, an
opinion as to whether I believe IPCo has provided the
most cost effective development practicable for this
resource.
Q. What is your opinion in this regard?
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A. Before answering that question, I should
make two important qualifying points. First, it is
much eas ier to second-guess the qua 1 i ty of a proj ect
after someone else has spent the money and labor to
develop it than it is to actually do the development.
Second, it appears that IPCo has made a substantially
greater effort to control costs on this project than
on many of its prior power supply developments.
Nonetheless, bearing those two caveats
in mind, it does not appear to me that IPCo has made
the same level of project optimization effort that one
would find in a QF development. The most glaring
weakness that I find in the project is in the royalty
agreement with the canal companies. Even though the
irrigators were faced with mandatory dam repairs and a
hydro electric project that could not be made cost
effective under avoided cost rates extant at the time,
the final royalty agreement not only assures the canal
companies that they wi II recover a II of thei r costs of
implementing dam repairs, it also assures them of a
substantial profit on their investment. This is hardly
the result one would expect from a QF developer's
negotiations. In fact, I expect that the irrigators
would have ended up with only partial reimbursement
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for their dam costs, not a profit, if dealing with a
QF developer.
Next, it appears that the Mi lner Plant
has been over-sized for the flows at the si te. The
overall average capacity factor of the project is less
than 36% and the average estimated capacity factor in
the most productive month (December) is less than 60%.
The standard in the industry is typically for overall
capacity factors of between 45% and 65%. In general,
cost effectiveness improves as capacity factors
increase, up to about 65%.
Finally, it appears that IPCo used the
standard firm bid process to procure equipment and
construction services, rather than the more cost
effective request for proposals (RFP) and negotiation
process. Although the bidding method is immune to
administrative challenge because it appears to result
in supplier competition, my experience has been that
it actually stifles competition and results in higher
costs; especially on large, complex projects such as
the Milner Plant.
There are several reasons for this.
Foremost among them is that in preparing requests for
bids the design engineer is constrained to "guessing"
about the best combinations of size, arrangement, and
--
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timing, with minimal input from suppliers; whereas in
competitively negotiated contracts based on RFPs the
suppliers are challenged to provide their most innova-
tive combinations with fruitful give-and-take discus-
sions between supplier(s), the owner, and the engineer.
In my experience, this method almost always results in
better projects at lower cost. Furthermore, it reduces
the probability of suppliers receiving cost over-run
payments for extra work, unexpected condi tions, and
ambiguous contract language being construed against
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the owner (the risk of over-run payments is reduced in
this case because the contract is drafted jointly by
all parties, not just the owner).
Q. Is the entire royalty agreement between
IPCo and the irrigators disadvantageous to IPCo and
its ratepayers?
A. No. The royalty agreement has two
components, a base royalty and an incentive royalty.
The base royalty assures the irrigators of recovering
nearly all of the costs of constructing the dam
modifications -- this is the part of the royalty I
consider to be excessive. The incentive royalty, on
the other hand, is very beneficial to ratepayers.
Q. Why is the incentive royalty beneficial
to ratepayers?
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A. Because it provides the irrigators with
a strong financial incentive to limit their water use
during good water years, and even provides some
incentive for irrigation efficiency during moderate
water years. I base this opinion on the secondary
value of the water that will pass through the turbines
at Mi lner. Al 1 water above mean flow condi tions tha t
passes through the Mi lner turbines wi II probably also
pass through each of IPCo' s other Snake River hydro
plants, except American Falls, which is upstream of
Milner. Although I have not quantified this value, it
will be substantial -- far in excess of the incentive
royalty cost.
Q. Do you propose that project costs should
be disallowed for ratemaking purposes because you
believe IPCo has not optimized its Milner resource?
A. No. My speculative criticisms do not
provide evidence of imprudent management. I merely
include this part of my testimony to provide support
for the position that IPCo should be held to the
standard of avoided cost in determining the ratemaking
allowability of new resource costs, and should be
required to fully justify its design and construction
decisions prior to such costs being allowed for rate
making purposes. Clearly the Milner Plant could not
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be developed as proposed by IPCo if its costs had to
be recovered under a QF contract, even under the rates
included in Order No. 23357 (which IPCo claims are too
high). Furthermore, it is my professional opinion
that the Mi lner si te could have been developed under
the 23357 rates by a QF developer, albeit only after
hard-nosed negotiations with irrigators and suppliers.
However, because it would be near ly
impossible to provide evidence to prove that IPCo had
not provided the optimum development for the resource,
the Commission is limited to using avoided cost as the
imputed surrogate for identifying prudent decision
making. The utility is perfectly able to determine
how its proposed projects stack up against comparable
avoided costs and it is perfectly capable of estimat-
ing the risks that its cost estimates may be low, so
it should be held accountable for keeping its costs
below those comparable avoided costs. Ratepayers
should not be held at risk for utility executives'
poor decision making beyond what has clearly been
established as achievable costs -- in fact costs the
utility claims are excessive (i .e., avoided cost).
It's bad enough that it is impossible to identify and
reject sub-optimal features that cause excess costs
below avoided costs.
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Q. What are your recommendations in this
case?
A. I recommend that, based on the estimate
that the Mi Iner Proj ect (as proposed by IPCo) wi I I
provide energy at approximately avoided costs, the
Commission grant a Certificate for the present Public
Convenience and Necessity for the Milner Hydro Electric
Plant, with the specific caveat that costs in excess
of the appropriate comparable avoided cost rate (to be
determined in a future rate making case) are, by
definition, imprudently incurred. I further recommend
that the Commission advise IPCo that this Certificate
in no way implies that all costs incurred in develop-
ing the project are inherently prudent, but that the
Commission will review all costs so incurred at a
later date and will determine at that time whether
IPCO's execution of the project was prudent in light
of the generally accepted standards of the hydro
electric construction industry.
Q. Did you consider IPCo' s suggestion that
the Milner Project not be included in rate base until
after it had operated for a 20-year period as an
unregulated resource ("20-year deferral" proposal)?
A. Yes, but I rejected the suggestion
because i estimate project costs to be approximately
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equal to avoided costs.
Q. If the estimated project costs are
determined to be greater than avoided costs will you
recommend that IPCo' s suggestion be accepted?
A. Maybe. However, that proposal presents
several difficult problems and risks. I believe it
would be extremely difficult to establish a completely
independent non-regulated subsidiary with clear
controls to assure that there can be no cross subsidi-
zation between that company and the regulated uti li ty.
Please note that a major factor in the difference
between IPCo' s cost estimate for the Mi lner Plant
($52.93/MWh) and mine ($62. 73/MWh) is the difference
between IPCo' s O&M cost estimate ($272, 217/yr) and
mine ($815, 780/yr). If the Commission sets up a
situation where IPCo is forced to recover its costs by
marketing the output of Milner in the compet i t i ve
wholesale market,there will be extremely strong
incentives for IPCo to allocate O&M costs actually
incurred in support of Mi lner to other accounts.
Although O&M costs would be fairly easy to audit,
Staff witness Miller includes in her testimony other
sound arguments against accepting without modification
IPCO's "20-year defer ra i" proposa l.
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Q. What are some of those other potential
areas of cross subsidization that might be particu-
larly applicable to an IPCo subsidiary marketing
wholesale electricity?
A. There are a number of services implicitly
and explicitly available to wholesale electricity
customers from utility generators that are not
typically available from independent (non-utility)
generators. Among these are wheeling services,
wheeling contract negotiating services, plant reserve
power, back up capaci ty and energy, dispatch services,
true-up services for ramping delays, etc. The explicit
services could be moni tored by staff, albei t wi th some
difficulty, but it would be impossible to ascertain or
estimate the level or value of implicit services being
supplied to the subsidiary's customers through the
parent (IPCo).
Q. Although you generally disagree with
applying IPCo' s "20-year deferral" proposal to this
project, do you believe there may be projects where it
would be more appropriate?
A. Again, maybe. But it is unlikely that
the proposal would be appropriate for any project
wi thout substantial modif ications to IPCo l s proposa i
(at least as extensive as suggested by Ms. Miller in
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her testimony). It seems to me to be more appropriate
in mos t ci rcumstances to requi re IPCo to commi t only
to acqui re resources that are cost effective relative
to avoided costs, considering all non-quantifiable
relative risks. Nonetheless, as Ms. Miller points
out, it would be unreasonable to presume that an option
such as IPCo proposes could never be appropriate.
Q. What kinds of "non-quantifiable relative
risks" should be considered, and how?
A. A couple of the "relative risks" that
come to mind immediately are, for the Milner Project,
the risk that future Snake River f lows at the site may
be more (less) than the historic flows and that the
environmental impacts of the project may be more
(less) than expected. For potential thermal projects
that could compete economically with the Milner
Project, a couple of the "relative risks" that come to
mind immediately are the risk that future fuel will be
unavailable, undeliverable, or more (less) expensive
than expected, and that the environmental impacts of
such a project may be more (less) than expected.
Because such risks are inherently
unquantifiable, decision makers must make their own
best estimate of the level and impact of each of the
potential occurrences actually happening and then
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decide how to factor that risk into granting or ldenying Certification and/or rate making application
of proj ect costs.
For example, it is currently taken as an
historic axiom that hydro plants have "always" been
more cost effective than thermal plants, so we should
expect them to be more cost effective in the future.
However, on careful reflection, it becomes apparent
that the reason that hydro has been more cost effective
than thermal is that fuel costs have escalated much
more rapidly than expected. Thus, the critical ques-
tion when comparing a specific hydro plant to potential
thermal plants is "How does the probability that we
have over (under) estimated water flows compare to the
probability that we have over (under) estimated fuel
costs?".
