19901109Faull Direct.pdf

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BEFORE THE IDAHO PULIC UTS COMMSSION
IN TH MAITR OF THAPUCATION
OF IDAHO POWER COMPAN FOR Å CER-TICATE OF PULIC CONVCE ANNECEIT FOR TI MTEG OFTH Ml HYROELC lROiCTOR IN TI ALTEATI A DET-ATION OF EX S1i\TUSFOR THMI HYROELECTC PROJE.
) CASE NO. IP-E-90-
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DIRCT TESTIONY OF THOMA FAUL
IDAHO PUUC UT COMMSSION
NOVEER 97 199
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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 utilities Engineer.
Q.Have you included a statement of your
qualifications in this testimony?
A.Yes. Exhibit No. 101 is a statement of
my qualifications.
Q.What is the purpose of your testimony?
A.The purpose of my testimony is to discuss
the cost effectiveness of Idaho Power Company's (IPCo' s)
proposed proj ect, 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", the criteria for
determining the applicability of a Certificate to a
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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 uni t 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.
First, I did not consider the case of 20
water years. In Order No. 20924 (Case No. U-I006-265)
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the Commission ordered IPCo to use the most recent 20
years of water data for retai 1 ratemaking purposes,
rather than alI available water data. This methodology
resulted from statistical evidence supporting 20 years
of data being the best predictor of the f low 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.
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Compo n.Ra:t~Qß
10.30%
10.29%
13.17%
50%
10%
40%
DebtPreferred
Common'
Weighted Cost 11.447%
I used this capi tal structure in my
analysis, rather than the capital structure used by
Mr. Keen, which was:
Component Ratio~
DebtPreferred
Common
10.00%
9.50%
12.25%
50%
10%
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.
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Fourth, Mr. Keen used an annua 1 average
generation of 194,700 MWh in his analysis. However,
IPCo indicated in the FERC license application that
the actual expected generation would be 186,395 MWh
because of unit unavailability. Therefore, I used
186,395 MWh/yr in my 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 4.0% per year used by Mr. Keen, again
resul ting 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 1.0% as the property tax rate for the
Surrogate Avoidable Resource (SAR) of the avoided cost
determinat ion. 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 parties were of estimating the
property tax rate of a coa 1 fi red plant in Wyoming.
Q.Can you further explain the analysis you
did to estimate annual O&M costs?
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A.Yes. Using pp. 406-A through 407-B of
IPCo's FERC Form 1, I determined the rated capacity,
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
Consumer 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 capaci ty for each
year for each plant. After a subjective determination
that the variation from year to year of the costs per
kW of capaci ty was acceptable, I averaged the 5 yea rs
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
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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' s other plants, as compa red 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 coming 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 project 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
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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 (wi thout
"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 bui Ids a resource wi th a 46
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year life ratepayers can reasonably expect that they
wi 1 1 have access to the energy f rom 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 portion will escalate, and assuming an on-line
year of 1992 yields an avoided cost of $65. 28/MWh.
Taking into account the seasonality weighting of
avoided costs relative to the availability of the
Mi lner 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 Mi lner Plant, wi th an estimated
cost of $62. 73/MWh is cost effective wi thin reasonable
limi ts 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 peti tion that might affect the
avoided cost rate comparable to the Mi lner Plant?
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A.There is a potential that a mathematical
error made in Case No. WWP-E-89-6 will 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 Iner 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 peti tion for
reconsideration of Order No. 23357 will affect the
avoided cost rate that is comparable to the Mi lner
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.
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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 proj ected future purchases of QF power and demand
side resources (conservation) for estimating the first
year of power need for each uti li ty. Al though 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 uti Ii ties' proposed resources.