Q. Doesn't the consideration of unquantifi-
able risks invalidate the concept of using avoided
cost as the only implied surrogate for estimating
prudent project selection and management?
A. Yes, slightly. Rather than using avoided
cost as the only measure of prudence, the Commission
should use avoided cost as the presumed measure of
prudence. Thus, as part of its application for rate
making treatment of any proj ect, a uti Ii ty should be
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expected to justify projected generation costs that
exceed avoided cost. That justification would be in
addi t ion to jus ti f ication for other facto rs and
conditions such as project size, contract over runs,
type of technology selected, method of project
management, etc.
Q. Does that conclude your testimony?
A. Yes.
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(The following proceedings were had in
open hear ing. )
MR. PURDY: And Mr. Faull is available for
cross-examina t ion.
COMMISSIONER MILLER: Thank you.
Mr. Miles, do you have questions?
MR. MILES: Yes, Mr. Commissioner, I have a
few.
CROSS-EXAMINATION
BY MR. MILES:
Q Mr. Faull, if you'd turn to Page 11 of your
direct testimony where you refer to the Idaho Power
Company's -- the Commission is encouraging Idaho utili ties
to acquire cost-effective conservation and down farther
you say, "the utilities have little conservation on line
and are essentially unprepared to aggressively bring such
resources on line," do you include Idaho Power Company in
that statement?
A Yes, I do.
Q To what action or inaction of Idaho Power
Company do you attribute their lack of acquiring
cost-effective conservation in the past?
A Well, you i re asking me to make a judgment
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and we i re talking about relative to what they could have
acquired and it i S my observation, has been my observation,
that the Company, that the Idaho Power Company, was not
eager to acquire conservation resources prior to maybe a
year-and-a-half ago and they made no effort that I could
see to put themselves in a position to ascertain what
conservation resources might be available wi thin their
service terri tory or to acquire any of those potential
resources, but that's a personal observation.
Q Yes. If you'd turn to Page 12, beginning
about Line 20, you say, "Therefore, based on the knowledge
and assumptions that Idaho Power Company was publicly
espousing at the time it made those decisions, commitments
and contracts relative to this project, they appear, on
their faces, to have been imprudent." Would you please
explain what actions were imprudent in your opinion?
A The commitments that the Company made to
acquire a resource that clearly had costs in excess of
what the Company was espousing as its next or was
espousing as a reasonably acquirable cost for new
resources to me appears to be imprudent; that is to say,
that the Company was suggesting that the cost for them to
acquire new resources was something less than five cents
per kilowatt hour, substantially less than five cents per
kilowatt hour, yet the Company at the same time was making
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commi tments to acquire a resource that clearly was going
to cost them in excess of five cents per kilowatt hour.
Q Thank you. I f you i d turn to Page 14 and in
the last sentence says, "In fact, I expect that the
irrigators would have ended up with only partial
reimbursement for their dam costs, not a prof it, if
dealing with a QF developer." Could you please explain
why the irrigators shouldn't have received a prof it on
their dam repairs?
A I think I did explain that in my test imony
that the irrigators were in a position where they had to
do something with the dam that supplied them water to
irrigate their fields so that they could stay in
business. Essentially, they were in a position that they
had to choose between upgrading their dam or going out of
business and the estimated cost that is included in this
filing for that upgrade is $11 million, roughly. It seems
like the irrigators would have been pleased to get any
portion of that paid for by someone other than themselves.
Q Well, Mr. Faull, are you familiar with the
fact that a lot of irrigation and canal companies have
gone to the Idaho Department of Water Resources or the
Idaho Water Board and applied for a low interest loan to
do such type of repairs?
A I'm not familiar with that, but that's, I'm
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not sure why that would be relevant to this other than
it's perhaps a less expensive way for them if they didn't
have some other entity to pick up the costs entirely.
They could at least reduce their finance costs through a
method like that.
Q If they had borrowed the money, for example,
from the Idaho Department of Water Resources, they
wouldn't have received a prof i t on the cost of the
repairs, would they?
A Certainly not. That would have been a
substantial expense.
Q Thank you.
Q If you would please turn to Page 15,
beginning on Line 3 you say, "Next, it appears that the
Milner plant has been over-sized for the flows at the
si te." What size plant in megawatts do you believe the
Milner plant should be to be most cost-effective?
A I haven't done a detailed analysis that I
would feel comfortable saying I know precisely what size
it ought to be. The range of capacity factors that I
suggest of 45 to 65 percent would probably yield a plant
on the order of 40 to 45 megawatts. It might be a broader
range than that, I haven't computed it, but something in
that general range.
Q I see. Mr. Faull, I have a couple of
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general questions I'll ask. If you know, how long is the
Milner license issued by FERC, for how many years is that?
A It's my understanding that it's a 50-year
license and it starts, that time period starts, running in
1988, but I have not confirmed that. That's a general
understanding.
Q Well, based on your experience and knowledge
as an engineer, what would be the additional capital costs
Idaho Power Company would be expected to expend after the
expiration of the original license?
A That's a very diff icul t question to answer.
If that was a license that was expiring today, the Company
would probably be looking at up-rating the size of the
generators to reduce the plant factors. They would
probably be looking at some additional mitigation
expenses, but to predict today what might happen 50 years
from now is far beyond anything I'd care to do.
Q Well, ordinarily hydro generating stations,
they are designed and built to last for longer than 50
years, aren't they?
A Generally speaking, yes.
Q And that a big part of the up-front monies
has already been expended, hasn't it?
A At the point of relicensing, typically, at
least in a regulated, for a regulated utility, it's my
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understanding that the utility should have recovered the
full value of its plant, and I don't believe that the
intrinsic value of the hardware in place is imputed to the
utility, although again, this is a general understanding
and it i s subject to legal interpretation.
Q Well, wouldn't they possibly, say, outside
of upgrading the generators or rewinding them or any
addi tional O&:M expense wouldn't be nearly as great as the
original up-front cost, would it?
A No, the upgrade would cost less and, in
fact, that i s why on a relicensing, well, on an original
construction, a capacity factor of 45 to 65 percent is
probably the most cost-effective range. On a relicensing,
you can up-size your plant and live with a much lower
capacity factor because you're talking about receiving the
abili ty to generate the base load plant at essentially no
addi tional cost; so by dividing the new cost into the
entire generation capacity, you can invest a lot of money
for a small upgrade and still be a profitable investment.
Q Well, then if we apply that situation to
Milner, then the cost to generate the power for a kilowatt
hour would be considerably less after the expiration of
the 50-year license, wouldn't it?
A If you're asking me that what it would cost
Idaho Power Company to continue generating after they've
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recovered the full value of that plant at the end of 50
years, essentially, it would only cost O&:M which is a
relatively small part; so after 50 years the cost per
kilowatt hour of continuing to operate that plant would be
substantially less.
Q Well, then considering the fact that a
well-constructed hydro station would last longer than 50
years, then if we continued on down, then this hydro
station would be even a greater benef it for the ratepayers
of Idaho Power Company, wouldn't it?
A That makes the presumption that Idaho Power
Company will be able to relicense that plant after 50
years and there i s no reason to assume that that's the
case. If the laws are the same 50 years from now as they
are today that that site will be subject to competitive
relicensing and the irrigation company could file on its
own, Idaho Power could file, you could file, I could
file. There's no logical reason why we should assume that
Idaho Power Company will in fact get the benefits of that
plant after the license expires.
Q To your knowledge, is there anything in the
FERC license for the Milner station that doesn't give
Idaho Power Company the choice of the first refusal?
A Yes, the laws, my understanding of the laws,
as they exist today are that the Company does not have a
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right of first refusal. There is no preference and
whoever files the best development or improvement on thF
si te is likely to receive the new license. I
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MR. MILES: Thank you. I have no furtherl
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questions of Mr. Faull, Mr. Chairman.i
IMiles.
I,
COMMISSIONER MILLER: Thank you, Mr.
Mr. Richardson.
MR. RICHARDSON: Thank you, Mr. Chairman.
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CROSS-EXAMINATION
BY MR. RICHARDSON:
Q Mr. Faull, do you know whether the cost 0lf
these two projects --let me rephrase that.Do you knor
ii
how the cost of these two projects compare to Idaho I
Power's cost of conservation resources?
is.
I have a general idea of how that compariLon
IConservation resources are available over a broad I
A
i
range of potential costs, but it's generally accepted i~
Ithe industry and some of Idaho Power Company's recent i
experimental projects have shown that there are
conservation resources available in the state for
I
fivel
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substantially less than the avoided costs of under
cents per kilowatt hour; so that I would say that therel
are probably some conservation resources available for
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,less than two-and-a-half cents a kilowatt hour and on up
to whatever it is prudent to pay compared to other
potential resources; so the simple answer is that this
project appears to me to be much more expensive than a
great deal of conservation that is available.
Q Would your answer be substantially the sa~e
for demand side management resources?
A Yes. In fact, there are some proposed
demand side management resources that Idaho Power has
Iindicated they intend to implement that are substantiailiy
less expensive than this plant, on the order of less th~n
two cents a kilowatt hour.
Q And would your answer be substantially th~
¡
same with regard to off-system purchases, both on the f~rm
and secondary markets?
A Substantially, yes. There ought to be,
there are def ini tely some short-term and mid-term
resources avai lable at a lesser cost than this. I doubt
that there are any 50-year resources available probablyl at
!
any rate, but if there is a 50-year resource available, I i
would be unable to tell you at this time whether it wou~d
be more or less expensive than this resource.
Q Do you have an understanding of how the
Milner or Swan Falls projects fit into Idaho Power's lebst
cost planning process?
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A I understand how they fit into their
resource stack and their resource management report
resource plan and to some extent how they fit into their
least cost planning process that they i re doing for the
State of Oregon.
Q Could you explain to us br ief 1 y your
,
understanding for how those fit into Idaho Power' s lea~t
¡
cost planning process, then, for the State of Idaho?
A For the State of Idaho, the Company has
,
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presented these resources as non-avoidable, I guess youl'd
icall it lost opportunity resources. They've presented i
them as resources that they will build and it Iwill be plart
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Iof cost. I
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of their resource stack without consideration
your,
!Q When will we know what -- a large part ofl
a portion of your, testimony deals with estimatiJg
1
O&:M costs; correct?
A Yes.
Q When will we know what' Milner or Swan's
actual O&:M costs will be?
A We'll only know the actual costs after there
is some experience, and to know the long-term costs, we
would actually have to see the plant operate for several
years to find out whether the construction and the
management techniques are in fact what are expected.
Q For ratemaking purposes, would you agree
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that it's more accurate to use actual O&M costs rather
than estimated O&M costs?
A As far as I know for retail ratemaking
purposes, only actual costs are used.
Q In your opinion, is that preferable to using
estimated O&M costs?
A Whenever possible, yes.
Q When will we know what Milner or Swan Falls'
actual construction costs are?
A After the plants are completed and all the
claims are settled.
Q And when will we know whether Milner or Swan
Falls are actually being used to provide service to Idaho
Power's ratepayers?
A After they actually come on line and provide
energy for the benef it of ratepayers.
Q At Page 8. toward the bottom of Page 8, of
your prefiled testimony, you state that there have been
numerous arguments made about the unfairness of limiting
QF contracts and their rates to 20 years. Do you think
that those arguments have any more validity in light of
the Company's request to bring on line a 50-year resource
at rates that are actually higher than 50-year avoided
cost rates?
A Well, it certainly provides a graphic
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demonstration of what many QF representatives have stated,
that they do not have an opportunity to receive long-term
benef i ts for long-term projects even though the Company at
the same time proposing to deny those long-term benef its
to the QF community is attempting to procure those same
benefits for itself; so, yeah, I think this is a graphic
demonstration of some of the problems that we've discussed
in other cases about diff icul ties that QF' s will have
relative to the limitation of contract length.
Q Do you think it would be a proper resolution
of that perception of inequity to allow QF' s with a
50-year resource to enter into 50-year contracts with the
purchasing utility?
A That would certainly eliminate the perceived
lack of consistency. There are a number of assoc iated
issues with permitting long-term resources to come on to
the system without having the same level of control over
those, the quality and reliability of those resources,
that we have over the utility's, but there are certainly
ways that those problems could be solved.
The first thing that comes to mind is you
could provide opportunities for long-term contracts at
rates that are not levelized and eliminate some of the
risk involved, but that's an issue that's presently being
discussed in other cases and other than for a
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demonstration of why avoided costs are important relative
to new resources, this really isn't the place to delve
into that.
Q Well, getting back to my first question on
conservation, you stated that, you testified that there
were a number of megawatts available to Idaho Power
Company at less than the cost of Milner or Swan Falls.
Can you give us an estimate of how many megawatts you had
in mind that are actually less expensive than Milner or
Swan Falls?
A I'm not really prepared to do that. I guess
I can give you some related information that might give a
feel for it. One project that the Company has been
involved in is conservation for irrigators, improving the
efficiency of their pumping systems, and I'm going to
throw out some numbers here that I'm not precisely sure of
because I'm talking from memory of a meeting I sat
through, but the Company allocated something on the order
of $200,000 for these projects and they contacted a number
of irrigators to see what kind of interest they would get,
and they got such a good response that the money that's
available for investing in these resources that's
substantially less than avoided cost rates is nowhere near
adequate to service all the customers that are interested
in it.
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The Company has also stated in some of its
least cost planning meetings that at five cents a kilowatt
hour avoided cost rates, something on the order of 200
megawatts of QF power is avai lable to it, known projects,
not speculative projects, but developers who have projects
that they would like to build that they think that they
could build for on the order of five cents a kilowatt hour
and I'm talking from memory. Actually, the chart that I
saw showed four cents, five cents and six cents and it may
have been at six cents that it was 250 megawatts, but at
five cents it was c lose to that. If it would be useful, I
could get the exact numbers and put them into the record.
Q Wi th the understanding that you don r t know
the precise numbers, would you agree, though, that the
magni tude of conservation that is avai lable to Idaho Power
Company at costs less than what Milner or Swan Falls are
projected to cost exceed the magnitude of the potential
generation for Milner and Swan Falls?
A I think that they probably do, yes.
MR. RICHARDSON: Mr. Chairman, that's all I
have for Mr. Faull.
COMMISSIONER MILLER: All right, thank you,
Mr. Richardson.
Mr. Ripley.
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CROSS-EXAMINATION
BY MR. RIPLEY:
Q Mr. Faull, at Page 1 of your testimony on
Line 23, you state that although the basic criterion for
granting a certif icate is need for power, do you see that?
A Yes.
Q And in your colloquy with Mr. Richardson,
you stated that you are aware that it was the Company's
position that both Milner and Swan Falls were
non-avoidable. Are you also familiar with the term
non-deferrable?
A Yes.
Q Are those terms used synonymously as far as
you're concerned?
A No, they're not synonymous, in general,
they i re not synonymous, but in this case, I think it would
be reasonable to use them synonymously.
Q All right. Are you familiar with the term
that has been used in a number of these proceedings lost
opportuni ty?
A Yes, I am.
Q Now, it's the Company's position, is it not,
that Swan Falls and Milner are non-deferrable and if the
projects are not constructed now that opportunity will be
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lost; is that the Company's position as you understand it?
A That is the Company's position as I
understand it.
Q And I take it you disagree with that
position?
A ! don't disagree with the position that the
opportunity to develop these sites will be lost if they're
not taken at this time. I disagree with the position that
all opportuni ties should be taken regardless of cost. We
all have opportunities to buy things at more than they're
worth every day and we try to avoid those whenever we can.
Q And isn't that the position that the
Commission is confronted with in this proceeding and that
is that if Idaho Power Company does not construct Milner
and Swan Falls today those projects will be lost to the
State of Idaho?
A Not only could be lost to the State of
Idaho, but possibly should be lost to the State of Idaho.
Q All right, and that indeed is the question
that the Commission must answer, and that is that when
we're discussing need, as you describe it at the bottom of
Page 1 of your pref iled testimony, that is the issue in
this proceeding, is it not?
A What is the issue? I didn't understand the
question.
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Q The issue is should the Commission authorize
the construction of Milner and Swan Falls on the basis
that it is a lost opportunity and that it is Idaho Power
Company's position that those resources are
non-deferrable, the Commission can reject that and deny
the certificates; correct?
A They can do that, yes.
Q And if they do that, those projects would be
lost; correct?
A Lost in the sense that they would not be
bought by ratepayers.
Q But they'd be lost, they'd be lost to Idaho
Power Company and they would be probably lost to the State
of Idaho.
A They would be lost to Idaho Power Company as
a regulated utility. As far as Milner goes, I would say
that Idaho Power Company has so committed itself at this
point and so committed ratepayers at this point that I
cannot conceive of a way that ratepayers are not already
substantially at risk, and I think part of one of the
issues that we're looking at here today is whether or not
the Commission should have granted a certif icate at the
time Idaho Power Company should have applied for a
certif icate.
Q And I understand your position there, but
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1 it's also clear under Idaho law, is it not, that if the
2 Commission denies the construction costs and the purchase
3 of equipment to date that it will not be included in rate
4 base?
5 A That's my understanding.
6 Q So the ratepayer is not yet at risk, it is
7 the stockholder of Idaho Power that is at risk; isn't that
8 accurate?
9 A No, I don't believe so, not entirely. I
10 think that beyond the authority of this body lies the
authori ty of the courts and it's potentially possible that
12 ratepayers could be subjected to costs as a result of
Idaho Power Company's actions to date.
14 Q And that, obviously, is a legal opinion,
15 correct, which you and I can argue from now until it's
16 time to go home today; true?
17 A Yeah, I'll accept that.
18 Q But in point of fact, when the Commission
19 reviewed Idaho Power Company i s investment in Boardman and
20 determined that Idaho Power Company had purchased certain
21 equipment in advance of the certificate, it determined
22 that a portion of those costs should be written off
23 because Idaho Power Company had not rece i ved a
24 cert if icate; isn i t that true?
25 A That is true.
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1 Q And that Commission decision was appealed to
2 the Idaho Supreme Court, was it not?
3 A I'm not familiar with that, but if you say
4 so, I'm sure it is.
5 Q And would you assume for me that the Idaho
Supreme Court said if you don't apply for a certificate
and you purchase equipment in advance of that certificate
6
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8 it is a stockholder risk, not a ratepayer risk?
9 A I would certainly accept that subject to
10 check.
Q If that i s true, and Idaho Power Company has
12 invested dollars in Milner and the Commission denies the
14
certificate, then Idaho Power Company, in the words of
Mr. Packwood, will eat that investment if we follow the
15 decision that has been issued in the Boardman disallowance
16 case.
A In the scenario you paint, that's exactly
18 correct.
19 Q All right. Now, let's go back to my basic
20 premise again and that is, as I understand it, it is your
posi tion that although a certificate should be issued for
22 Milner, and for that matter for Swan Falls, that
23 certif icate in itself should make no determination as to
24 need at this time?
25 A No, that's not my position. My position is
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that the certificate should not be issued if there is no
need. If there is a need and a certificate is issued,
that should not make any statement or commitment as far as
whether the Company's actions on those projects have been
prudent to date.