This is especially true in the case of
conservation resources. The Commission has been
encouraging Idaho utilities to acquire cost effective
conservation resources for years, but with Ii ttle
avail. Now, when it appears that new resources are
needed, the utilities have little conservation
"on-line", and are essentially unprepared to aggres-
sively bring such resources on line. Therefore, it
appears inéquitable to ascribe a benefit to IPCo in
evaluating its supply side resources by ignoring the
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utility's apparent negligence in acquiring demand side
resources. I believe the Commission should consider
imputing prior and future demand side resource
acquisi tion 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.No. IPCo made its decisions, commi t-
ments, and contracts relative to this Project without
a Certificate, even though one was clearly required
prior to beginning "construction". Furthermore, it
did so while fully aware of the interim avoided cost
rates, whi Ie 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
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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
Mi lner Proj ect costs are not less than avoided costs,
IPCo should be imputed to have known that the project
was not cost effective, at least to the extent that
Mi lner costs exceed avoided costs us ing the assumpt ions
included in IPCo l 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 proj ect. . ." . What did
you mean by that?
A.I meant that in addi tion 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 proposal being the most
cost effective development from the family of reason-
ably potential developments at the si te -- 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 easier to second-guess the quality of a project
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 will recover all of their 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. Al though the bidding method is immune to
administrative challenge because it appears to result
in supplier competi tion, my experience has been that
it actually stifles competition and results in higher
costs i 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-
ti ve combinations wi th 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
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
va lue of the water that wi II pass through the turbines
at Milner. All water above mean flow condi tions that
passes through the Mi lner turbines wi 1 1 probably a Iso
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 site 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 lner Proj ect (as proposed by IPCo) wi 1 1
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 wi 11 determine a t 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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equa 1 to avoided costs.
Q.If the estimated project costs are
determined to be greater than avoided costs wi i 1 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 Milner 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
si tuation where IPCo is forced to recover its costs by
marketing the output of Milner in the competitive
wholesale market,there will be extremely strong
incentives for IPCo to allocate O&M costs actually
incurred in support of Hi 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 deferral" proposal.
IPC-E-90-811/9/90 FAULL (Di)Staff 20
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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 electrici ty?
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 explici t
services could be monitored by staff, albei t wi th some
difficulty, but it would be impossible to ascertain or
estimate the level or value of implici t 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
proj ect, do you bel ieve there may be proj ects where it
would be more appropriate?
A.Again, maybe. But it is unlikely that
the proposal would be appropriate for any proj ect
without substantial modifications to IPCo' s proposal
(at least as extensive as suggested by Ms. Miller in
IPC-E-90-811/9/90 FAULL (Di)Staff 21
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her testimony). It seems to me to be more appropriate
in most circumstances to require IPCo to commit only
to acquire 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 flows at the site may
be more (less) than the historic flows and that the
envi ronmenta 1 impacts of the proj ect 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 proj ect 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
IPC-E-90-8
11/9/90 FAULL (Oi)Staff 22
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decide how to factor that risk into granting or
denying 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 Commi ss ion
should use avoided cost as the presum measure of
prudence. Thus, as part of its application for rate
making treatment of any project, a utility should be
IPC-E-90-811/9/90 FAULL (Di)Staff 23
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expected to justify projected generation costs that
exceed avoided cost. That justification would be in
addition to justification for other factors 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.
IPC-E-90-811/9/90 FAULL (Di)Staff 24
..
QUALIFICATIONS
OF
Thomas G. Faull, P.E.
of the
Idaho Public Utilities Commission
Mr. Faull received a Bachelor of Science
degree from the Uni versi ty of Idaho in 1970. His
major was Mechanical Engineering with emphasis on
Nuclear Engineering and Stress Analysis.His minor
was Business Administration with emphasis on Economics
and Management.
PROFESSIONAL REGISTRTIONS AND HONORS:
Mr. Faull is a member of Sigma Tau, the
collegiate engineering honorary society.He has
received registration to practice Professional
Engineering in the following states:
1974 :
1975 :
1977 :
1979 :
Idaho; Mechanical
Colorado; General
New Mexico; General
Oregon; Civil
He is also registered to practice before the U. S.
Office of Patents and Trademarks as a Patent Agent.
PROFESSIONAL EXPERIENCE:
A. From 1970 through 1978, Mr. Faull worked
for the U. S. Bureau of Reclamation in the capaci ties of
Mechanical Engineer,Contract Administrator,and
IDAHO POWER COMPANY
Case No. IPC-E-90-8
Exhibi t No. 101
T. Faull, Staff11/9/90 Page 1 of 4
..