Q But doesn't the Commission after it is
presented with Idaho Power Company's position that this is
a non-deferrable, that these are non-deferrable projects
and that if they are not built now they will be lost, the
Commission has to at least address that and say we
disagree, we're not going to issue a certificate on that
basis? We don't wait until the project is constructed to
decide what the Commission's position is on whether or not
these projects are non-deferrable and should be
constructed now; do you agree with that?
A In fact, I would say that we should not have
wai ted until the license was issued before we considered
these issues.
Q And I understand that, but the license has
now been issued. All right, what is your position as far
as what the Commission should do as far as the issuance of
the certificate that you recommend be issued as a result
of this proceeding?
A It's my recommendation that based on the
analysis of need for power and the analysis that these
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si tes potentially could have been developed
cost-effectively the Commission ought to grant the
certif icate if the Company thinks it wants the
certif icate, but the Company ought to be advised that that
does not imply that its actions to date have been prudent
or that it will recover expenses and costs committed to to
date.
Q What good is the certif icate on that basis?
What does the Company obtain?
A It obtains the right to do what it has
already done.
Q What else, anything?
A No.
Q Okay. Now, you also state at the top of
Page 2 that the specific resource should include the cost
of generation from that resource relative to other
potential resources; do you see that?
A Yes.
Q My question to you is when you refer to the
cost of generation from that resource, is that the cost
that the ratepayer will incur for that generation or the
cost that the utility will incur for that generation?
A Well, from my point of view, my interest is
in what cost the ratepayer will incur.
Q So what you i re talking about is the cost
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that this Commission will permit the utility to pass on to
the ratepayer in the form of revenue requirement?
A That's a fair characterization, yes.
Q All right. Now, you've also stated that you
would not use in your analysis the 20-year period of time
for determining the costs of Milner, but that you would
use a longer period of time, the 60-year period of time.
A Yes.
Q If the Commission sets rates based on 20
years of time, isn't that the cost to the ratepayer of
that project?
A At any given point in time, yes, but that i s
not the long-term cost of that project to the ratepayer.
Q If the Commission consistently sets rates
based on 20 years over the life of that project, why isn't
that the cost to the ratepayer?
A Because the 20 years used will change from
rate case to rate case, and over the life of a 50-year
project, the effect should be about the same as if the
Company had been, had had rates set over the long term
based on a longer period of time. These are statistical
issues and, obviously, you're not going to end up at
exactly the same point, but you should approach it.
Q That's the assumption, is it not?
A That's what statistics are based on.
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Q I understand, but that hasn't been proven,
has it?
A Mathematically, yes.
Q Let me put it this way: We do not know the
number of years that the Commission will use in the
Company's next revenue requirement, do we?
A No, we don't.
Q And if we don't know that, how are we going
to compute the cost to the ratepayer now?
A Using the largest number of water years
available since over the long term that is what the cost
to the ratepayer ought to be regardless of what changes
may come in the short-term analyses.
Q But if the rates of the Company are set on
20 years of water and for some reason the utility does not
apply for a change in those rates, then the cost to the
ratepayer is going to be based on the 20 years; correct?
A Well, that's an absurd assumption, but
that's correct.
Q Why is that? Why is it any more absurd than
your contending that 60 years of water is going to give
you the long-term cost to the ratepayer?
A Sixty years of water is going to give our
best estimate of the long term. The absurd assumption is
that the Company will never apply for another rate
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change. If the Company would like to commit to that
today, I suppose we might take a look at it.
Q Now, again on Page 3, on Line 10 you say,
"However, for a long-term analysis such as determining the
value of generation from a resource with a 46-year life,
one should use a larger data base -- in this case, 60
years of water data," that's what you're referring to when
you just responded to my questions?
A Yes.
Q Then isn't there a perpetual recalculating
of the cost to the ratepayer over the life of the project?
A Over the life of the project the rates will
be set on actual conditions and actual assumptions made at
the time and those could vary from the assumpt ions and the
data that we have today, yes.
Q One thing that would change is the rate of
return on equity that would be authorized the Company?
A Yes.
Q Now, on Page 7 in your answer you say,
"According to Order No. 23357, the maximum avoided cost
rate available to qualifying facilities in Idaho is
defined as 57.53"; correct?
A Correct.
Q All right. Now, that method is a method by
which you compute the avoided cost rates that the utility
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is required to offer to purchase power from cogenerators
and small power producers; is that right?
A Yes.
Q That avoided cost rate is not what Idaho
Power Company's rates will be set upon; correct?
A Onl y to the extent that resources procured
under those rates or under that methodology will affect
the retail rates of the Company.
Q But as you and I have just discussed, the
cost to the ratepayer of a generating facility owned by
the utility is not set on an avoided cost rate
methodology .
A That's correct. The avoided cost rate
methodology is the methodology that's been developed for
estimating the next cost or the cost of the next most
probable, most ef f ic ient resource that the Company would
purchase if it did not have to purchase QF resources under
PURPA.
Q But in point of fact, what the Commission
uses is a surrogate avoided cost unit, isn't that true,
the SAR as I understand the current vernacular?
A Yes.
Q What is an SAR?
A Surrogate avoidable resource. It's our
best, it i s the Commission's best, estimate of the cost of
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future base load plant, of the most eff icient future base
load plant, based on the testimony provided by the
utility.
Q But isn't that the next deferrable unit that
the Company will construct, isn't that the hypothesis?
A Yes, it is.
Q So what is the relevance of applying a test
for the next deferrable uni t to a uni t which is
non-deferrable?
A The rationale is that if the cost of the
non-deferrable uni t exceeds the cost of the deferrable
uni t, a rational man would simply walk away from the
non-deferrable uni t .
Q Again, it gets back to the issue that this
Commission is presented with in Swan Falls and Milner, and
that is recognizing that the units are non-deferrable,
what should the Commission's action be?
A Are you asking me?
Q Yes, isn't that the issue that we keep
coming back to?
A I believe that is the base issue, yes.
Q Now, if a utility's facility becomes
operable, such as Milner, and the utility's rates do not
change, what is the cost to the ratepayer of that unit?
A I don't understand the question.
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Q Let's assume that Milner becomes operable on
January 1, 1992, and the Company's rates on January 1,
1992, do not change. You now have an additional unit that
is producing power r but the rates to the ratepayer have
not changed; do you understand my hypothesis?
A Uh-huh.
Q All right, what's the cost to the ratepayer
of the addition of that unit?
A That depends on why the rates didn't
change. If the rates didn't change because no costs
incurred by the Company are included in the rates, then
there's no cost to the ratepayer. If the reason the rates
didn't change is because other costs went down and new
costs were added r then the cost to the ratepayer is
whatever was included in the new rates for that facility.
Q So are you urging that if you are going to
reasonably balance a utility-owned facility against
cogeneration and small power production that the
Commission should authorize some type of interim rates on
the date that the unit becomes operable if as a result of
a full blown proceeding the utility can show on that date
it should have had an increase in its rates?
A I wouldn't go so far as to say that I'm
recommending that, but it's something I would consider. I
haven't thought about it; so I'm really not prepared to
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1 answer the question.
2 Q But if we are going to compare the two on
3 totally even grounds, isn't that a necessary result of the
4 assumptions that you and I have discussed?
5 A No, it's not a necessary resul t . There are
6 other means that utili ties use to recover the costs
7 incurred during construction.
8 I'm talking now the uni t is now operable,Q
9 not under construction.
A I'm not familiar with whether the Company
has the opportunity to pick up the difference in
12 regulatory lag between on-line date and rate
determinat ion.
Q And I'm not discussing with you, Mr. Faull,
15 as to whether the utility has that opportunity or not.
What I'm asking you is if you i re going to compare the two
11 units, isn't it essential if you're going to play on a
18 level field that the utility be given the opportunity to
19 commence recovery of its costs on the date that the unit
20 becomes operable?
21 A On its face that seems reasonable.
22 Q Now, in response to a question from
23 Mr. Miles, you stated that there was no preference on
24 relicensing and again, if you don't know, Mr. Faull, we
25 don't need to dwell on this, but assuming that the
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existing holder of the license has filed an application
and a competitor has filed a similar application in the
sense that both are ident ical . Does the exist ing licensee
have any favored position or do you know?
A I don't know.
Q All right, and while we're on this, it is
the Federal Energy Regulatory Commission that issues the
license as to how the facility is to be constructed; isn't
that true?
A Yes, that is true.
Q And Idaho Power Company cannot change the
condi tions of the license without reapplying to the
Federal Energy Regulatory Commission for approval to
change those conditions?
A Once the Company receives the license it has
appl ied for and requested from the FERC, it must request
amendments in order to build something different,
substantially different.
Q But, Mr. Faull, in submitting its license
application, is it not subject to the scrutiny of the FERC
staff and suggestions as to changes in capacity before the
license will be issued?
A Yes, it is.
Q And in fact, that's what occurred in
Milner.
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A It's my understanding that what occurred in
Milner is that the FERC recommended that the Company look
at adding a 200 cfs unit at the dam site and that was done
and it was found to be cost-effective and that was
issued. It's not my understanding that the additional
1,000 cfs was recommended by FERC and even if it had been,
I would question that FERC required that as opposed to
recommended it.
Q But FERC is the entity that issues the
license and sets out the conditions of how the facility is
to be constructed.
A And Idaho Power Company is the entity that
negotiates with FERC to determine whether or not it can
get a license that it finds to be cost-effective.
Q Who has the final say, FERC or Idaho Power?
A Idaho Power Company.
Q Idaho Power has the final say on a license
to FERC?
A It has the final say on whether or not it
will accept the terms and conditions that FERC requires.
Q Yes, but FERC, obviously, is the entity that
imposes the final condi t ions which then Idaho Power
Company must either accept or reject?
A Yes.
Q And in the instance when we say Idaho Power,
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we're also referring here to the fact that originally the
license was issued to the canal companies.
A Or in any other case any other licensee, be
it a utility or QF.
Q And if the utility or the licensee rejects
the conditions of FERC, it loses the project?
A Correct. The point I wanted to make was
that the Power Company has the final say on whether or not
it is committed to make the expenditures required to build
the project as FERC licenses it.
Q Because it has under your understanding the
right to walk away and say I refuse to accept that
license?
A Yes.
Q Now, the avoided cost that you're talking
about to determine if these projects are cost-effective or
not, is that the avoided cost that has been calculated by
the Commission in a companion proceeding setting the
avoided cost rates for the purchase of cogeneration/small
power production?
A The avoided cost that I used for comparison
is a number computed using the assumptions included in
that companion case, but it's not an avoided cost that was
actually published as a result of that case.
Q All right, and that, those assumptions were
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that Idaho Power Company could defer the construction of a
coal-f ired plant.
A Correct.
Q Now, at the bottom of Page 23 -- excuse me,
Page 10, Line 23, you state what the Company should be
limi ted to and that is, you say, "Under those
circumstances, I believe Idaho Power Company should be
limi ted in its recovery to an accurate Commission
determined comparable avoided cost rate"; do you see that?
A Yes.
Q How would you compute that comparable
avoided cost rate for a hydro facility that Idaho Power.
Company has a license from FERC for an extended per iod
period of time?
A As I have computed it in my direct
testimony, using the assumptions of the avoided cost case
provided, using the life cycle, the reasonable life cycle,
under the license of the hydroelectric project and making
final determinations as to the questionable areas that I
pointed out in my testimony as to first deficit year,
potential for conservation to defer the project and other
items that mayor may not have been mentioned in the
direct testimony.
Q What I'm more interested in, Mr. Faul l, is
how you would calculate it from the standpoint of let's
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assume that under your scenario the utility receives a
certificate and the project comes in at above the
utili ty' s avoided cost; all right? What would the utility
rate base or would you rate base anything? Would you have
a purchased power clause or how would you handle the
revenue requirement issues?
A I would reduce the capital costs of the
project to the point that the levelized long-term costs of
the hydroelectric project equaled the comparable avoided
cost rate.
Q So you would simply, for purposes of
illustration, assume the utility had $100 invested in the
plant and based upon your formula, you would derive an
avoided cost of X, apply it to the $100 and 80 would fall
out, you'd rate base the 80?
A Correct.
Q Now, when it came time for the utility to
apply for a rate increase, you'd still use a different
method perhaps of computing the number of water years for
that project, as I understand it, for ratemaking purposes?
A That's a possibility.
Q What would your recommendation be as far as
we're trying to follow through how this is going to work?
A Assuming that no evidence was to come to
light that would lead us to find that our prior position
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1 that 20 years is the right number of water years for
2 estimating short-term rates, then my recommendation would
3 be to continue to use 20 years of water for retail
4 ratemaking.
5 Q Okay. Now, I also assume that dur ing this
6 period of time that the utility's asset is going to be on
7 the books the rate of return of the utility will also
8 fluctuate.
9 A That's a reasonable assumption.
10 Q Would you go back and readjust the $80.00 as
the utility's rate of return changed?
12 A No, as volumes of testimony in the avoided
13 cost case amply demonstrated, the reasonable rate of
14 return to apply to a long-term cost est imate is for --
15 well, I'm not qualified and I'm not ready to point out
16 what it is, but it is what we determined in the avoided
17 cost rate at this time.
18 Q But that's for the purposes of computing an
19 avoided cost rate for the purchase of cogeneration and
20 small power production.
21 A That's for the purpose of evaluating the
22 cost to the utility of acquiring a capital asset.
Q You do not believe that what the Commission23
24 is setting is the avoided cost rate to be used for the
25 purchase of cogeneration/small power production, but
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rather is determining what the costs to the utility are of
its next unit?
A Both, the two are the same thing.
Q The two are comparable in your mind?
A I would even go so far as to say that
theoretically they're identical.
Q Now, if I understand, on Page 11 and 12 in
response to quest ions from Mr. Mi les, you would impose a
penal ty upon the Company for its lack of conservat ion
efforts in the past at the time it applies for the rate
basing of its next resource unit to the extent that the
Company has not performed as it should in the conservation
area.
A More specifically what I've said is that I
would impute some level of reasonable conservation
development when I determined the first deficit year that
is used in computing the value of, the long-term levelized
value of, utility-acquired generating assets.
Q So again, what you would have is under our
assumptions, we've got a plant that the utility has $100
worth of costs invested in it, and assume for me, if you
will, that those construction costs are reasonable and
prudent and they have been audited and everybody is in
agreement that the best possible construction practices
have occurred and the utility has $100 in that plant. You
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would then go through your computation and say,
unfortunately, you've not done a good enough job in
conservation, therefore, you're going to rate base
$90.00.
A No, that's not exactly what I would say.
What I am saying is that at the time the utility applies
for a Certificate of Public Convenience and Necessity,
they should be advised that their target, their maximum
recoverable amount is the avoided cost rate and they
should know that up front before they start construction
and they should be held to that standard of performance
throughout the performance of the contract and it should
be imputed or it should be understood that any investment
made in excess of that is by def ini t ion imprudent
investment.
Q But you would do that at the time of the
issuance of the certificate?
A Yes, before construction started.
Q Now, when is the Milner project projected to
be completed?
A My understanding is 1992.
Q Now, on Page 22 you talk about, at the top
of Page 22, Lines 1 through 5, "It seems to me to be more
appropr iate in most circumstances to require Idaho Power
Company to commit only to acquire resources that are
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cost-effective relative to avoided costs, considering all
non-quantifiable relative risks," and then you're asked
about the kinds of non-quantifiable relative risks and you
talk about the discussion that there is a risk that the
f lows at the sites might be less. Am I paraphrasing your
test imony correct 1 y?
A Yes.
Q Now, in those non-quantifiable risks, would
you also include the effect that the Swan Falls project
has on the Company's other hydro fac i lit ies, such as the
Hell's Canyon Dam complex?
A Yes, I would.
Q There is a benef it, is there not, to the
reconstruction of Swan Falls to the Brownlee and the
Hell's Canyon Dam complex?
A You caught me off guard. I thought we were
talking about Milner here, but, yes, there is.
Q And for that matter, there may be a benef it
to Milner?
A Yes, there may be. In fact, in my testimony
I identified a potential benefit involved with the
incentive royalty.
Q You haven't attempted to quantify that as I
understand from your test imony .
A Not at this time, no.
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Q When would you quantify those things, at the
time the Company asked for its revenue requirement?
A Yes.
Q Now, assume for me that the utility
constructs a project and it comes in underneath your
avoided cost lid, can you make that assumption with me?
A Uh-huh.
Q What would you rate base in that scenario?
A All reasonably and prudently incurred
expensès.
Q If the comparable avoided cost rate would
generate my $100 and the utility had invested only 80, why
wouldn't you give the utility the 100 in that scenario?
A Because the utility is presumed to use
prudent and reasonable management techniques ~d the
reward for that is presumed to be in the return on
equity. If the utility wants to enter into the
compet it i ve independent power produc ing fie ld, there are
means for it to do that, but for regulated power plants, I
don't think that, I don't know, but I don't think the
Commission has the authority to grant more than prudently
incurred expenses even if they chose to, but at any rate,
I wouldn't recommend that. I would recommend that the
prudently incurred costs be recovered along with a
reasonable return on investment.
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Q And in that instance it would be a cap and
not a floor?
A Correct.
Q Now, the Company has also asked in this
proceeding that its contractual arrangement with the canal
companies be approved at this time, I assume you're aware
of that?
A Uh-huh.
Q Would you approve that at this time as part
of your recommendation?
A I think inherent in my recommendation that a
certif icate be granted, with a number of caveats attached
to that recommendat ion, that inherent in that
recommendation is a recommendation that the contract with
the canal companies be approved.
Q Now, you were asked by counsel for the
Industrial Customers questions relative to the
presentations that you sat in on that Idaho Power Company
has made that it believes that there are cost-effective
conservation programs which it desires or will be
implementing. Am I paraphrasing your testimony correctly?
A Reasonably.
Q Okay. My quest ion to you is this: I f your
suggestion is accepted, what is the incentive to the
utility to perform the conservation programs that it's
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coming up with?
A Which recommendation?
Q Well, as I understand it, you say, Idaho
Power Company, if you have come up with a project where
you can save so much energy at two cents a kilowatt hour,
however we determine the two cents, then, Idaho Power
Company, you better do the two cents and we're going to
deny your applications for the Swan Falls and Milner
applications. Am I paraphrasing again your testimony
correctly?
A Okay, that's reasonable.
Q What's the inducement for the utility to do
the conservation programs under that scenario?
A The major inducement for the utility to
acquire cost-effective conservation is the fact that at
this time, as I pointed out in my direct testimony, at
this time estimates of cost-effective conservation are not
included in the load/resource plan of the Company for
purposes of determining avoided cost rate. If the Company
were to demonstrate by acquiring a good deal of
cost-effective conservation and developing and
demonstrating that there is a substantial amount of that
out there, then that cost-effective conservation would be
included in the load/resource balance for avoided cost for
ratemaking and the avoided cost rates would be reduced
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accordingly and the Company could acquire QF power at a
lower rate.
Q But is your testimony only relative or only
relevant to the avoided cost determination proceeding
that's going on or have I become confused that I thought
your recommendations were that Idaho Power Company's
failure in your opinion to conduct an aggressive enough
conservation program should be used as a penalty in the
Milner/Swan Falls applications?