Resident Engineer.As a Mechanical Engineer he
provided quality control for mechanical, electrical,
and civil works at major hydroelectric construction
projects. As a Contract Administrator he analyzed and
made recommendations pertaining to claims for addi-
tional compensation under contracts to build and supply
equipment for major hydroelectric and irrigation
projects, negotiated settlements thereto, and wrote
contract addenda to reflect negotiated settlements. As
a Resident Engineer he supervised up to 50 engineers,
surveyors, and technicians providing quality control of
electrica l, mechanical, and ci vi 1 works of a 100,000
acre irrigation project; including roads, highways,
canals, pumping plants, pipelines substations, and a
115kV transmission line.
From 1978 through 1986 Mr. Faull work.ed in
various capacities of consulting engineering. As such,
he did (or supervised) financial feasibility analyses,
design,construction management,cons t ruct ion,and
start-up of chemical, water, and energy proj ects,
including PURPA hydro, coal, and MSW projects. He also
did business development, billing, personnel manage-
ment, and hiring/firing.
I DAHO POWER COMPANY
Case No. IPC-E-90-8
Exhibit No. 101
T.Faull, Staff11/9/90 Page 2 of 4
..
From 1987 through the present Mr. Faull has
served as a Uti Ii ties Engineer at the Idaho Public
Utilities Commission. In that capacity he has analyzed
Cogeneration and Small Power Producers'(CSPPs' )
projects;developed computer models to represent
uti li ties' Avoided Costs, power supplies, cash flows,
and other features; testified in electric avoided cost
cases; authored Proposed Orders pertaining to avoided
costs,cSPPs ·security arrangements,utility sur-
charges, and uti Ii ties' conservation/least-costplanning
programs; and authored proposed Idaho comments to
Federal Notices of Proposed Rulemaking.He has also
attended several related training programs and con-
ferences, including the NARUC 1987 Western Utility Rate
Seminar,the NARUC 1987 19th Annual Williamsburg
Regulatory Conference, The 1988 First Annual Utility
Least-Cost-Planning Conference, the 6th NARUC Biennial
Regulatory Information Conference, aNARUC Conference
on Transmission Issues in Washington D.C., two pri-
vately sponsored conferences on CSPP regulation, and
one privately sponsored conference on bidding for CSPP
power.
IDAHO POWER COMPANY
Case No. IPC-E-90-8
Exhibit No. lOlT. F au ll, S t a f f11/9/90 Page 3 of 4
..
PUBLICATIONS:
Mr. Faull has authored and presented three
papers that were published in the "Proceedings of the
Sixth NARUC Biennial Information Conference". The
papers were entitled:
1."Irreconcilable ConflictsInherent in Vertically
Electric utilities",
of InterestIntegrated
2. "Solving the Overpayment Dilemma for
Levelized Rate PURPA Contracts", and
3. "Bid Price and Reserve Margin: Chicken
and Egg? An Approach to Pricing Power
in the Post-Spiral World".
__ = ____ _= _.. _e=__=. ....... __=_ ___._ __ ... __._..
IDAHO POWER COMPANY
Case No. IPC-E-90-8
Exhibi t No. 101
T.Faull, Staff11/9/90 Page 4 of 4
..
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IDAHO~POWER COMPANY
Case No. IPC-E-90-8
Exhibit No. 102
T. Faull, Staff11/9/90 Pagel of 2
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IDAHO POWER COMPANY
Case No. IPC-E-90-8
Exhlbi t No. 102
T. Faull, Stáff11/9/90 Page i of 2
..UNIT COST UNIT COST
HYDRO PLANT YEAR (1992 $/MWh)(1992 $/kW)------------------------------------
TWIN FALLS '89 1989 AVG.AVG.***************
TWIN FALLS '88 1988 AVG.AVG.
TWIN FALLS ' 87 1987 $3.34 $25,15 TWIN FALLS
TWIN FALLS '86 1986 AVG.AVG.8.4 MW
TWIN FALLS '85 1985 AVG.AVG.55.0 YEARS OLD
SWAN FALLS '89 1989 AVG.AVG.
SWAN FALLS '88 1988 AVG.AVG.
SWAN FALLS '87 1987 $8.05 $68.28 SWAN FALLS
SWAN FALLS '86 1986 AVG.AVG.10.3 MW
SWAN FALLS '85 1985 AVG.AVG.45.0 YEARS OLD
CASCADE '89 1989 AVG.AVG.
CASCADE '88 1988 AVG.AVG.
CASCADE '87 1987 $5.93 $16.42 CASCADE
CASCADE '86 1986 AVG.AVG.12.4 MW
CASCADE '85 1985 AVG.AVG.6.0 YEARS OLD
SHOSHONE FALLS '89 1989 AVG.AVG.
SHOSHONE FALLS '88 1988 AVG.AVG.
SHOSHONE FALLS '87 1987 $5.58 $25.14 SHOSHONE FALLS
SHOSHONE FALLS '86 1986 AVG.AVG.12.5 MW
SHOSHONE FALLS '85 1985 AVG.AVG.69.0 YEARS OLD
MALAD '89 1989 AVG.AVG.
MALAD '88 1988 AVG.AVG.
MALAD '87 1987 $1.99 $12.89 MALAD
MALAD '86 1986 AVG.AVG.20.7 MW
MALAD '85 1985 AVG.AVG.42.0 YEARS OLD
UPPER SALMON '89 1989 AVG.AVG.
UPPER SALMON '88 1988 AVG.AVG.
UPPER SALMON '87 1987 $2.81 $21.35 UPPER SALMON
UPPER SALMON '86 1986 AVG.AVG.34.5 MW
UPPER SALMON '85 1985 AVG.AVG.43.0 YEARS OLD
LOWER SALMON '89 1989 AVG.AVG.
LOWER SALMON '88 1988 AVG.AVG.
LOWER SALMON '87 1987 $2.99 $13.83 LOWER SALMON
LOWER SALMON '86 1986 AVG.AVG.60.0 MW
LOWER SALMON '85 1985 AVG.AVG.41 .0 YEARS OLD
BLISS '89 1989 AVG.AVG.
BLISS '88 1988 AVG.AVG.
BLISS '87 1987 $1.29 $6.79 BLISS
BLISS '86 1986 AVG.AVG.75.0 MW
BLISS '85 1985 AVG.AVG.40.0 YEARS OLD
STRIKE '89 1989 AVG.AVG.
STRIKE '88 1988 AVG.AVG.
STRIKE '87 1987 $1.32 $7.73 STRIKE
STRIKE '86 1986 AVG.AVG.82.8 MW
STRIKE '85 1985 AVG.AVG.38.0 YEARS OLD
AMERICAN FALLS '89 1989 AVG.AVG.
AMERICAN FALLS '88 1988 AVG.AVG.
AMERICAN FALLS '81 1987 $3.02 $11. 35 AMERICAN FALLS
AMERICAN FALLS '86 1986 AVG.AVG.92.3 MW
AMERICAN FALLS '85 1985 AVG.AVG.12.0 YEARS OLD
OXBOW '89 1989 AVG.AVG.
OXBO '88 1988 AVG.AVG.
OXBOW '87 1987 $0.96 $4.81 OXBOW
OXBOW '86 1986 AVG.AVG.190.0 MW
OXBOW '85 1985 AVG.AVG.29.0 YEARS OLD
HELLS CANYON '89 1989 AVG.AVG.
HELLS CANYON '88 1988 AVG.AVG.
HELLS CANYON '87 1987 $0.56 $2.90 HELLS CANYON
HELLS CANYON '86 1986 AVG.AVG.391. 5 MW
HELLS CANYON '85 1985 AVG.AVG.23.0 YEARS OLD
BROWNLEE '89 1989 AVG.AVG.
BROWNLEE '88 1988 AVG.AVG.