A I wouldn't call it a penalty, but what I've
asked the Commission to consider is presuming for
ratemaking purposes that the Company had done what I
believe it should have done and that will reduce the cost
to ratepayers or potentially would reduce the cost. It
would reduce the cost cap to ratepayers on Milner and
Swan Falls.
Your question to me is what is the incentive
for the Company to acquire cost-effective conservation
ongoing and I gave you one reason. Another reason would
be that if the Commission accepts my recommendation in
this case, the Company, I would think, would reasonably
assume that the same recommendation would be made in
future cases and consequently, if theyl re going to be
treated as though they own cost-effective conservation and
since the Commission has said that they will give the
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Company a return on all cost-effective conservation that
they acquire, it would be reasonable to assume that the
Company ought to go out and acquire that conservation and
earn a return on that.
Q I can understand your theory if we are
talking about a deferrable unit, but I'm having ditficulty
in my mind coming to grips with your recommendation in
Milner and Swan Falls if it is a given that those
facili ties are non-deferrable. Evidently you make no
distinction between the two scenarios.
A That i s correct.
Q Okay. One final area, Mr. Faull. Do I
understand that it is your recommendation that if all
things are equal, Idaho Power Company should meet its load
only by acquiring conservation and cogeneration resources?
A No, that's not my testimony at all. My
testimony is that Idaho Power Company should meet its
resources only by acquiring those resources that are
cost-effective.
Q If, Mr. Faull, under your scenario in your
short-term analysis for the next three or four years that
it is cost effective for the Company to only acquire
conservation and cogeneration resources, then that should
be the Company's resource acquisition plan?
A Could you restate that? i"' m sorry, I left
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1 for a minute.
2 Q Sure. If under your analysis that for the
3 next period of time, whatever period we desire to discuss,
4 it is cost-effective for the Company to acquire
5 cogenerat ion and conservat ion resources and not construct
6 any resources of its own, then that should be the
1 Company's resource plan?
8 A That's not exactly what I'm trying to say.
9 What I'm trying to say is that if those are cost-effective
resources and we have set a cap on what we're willing to
11 pay for those resources, the Company ought not to acquire
any other resources that are more expensive than that.
13 Q All right. Then in the long run, aren't you
acquiring all future resources at the margin?
15 A I've always had, in all my economics classes
16 I've always had a hard time defining the margin in the
17 long run and the short run; so I'd apprec iate a def ini tion
18 of what you mean by acquiring at the margin.
19 Q You can supply to me any def ini tion that you
20 feel comfortable with and then answer the question.
21 A If you're saying, if you define acquiring
22 resources at the margin as acquiring resources at the
23 cost -- I guess if you're saying at the point where the
24 supply and demand curves cross, no, that's not what I'm
25 saying. I'm saying at or below the margin, presuming that
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the avoided cost rate represents the point at which supply
and demand curves cross.
COMMISSIONER MILLER: Is this your last
question?
MR. RIPLEY: Yes, it is.
COMMISSIONER MILLER: Why don't we take a
recess right now and let Dr., Mr. Faull ref lect on the
answer for a few moments. We've been working our court
reporter for a while and we'll take a ten-minute recess
and come back and take Mr. Faull's answer to that quest ion
and then have Commissioner questions.
(Recess. )
COMMISSIONER MILLER: All right, let's go
back on the record in Case IPC-E-90-8 and find out if
Mr. Faull has had any success with his margin concept.
THE WITNESS: Well, somewhat. I'm still a
li ttle confused of how to apply it here, but essentially
as purchases, at least in the competitive market, are
always on the margin, so from that viewpoint, the
recommendation is that the rates be set based on or the
rates for a, the rate effect of a given, of all new
resources should be based on the margin.
Q BY MR. RIPLEY: And we have this conflict,
do we not, between the fact that we are discussing in one
sense of the word a free marketplace economic theory and
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in the other sense of the word we are talking about the
regulatory environment that a utility operates in as far
as the rates it can charge, the fact that its rate base is
determined by a regulatory agency, its revenue requirement
is determined by a regulatory agency?
A Right, but the conflict that arises when you
try to regulate a monopoly.
Q One final, and I promise, question or
series, depending on your answer, that's a threat, Tom.
Seriously, if we accept your premise that what the utility
should acquire are those resources that are most
cost-effect ive and it turns out that those resources are
conservation and cogeneration/small power production, then
each time that a hydro site comes up for licensing, under
your scenario, the utility would opt not to obtain a
license for that facility.
A No, I don't believe that's the case at all.
Q How could it and still recover its
investment?
A I think at least the Company has proclaimed
and I tend to agree that there are hydroelectric sites
available that can be developed for less than the avoided
cost.
Q i understand that. We're not
communicating. Assume for me that the specific hydro site
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that is under review by the utility is a site where the
cost of developing that site would result in a rate per
kilowatt hour which is more than the same comparable rate
for cogeneration or conservation, assume that scenario for
me.
A Okay.
Q If I understand correctly, your opinion is
the utility should not develop that site.
A That is correct.
Q And in which event every time that a hydro
si te came up for licensing, under that scenario, assuming
it's more than the cost-effective rates of Idaho Power
Company, Idaho Power would give up that site to other
deve lopers .
A Or to no developers, and I guess I would
modify your statement by saying that there is no way of
developing that site at less than the avoided cost rate.
Q As far as Idaho Power is concerned?
A For Idaho Power Company, that is correct.
Q So another entity would acquire that site?
A Might acquire that site.
Q In time what would occur under your scenario
is that the utility would be relying totally as far as new
resources is concerned on cogeneration/small power
production contracts which are purchased power contracts
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and conservat ion.
A No.
Q If it is cost-effective.
A If every hydro site and every thermal site
that is potentially available to the Idaho Power Company
is more expensive than those other resources, that would
be the case, but that's a big if.
Q But what I'm talking about, Mr. Faull, is
hydro only under your scenario, and the dilemma that I
believe you and I have beaten to death, is that if there
is a site which comes up for development, Idaho Power
Company has a chose, it either develops that site or
relinquishes that site to someone else who will develop
it; correct?
A No. It relinquishes that site and someone
else might develop it.
Q All right.
A That's a big difference. If it's not
cost-effective to Idaho Power Company, it may very well
not be cost-effective to any other utility.
Q But it very well might be cost-effective.
A Yes, it might.
Q And we're seeing, are we not, in point of
fact interest by other developers of energy, i. e. ,
utili ties from Seattle, et cetera, that are interested in
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1 hydro sites in the State of Idaho?
2 A Yes, we have seen that and there is still
3 some of that going on.
4 Q And under your scenar io , if the
5 cost-effective rate for Idaho Power Company for
6 conservation or cogeneration/small power production is
7 less than the cost to Idaho Power Company of developing
8 that site, Idaho Power should release that site to
9 out-of-state developers?
10 A Should make that site available, yes, that's
true.
Q And if they can develop it, it's developed
13 and that energy is lost to Idaho Power Company's customers
for at least the duration of the first license issued to
15 that developer.
16 A Correct.
17 MR. RIPLEY: That's all the questions I
18 have.
19 COMMISSIONER MILLER: Thank you,
20 Mr. Ripley.
21 Commissioner Swisher.
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EXAMINATION
BY COMMISSIONER SWISHER:
Q On your problem with the question of margin,
Mr. Faull, the relationship between a utility and the
source of conservation is a monopsony, is it not, the
utili ty is the sole buyer of that resource?
A That is correct.
Q So in current conditions in this region
where you have the historic presence of a great number of
uses of electricity that were embedded in the era of penny
power, we have to assume that most conservation
acquisi tions until you reach some unknown point in the
future would be below the margin, almost consistently
below the margin, unless we're talking about a new
construction situation sort of thing.
A If you define the margin as supply side
resources, then that's correct.
Q Yes, and isn't that one way to help to get
the garbage of the '80s out of our Hearing Room when we're
discussing those questions? I mean, we don't always have
to -- what was that organization, NERA, you know, that
group of religious economists, fundamentalists, who so
polluted our process. When we're talking about what
actually happens under regulation, it is the utility that
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1 acquires the conservation resource and all the babble of
2 Chicago school economists and the Fred Kahns and all that,
3 you know, that's irrelevant, is it not? Can you think of
4 any situation in which Idaho Power in acquiring the
5 conservation resources it has acquired was competing with
6 somebody else?
7 A No.
8 Q All right. Yesterday when Mr. Keen was, not
9 Mr. Keen but Mr. Baggs was on the stand, I asked him
10 wouldn't it have been possible to have proposed to the
11 Commission some method of phasing in the electricity from
12 the Milner project that mirrored, as it were, the
13 long-term levelization used in setting cogeneration rates;
14 were you here?
15 A Yes.
16 Q What's your reaction to that?
17 A I think it's a good idea. It's an idea that
18 we as a team in Staff discussed and actually Ms. Miller
19 was planning, I believe, on presenting that as an option
20 but discovered some FASBE, and I can't tell you what that
21 acronym means, but some reason why that's not acceptable
22 to the account ing standards board.
23 Q And they have regulatory power over
24 accountants; right?
25 A As far as I know. That's, fortunately, not
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one of my fields of expertise.
Q But they certainly can intimidate them,
can't they?
A Yes, but you'd really have to ask that
question of Ms. Miller to get the right answer.
Q All right. But since you and Stephanie
Miller work in the same store, the question still applies
in a way. Part of the Company's application includes that
contract with the two canal companies. In your testimony,
you're somewhat critical of the contract. You told
Mr. Ripley on cross this morning, yes, that approval of
the contract is linked by your logic to certification, and
you were saying that, you know, I mean you had caveats,
bu t you were say ing yes, you would recommend the approval
of the contract even though in your direct testimony you
were critical of the contract in that the irrigators get
back most of their costs, the non-energy costs, of the
project out of their receipts from Idaho Power.
A Yes.
Q But can you conceive of any scenario under
which the irrigators would not have made that a
precondi tion? Let me put it another way. You were not on
the Staff at the Public Utilities Commission, but you were
in the area, you were a working engineer, at the time that
the five canal companies that comprise the Boise Board of
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Control reached their agreement on Lucky Peak Dam, one
under which Seattle City Lights is now getting that juice,
and basically were there not some costs that went even
beyond the project that went clear out on the maintenance
of the canal systems themselves that were extracted from
Seattle as a condition of using the Board of Control's
FERC license?
A There may well have been and that's a
function of the conditions at the time a negotiation would
take place and the time the contract would be signed. For
example, back when Idaho's avoided cost rates were 67
mills or above per kilowatt hour, I could conceive of, and
this was at the time Idaho Power was negotiating with the
canal company, it's conceivable that a developer could
have come in and tried to compete with Idaho Power Company
for that site and offered more than Idaho Power Company
has contracted for today, but I think what we ought to be
looking at as far as analyzing that contract is what were
the conditions at the time the contract was signed. At
the time the contract was signed, the irrigators were in
dire straits and the value of power was substantially
lower. It was at that time possibly on the order of
four-and-a-half cents a kilowatt hour.
Q About 45 mills.
A And so if the negotiator had a credible
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posi tion that he could not develop this site if he didn't
get a better deal on that dam development and he was
willing to walk away from the site if he didn't get that
better deal, then I believe he could have negotiated a
better deal, but I don't believe that either Idaho Power
Company or the irrigators thought that Idaho Power Company
was willing to walk away from that site under any
condi tion, the reason being they would expect to come in
and recover whatever costs they negotiated for on the
grounds that it's my burden to prove that they didn't do
an adequate job of negotiating, and you can't prove that
unless you have videotapes of the negotiation or you have
a comparable negotiation made at the same time on an
identical site by another entity.
Q Don't I find that undercurrent in your
direct te~timony? Aren't you faulting the utility for the
costs that are brought to us now, costs which prior review
rather than reactive review could have changed, but
keeping in mind the Commission can never be at that
negotiating table, but aren't you saying we've been
brough t a fai t accompl i by the Power Company, we're
supposed to sign off on it and I'm saying the costs are
higher than they should have been, I, Tom Faull?
A Yes, that's exactly what I'm saying. I'm
saying I might not be able to prove that, but I believe
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they're higher. I might even with more effort be able to
prove that some of those costs are higher; so my final
posi tion is if the Company is asking permission or
assurance that the Commission will not find this action
completely outrageous, if it's continued from this point
forward, I'm saying that authority is probably reasonable,
but it's not reasonable at this time to tie to that an
assumption that the utility's management to date has been
prudent and that as a Staff member, I would like the
opportuni ty to review that in more depth.
Q As a Staff member. As an Idaho resident,
surely you know that when you follow that particular kind
of negotiation out, it's an endless skein. These
negotiations occurred in the wake of the resolution, for
instance, of the Swan Falls dispute, not the dam dispute,
but the cfs at Swan Falls and the whole big hairy matter
of that war, as close as we've had to a civil war in Idaho
in modern times between irrigation development and power
interests, and that was an extraordinary time in which,
for which -- well, forget the syntax, just say it was an
extraordinary time, and that going forward in dealing with
the relations among the utility, the irrigators, the PUC
as a regulatory entity, the legislature as the empowering
enti ty, there will be some additional changes, will there
not?
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Do you think, for instance, that once the
work of the salmon summit comes to some resolution or
whatever follows on the salmon summit, do you think, for
instance, as an engineer and as one who crunches these
costs that there is an indef ini te aff irmative future for
all existing high lift pump irrigation in the Idaho Power
service territory?
If we take those projects on which the lift
varies from 500 feet to 750, almost 800, feet when it's
relifted, given the power costs we already see, given the
decisions that have to be made on new costs for this
Company, whether they be in conservation, cogeneration or
new base load plant, isn't that going to be a new
dimension in the costs of this Company and in the economic
consequences of our decisions?
Is the future of the decisions not just that
we make but that others make such that we can expect the
present relationship between the load of Idaho Power
Company and the agr icul tural economy to stay as it is?
It's not going to stay as it is.
A No. In fact, there are a range of dynamics
that are pretty unpredictable. One is the high lift
pumping, maybe uneconomic today and almost certainly will
become uneconomic in the future without some sort of
subsidization, additional subsidization. Another is the
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fishery, the salmon issue. That's almost certainly going
to affect, negatively affect, levels of generation in the
future on the Snake River and Columbia River dams.
Whether it would affect as far upstream as Milner is hard
to say and how extensive that effect will be impossible to
say, but there will be that effect.
The other side of the coin is that
irrigators are continually becoming more efficient and
there may be more water available, and then another side
of that coin is there are also lands projected to be
developed in the future using additional water; so which
way the f lows are going to go is anybody' s guess in my
mind, but, yeah, there are tremendous dynamics happening
on the river.
Q Do you really think there's going to be
significant additional new land broken up under these fish
scenarios?
A Not in the near term.
Q Okay. None of the attorneys walked you
through your analysis of Mr. Keen's outlay of the costs of
the Company except that one, you had the one discussion
that was highly categorical over cost of capital. What am
I to make of that? Why weren't you crossed on that in
your judgment?
A You mean my analysis of the avoided cost
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1 rate and the est imate of --
2 Q Everything, on megawatts per year, the cost
3 of capital, your walk-through that's basically in the
4 middle pages of your test imony .
5 A Probably because the Company rebutted or, at
6 least i I wouldn't say they successfully rebutted my
7 posi tions on many of the issues that raised the cost of
8 the i the unit cost of i the power from the site, but they
9 raised enough of an issue on each of those to say that
there is more than one point of view on what those costs
might be i which is exactly the point I was trying to
make.
I don't profess to say that the numbers I
14 gave you are exactly the right numbers, but I say that the
numbers the Company gave you are in my opinion not the
16 right numbers and that in each case they're lower than I
17 believe they actually ought to be and I believe that my
18 numbers are closer than their numbers.
19 Q And to oversimplify and to malign the
Company a little bit in the way the question is asked, and20
21 I don't mean to do that, but I don't see any other way to
22 ask it and I think it's an important question, are you
23 saying what the Staff often implies; that is, that the
24 Company uses one set of numbers when we're holding
25 hear ings on PURPA rates and quite another when we're
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dealing with new rate base Company generation?
A I'm saying that it appears that that could
have happened. Certainly the number that the Company
included in its application to FERC as the value of power
is not the number that they presented to the Idaho Public
Utilities Commission as the costs that could be avoided in
the future or the value of power purchased from QF
entities; so to that extent, it appears that they have
more than one set of books, if you will.
COMMISSIONER SWISHER: Thank you. That's
all ~ had, Mr. Chairman.
COMMISSIONER MILLER: Thank you,
Commissioner Swisher.
Commissioner Nelson.
COMMISSIONER NELSON: Thank you,
Mr. Chairman.
EXAMINATION
BY COMMISSIONER NELSON:
Q Mr. Faull, I got out of your conversation
wi th Mr. Ripley that you felt there were hydro sites on
the river that should not be developed, they just weren't
worthwhile, too expensive.
A That's a true statement.
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Q Do you think that Mi Iner is one of those?
A No. No, I think Milner is a hydroelectric
site that will make any hydro developer salivate. You've
got an existing dam in place. You've got well-known,
fairly well-known, water conditions, as well known as you
can have. You've got water rights through the irrigation
company to a great deal of those rights. You've got a
partially developed canal system. It certainly has more
potential to be an economic site than most that you'll
find.
Q Don't you think that Lucky Peak was one of
those?
A Again, it certainly had the potential to
be. The way it was developed, I'm not sure. It's my
understanding that its generation has been less than
predicted and that its costs have been much higher than
predicted. I would say that Lucky Peak was developed
perfectly for Idaho. We got all of the benefits and none
of the costs. The operators live and pay taxes in Idaho,
the site pays taxes in Idaho. The construction money was
spent in Idaho, but the high-cost power is being paid for
by the people of Seattle.
Q Do you think in hindsight maybe that's a
si te that Idaho Power should have developed, albeit
differently?
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A Perhaps. It's my understanding, and I'm
talking hearsay now, that they made a pretty substantial
effort to get the site and they were simply beaten out by
another customer, and in that case, the Company may well
have been using good judgment; so I guess the answer is
no, under the circumstances, I think Idaho Power did the
right thing in that case.
COMMISSIONER SWISHER: You're going contrary
to the mythology all ready in place, you understand that.
THE WITNESS: Yes.
Q BY COMMISSIONER NELSON: In discussing the
capac i ty of the site and how big a generator should be put
in there, isn't that capac i ty constrained more by the
seasonality of the project than by the flows? I don't
know as much as I' d 1 ike to about this, but when the water
is running, isn't that a small enough generator in there,
whatever size it is?
A Yes, it appears that the size that the
Company has selected costs too much for the amount of
energy you can get out of it and it's al 1 interconnected.
Seasonality is important, but total flow is important and
my estimate or my opinion that it's oversized is based on
a look at average flows, and to be absolutely certain that
it's oversized, I i d have to do a much more detailed
analysis of all the flow data that I could get my hands on
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and even then it's an estimate, but the bottom line is it
appears that it's going to cost more for this power than
it would cost for the other resources and it appears that
the site could have been developed so that it cost less
per unit and you'd still have the opportunity to upgrade
the site either by an amendment to the existing license in
the future when additional energy would be more valuable
or to a new license at relicensing.