BROWNLEE '81 1981 $0.53 $2.08 BROWNLEE
BROWNLEE '86 1986 AVG.AVG.585.4 MW
BROWNLEE '85 1985 AVG.AVG.23.0 YEARS OLD
IDAHO POWER COMPANY
Case No.IPC-E- 90- 8
Exhibi t No.103
T.Faull,Staff
11/9/90 Page i of 3
..CAPACITY GENERATION AVERAGE CAP.FACT.
HYDRO PLANT YEAR (MW)(MWh)(aMW)(%)------------------------------------------------------
TWIN FALLS '89 1989 8.4 63,593 7.3 86.0%
TWIN FALLS '88 1988 8.4 54,367 6.2 73.6%
TWIN FALLS '87 1987 8.4 66,036 7.5 89.3%
TWIN FALLS '86 1986 8.4 73,261 8.4 99.1%
TWIN FALLS '85 1985 8.4 74,005 8.4 100.1%
SWAN FALLS '89 1989 10.3 88,451 10.1 98.4%
SWAN FALLS '88 1988 10.3 92,710 10.6 103.1%
SWAN FALLS ' 87 1987 10.3 88,302 10.1 98.2%
SWAN FALLS '86 1986 10.3 80,345 9.2 89.4%
SWAN FALLS '85 1985 10.3 84,495 9.6 94.0%
CASCADE '89 1989 12.4 37,264 4.3 34.3%
CASCADE '88 1988 12.4 22,328 2.5 20.5%
CASCADE ' 87 1987 12.4 30,021 3.4 27.6%
CASCADE '86 1986 12.4 52,624 6.0 48.4%
CASCADE '85 1985 12.4 39,051 4.5 35.9%
SHOSHONE FALLS '89 1989 12.5 99.258 11. 3 90.6%
SHOSHONE FALLS '88 1988 12.5 94,546 10.8 86.3%
SHOSHONE FALLS '87 1987 12.5 69,558 7.9 63.5%
SHOSHONE FALLS '86 1986 12.5 37,334 4.3 34.1%
SHOSHONE FALLS '85 1985 12.5 48,528 5.5 44.3%
MALAD '89 1989 20.7 78,047 8.9 43.0%
MALAD '88 1988 20.7 180,474 20.6 99.5%
MALAD '87 1987 20.7 185,584 21. 2 102.3%
MALAD '86 1986 20.7 155.989 17 .8 86.0%
MALAD '85 1985 20.7 180,612 20.6 99.6%
UPPER SALMON '89 1989 34.5 249.042 28.4 82.4%
UPPER SALMON '88 1988 34.5 235,512 26.9 77.9%
UPPER SALMON '87 1987 34.5 274,806 31. 4 90.9%
UPPER SALMON '86 1986 34.5 282,465 32.2 93.5%
UPPER SALMON '85 1985 34.5 290,873.0 33.2 96.2%
LOWER SALMON '89 1989 60.0 235,299 26.9 44.8%
LOWER SALMON '88 1988 60.0 221,461 25.3 42.1%
LOWER SALMON '87 1987 60.0 263,047 30.0 50.0%
LOWER SALMON '86 1986 60.0 457,749 52.3 87.1%
LOWER SALMON '85 1985 60.0 379,213 43.3 72.1%
BLISS '89 1989 75.0 349,575 39.9 53.2%
BLISS '88 1988 75.0 333,319 38.1 50.7%
BLISS '87 1987 75.0 391,367 44.7 59.6%
BLISS '86 1986 75.0 484,596 55.3 73.8%
BLISS '85 1985 75.0 508,491 58.0 77.4%
STRIKE '89 1989 82.8 439,626 50.2 60.6%
STRIKE '88 1988 82.8 403,106 46.0 55.6%
STRIKE '87 1987 82.8 465,243 53.1 64.1%
STRIKE '86 1986 82.8 681,166 77.8 93.9%
STRIKE '85 1985 82.8 592,109 67.6 81.6%
AMERICAN FALLS '89 1989 92.3 269,790 30.8 33.4%
AMERICAN FALLS '88 1988 92.3 234,808 26.8 29.0%
AMERICAN FALLS '87 1987 92.3 327,622 37.4 40.5%
AMERICAN FALLS '86 1986 92.3 667,174 76.2 82.5%
AMERICAN FALLS '85 1985 92.3 536.430 61.2 66.3%
OXBOW '89 1989 190.0 980,413 111. 9 58.9%
OXBOW '88 1988 190.0 677 ,644 77 .4 40.7%
OXBO '87 1987 190.0 878,563 100.3 52.8%uxtJow .~~198~190.0 1.397 , O~ 1 159.5 83.9%
OXBOW '85 1985 190.0 1,194,306 136.3 71.8%
HELLS CANYON '89 1989 391.5 2,032.046 232.0 59.3%
HELLS CANYON '88 1988 391. 5 1,370,368 156.4 40.0%
HELLS CANYON '87 1987 391. 5 1,727,751 197.2 50.4%
HELLS CANYON '86 1986 391.5 2,509,024 286.4 73.2%
HELLS CANYON '85 1985 391.5 2,405,854 274.6 70.2%
BROWNLEE '89 1989 585.4 2,351,817 268.5 45.9%
BROWNLEE '88 1988 585.4 1.587,272 181. 2 31.0%
BROWNLEE '87 1987 585.4 2,103,407 240.1 41.0%
BROWNLEE '86 1986 585.4 3.887,256 443.8 75.8%
BROWNLEE '85 1985 585.4 2,983,072 340.5 58.2%
IÚAHOPOWER COMPANY
Case No.IPC-E-90..8ExhibitNo.103
T.Faull,Staff
11/9/90 Page 2 of 3
.COSTS COSTS . COST UNIT COST
HYDRO PLANT ($)(1992 $)(1992 $/MWh)(1992 $/kW)----------------------------------------------------------
TWIN FALLS '89 $219,050 $246,401 $3.875 $29.20
TWIN FALLS '88 $263,923 $308,753 $5.679 $36.60
TWIN FALLS '87 $139,252 $169,421 $2.566 $20.08
TWIN FALLS '86 $132,680 $167,883 $2.292 $19.90
TWIN FALLS '85 $127,923 $ ~ 68,338 $2.275 $19.95
SWAN FALLS '89 $952,425 $1,071,349 $12.112 $104.37
SWAN FALLS '88 $575,638 $673,415 $7.264 $65.60
SWAN FALLS '87 $484,351 $589,287 $6.674 $57.41
SWAN FALLS '86 $466,493 $530,262 $7.347 $57.50
SWAN FALLS '85 $441,014 $580,344 $6.868 $56.54
CASCADE '89 $131,255 $147,644 $3.962 $11,89
CASCADE '88 $152,297 $178,166 $7.979 $14.35
CASCADE ' 87 $155,118 $188,725 $6.286 $15.20
CASCADE '86 $183,334 $231,976 $4.408 $18.68
CASCADE '85 $207,783 $273,428 $7.002 $22.02
SHOSHONE FALLS '89 $278,917 $313,744 $3.161 $25.10
SHOSHONE FALLS '88 $175,099 $204,841 $2.167 $16.39
SHOSHONE FALLS '87 $196,672 $239,282 $3.440 $19.14
SHOSHONE FALLS '86 $306,024 $387,218 $10.372 $30.98
SHOSHONE FALLS '85 $323.892 $426,220 $8.783 $34. '0
MALAD '89 $244,868 $275,443 $3.529 $13.31
MALAD '88 $203,374 $237,919 $1,318 $11, 49
MALAD ' 87 ($66,145 )($80,476)($0.434)($3.39)
MALAD '86 $511,085 $646,686 $4.146 $31,;:4
MALAD '85 $193,131 $254,147 $1. 407 $12.28
UPPER SALMON '89 $762,935 $858,198 $3.446 $24.88
UPPER SALMON '88 $711,545 $832,407 $3.534 $24.13
UPPER SALMON '87 $534,441 $650,229 $2.366 $1 e. 85