Q Isn't there some economy of scale there? I
mean, a 50 megawatt generator is going to cost less per
megawatt than a 40 megawatt generator.
A That i s the balance. You i ve already got your
construction crews on site, you're already excavating the
canal, you're already upgrading the dam, so that's
essentially free for the additional unit; so there are
those economies of scale, but each step you go up in the
capaci ty of the plant is almost an exponential reduction
in the amount of generation or amount of kept capacity
factor that that increment can obtain; so there's some
point where the two curves would cross and it just appears
to me that that point is below 58 megawatts.
Q So are you saying your judgment there is
based more on back-of-the-envelope stuff than detailed
analysis?
A Yes.
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Q Mr. Richardson asked you about where Milner
fit into the resource stack in Idaho and you mentioned
something about the Oregon least cost plan, but he didn't
follow up with that. Do you know where Milner fits in to
Idaho Power's least cost plan filed with Oregon?
A As far as I know, and I'm almost certain of
this~ it's in the same position that it is in Idaho, that
it's considered a non-deferrable/non-avoidable resource
that will be developed and included as a resource on Idaho
Power's system.
Q So that it's not specifically listed there
as we've got so much conservation at 40 mills and
something else at 50 mills and Milner at 60 mills?
A No, it's set up more Idaho Power owns
Brownlee, Swan Falls, Twin Falls, Milner, et cetera, but
Milner is going to come on line in 1992 and Swan Falls is
going to be upgraded in 1993 and in addition to that,
we're going to need certain resources and they're going to
come from this resource stack.
Q We ll, if these numbers were in here, I
didn't see them. In your analysis, how far off is the
Company's proposal from avoided cost if you took that
avoided cost and ran it out to the 46 years or whatever it
was?
A In the analysis I did, they were wi thin two
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percent and I pointed out that there are reasons why the
avoided cost that I used might be higher than it should
have been and there are also potentially some reasons why
my analysis of the cost of the plant may be higher, but
looking at just the avoided cost, the variables included
or decided on in the avoided cost case and my best
estimate of the cost of the Milner project, they're wi thin
two percent, which for purposes here, they're identical.
Q Do you think an independent producer making
the same analysis and coming wi thin two percent might go
ahead with that and say I'LL take less return on my
investment in order to get the project done for the
20-year contract?
A Depending on what sort of return on
investment he assumed when he did his analysis, he might
we 1 1 take that risk. For example, I used the cap as the
cost of the project. If the developer believes that he
can actually come in at less than that cap and the cap is
in fact his absolute maximum, then he would probably go
ahead with that.
Q And finally, correct this statement, I
gleaned that it was your position that this facility was
not needed because the Company should have become more
aggressive on conservation in the past.
A That's not my position. My position is that
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in determining the prudence of selecting the size,
determining, first of all, to go ahead with the project,
determining the size, determining what construction costs
are reasonable, the overall analysis of prudency, I'm
saying there should be a cap that is the avoided cost rate
and that cap should include the assumption that the
Company had been and would continue to bring on line
cost-effective conservation.
That assumption would drive the, that's one
of the things I said would lower the avoided cost rate
that I used for comparison and would make this project
look uneconomic, and I'm saying, what I'm saying is that
since the utility has no direct competition that would
force it to be as cost-effective as it possibly could,
this would be a reasonable surrogate, the avoided cost
rate would be a reasonable surrogate, to at least keep
them competitive with QF projects, but in determining
that, we ought to assume that they had already brought on
line and would continue to bring on line less expensive
conservation.
Q I guess I'm a little concerned about what
the record is showing about your thoughts on the
conservation program, and I don't know whether you should
be speaking for the Staff or for yourself, but are you
unhappy with the programs, conservation programs, that the
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Company has been bringing in in the last 18 months? You
mentioned 18 months somewhere in your testimony.
A Yeah, a year to 18 months. I think the
Company is beginning to do what it probably should have
done two or three years ago and what the Commission
actually told it to do, which is to determine what the
market for conservation is and to begin acquiring
cost-effective conservation. I think the Company is being
less aggressive than it ought to be based on the results
that -- no, let me restate that. I think the Company has,
based on the results it has gotten to date, the Company
has an opportunity to greatly increase its aggressiveness
in pursuing those resources, but to date, from the time
they actually started, say, 18 months ago, to date I think
that they've been reasonably aggressive in that program.
My complaint is that they started too late and they may be
doing too little.
Q And that wasn't my final quest ion. You talk
in your testimony, you gave a figure first-year cost of
this project of about 74 mills, I think. How does that
compare to current costs on Valmy, either 1 or 2 or
whatever you approximately think our current costs are
running?
A Actually, I didn't look at first-year
costs. Stephanie Miller looked at first-year costs. I
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listed levelized unit cost.
Q It was in her testimony that I saw it.
A Right.
Q Since I've asked the question, do you know
what
A Her first-year Valmy cost is, no, I didn't
look at that. I did look at long-term, made an estimate
of long-term, level costs for a number of coal-fired
plants, but not Valmy.
COMMISSIONER NELSON: Okay, thank you.
That's all I have, Mr. Chairman.
COMMISSIONER MILLER: Thank you.
EXAMINATION
BY COMMISSIONER MILLER:
Q I thought your discussion with Mr. Ripley
was very enlightening, and as a result of it, it seems to
me that the Commission is with your testimony faced with
something of a dilemma and let me tell you what I think
the di lemma is and you see if you think it's a true
di lemma or not.
MR. MILES: Mr. Commissioner, would you pull
your microphone closer?
COMMISSIONER MILLER: Sure, Harold.
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Q BY COMMISSIONER MILLER: On the one hand,
least cost planning and the Commission's commitment to
least cost planning doesn't really mean very much if a
utili ty is permitted to construct supply side resources at
costs that are greater than cogeneration and conservation,
that's kind of your point, isn't it?
A Yes.
Q That if we don't have conservation or
cogeneration as some sort of a cap on price or cost, then
our commitment to least cost planning is probably in name
only and it's not rigorously enforced, that's kind of what
you're telling us, I think.
A Right.
Q And the Commission undoubtedly has a policy
commi tment to least cost planning. At the same time, it
seems to me that there is a, I don't know where you find
it, but there's a policy in the State of Idaho, I think,
that the development of hydro capacity of the Snake River
and preserving the ownership of that capacity in an entity
that is pervasively regulated by the State of Idaho is
part of the state policy; that is, we don't need Seattle
City Light with a facility in the middle of Idaho Power's
integrated system, and it seems to me that those policies
come into conflict here, because if we follow your
recommendation on being serious about least cost planning,
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we may not be able to achieve the other policy. Have I
stated this in a way that's accurate do you think?
A Yes.
Q And how do you suggest we resolve this
dilemma?
A I guess as I see it, the state policy to
develop Idaho resources for Idaho ratepayers must include
some cost-effectiveness criteria that's unspoken. If it
didn't, then it would be reasonable to assume that if you
could take a fan out of your kitchen and submerge it in
the Snake River where there's a two-mile an hour flow and
produce energy for $50.00 a kilowatt hour, then that's the
policy of the State of Idaho and I don't think that's the
intention of the policy, the energy policy; so the
question that arises is how much is having control over
that site by the Idaho Public Utili ties Commission worth
to the State of Idaho. Fortunately, I get to pose the
question and I don't have to answer it.
Q But isn't your recommendation -- well, if we
take the Snake River hydro projects, those in the
Company's language are non-deferrable.
A Yes.
Q Non-deferrability is a short way of
summarizing this policy that I have just tried to
articulate as one way of looking at it; correct?
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A Correct.
Q You, however, I think, are telling us that
we should use the same cost-effectiveness test for
non-deferrable projects for Snake River hydro projects as
we would use for a deferrable project, as we would use for
a gas peaker that you could build any time, any place.
A I'm at least saying that that ought to be
the starting point and if it's possible to develop the
si te at that rate, then that ought to be the standard that
has to be met. If it's not possible to develop the site
at that rate, then it becomes a judgment question of how
much of a premium should we pay for the site, but if it's
not necessary to pay a premium to have the site, I don't
believe that we should pay a premium.
Q Just so the record is clear, in the Milner
case, is it your opinion that the Milner site meets the
cost-effectiveness test for a deferrable resource or not?
A I guess I have to -- I can't answer that
question directly. If we were at the point of development
where the Company is in the process of applying for a
license and were at the point where there is substantial
flexibility on how the project would be developable, then
I'd say the Milner site is unquestionably a site that
should be developed and it's unquestionably possible to
develop it cost-effectively.
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If you're asking me do I think the Milner
si te still has the potential, as with all the constraints
that are on it has the potential, to be developed wi thin
that range, I'm saying, I would say yes, that potential
appears to me to still be there. It's going to be much
more diff icul t to get it at this point than it would have
been ear 1 ier .
If you're asking me by making that decision
do I think that all the Company's decisions to date have
been prudent and should be recoverable and all the
expenses that resulted from those decisions should be
recoverable, I'm not sure that I agree with that. I think
probably there have been some imprudent actions that have
increased the costs and might justify a reduction in the
amount that's rate based at the end of the project, which
is why I recommended that a certificate be granted, but
that it be made clear in that granting that this
certif icate is not a statement that this was an interim
prudent review and the Company has been prudent to date.
COMMISSIONER MILLER: Well, we've gone into
the noon hour; so I think we'll take our noon recess now.
I may want to follow this up a little bit further with you
when we come back from lunch, but let's not detain
everybody into the lunch hour to do that; so let's take
our noon recess and reconvene at 1: 30 .
(Noon recess.)
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