UPPER SALMON '86 $566,535 $716,848 $2.538 $20.78
UPPER SALMON '85 $474,928 .$624,973 $2.149 $18.12
LOWER SALMON '89 $914,930 $1,029,172 $4.374 $17 .15
LOWER SALMON '88 $696,710 $815,052 $3.680 $13.58
LOWER SALMON ' 87 $780,201 $949,234 $3.609 $15.82
LOWER SALMON '86 $498,667 $630,973 $1, 378 $10.52
LOWER SALMON '85 $550,449 $724.353 $1. 910 $12.07
BLISS '89 $483,908 $544,331 $1. 557 $7. 26
BLISS '88 $474,894 $555,559 $1.667 $7. 41
BLISS '87 $469,001 $570.611 $1, 458 $7. ?1
BLISS '86 $427.579 $541,024 $1.116 $7.21
BLISS '85 $254.431 $334,814 $0.658 $4.46
STRIKE '89 $746,261 $839,442 $1,909 $10.14
STRIKE '88 $596,342 $697,636 $1. 731 $3.43
STRIKE '87 $429.668 $522,757 $1.124 $6.31
STRIKE '86 $353.651 $447,481 $0.657 $5.40
STRIKE '85 $527.101 $693,629 $1.171 $8.38
AMERICAN FALLS '89 $877 ,496 $987,064 $3.659 $10.69
AMERICAN FALLS 'S8 $919,701 $1,075,920 $4.582 $11. 65
AMERICAN FALLS '87 $865,762 $1,053,332 $3.215 $11.41
AMERICAN FALLS '86 $739,771 $936,046 $1.403 $10.14
AMERICAN FALLS '85 $903,766 $1,189,294 $2.217 $12.88
OXBOW '89 $932.351 $1,048,768 $ 1.070 $5.52
OXBOW '88 $812,699 $950,743 $1. 403 $5.00
OXBOW '87 1732.162 $890,787 $1.014 $4.69
OXBOW '86 $603,416 $763,514 $0.547 $4.02
OXBOW '85 $695,998 $915,886 $0.767 $4.82
HELLS CANYON '89 $673.591 $757,698 $0.373 $1.94
HELLS CANYON '88 $631.940 $739,280 $0.539 $1.89
HELLS CANYON '87 $813,807 $990,121 $0.573 $2.53
HELLS CANYON '86 $1,133,393 $1,434,104 $0.572 $3.66
HELLS CANYON '85 $1,333.740 $1,755,111 $0.730 $4.48
BROWNLEE '89 $1,223,548 $1,376,325 $0.585 $2.35
BROWNLEE '88 $1.148,602 $1,343,702 $0.847 $2.30
BROWNLEE '87 $1,032,048 $1,255,644 $0.597 $2.14
BROWNLEE '86 $905,745 $1,146,056 $0.295 $1.96
BROWNLEE '85 $741,394 $975,624 $0.327 $1. 67
IDAHO POWER COMPANY
Case No.IPC-E- 90- 8
Exhibi t No.103T.Faull,Staff11/9/90 Page 3 of 3
..
CBBCATE OF SEVI
I HEREBY CERTIFY THAT i HAVE THIS 9th DAY OF NOVEMBER,
1990, SERVED THE FOREGO I NG DIREC TESTIMO OF THMAS FAULL,
CASE NO. IPC-E-90-8, ON ALL PARTIES OF RECORD BY MAILING A COpy
THEREOF, POSTAGE PREPAID, TO THE FOLLOWING:
LARRY D. RIPLEY, ESQ.
LEGAL DEPARTMENT
IDAHO POWER COMPANY
P. O. BOX 70
BOISE, ID 83707
STEVEN L. HERNDON, ESQ.
LEGAL DEPARTMENT
IDAHO POWER COMPANY
P. O. BOX 70
BOISE, ID 83707
HAROLD C. MILES
IOAHO CONSUMER AFFAIRS, INC.
316 - 15TH AVENUE SOUTH
NAMPA, 1D 83651
R. SCOTT PASLEY
ASSISTANT GENERAL COUNSEL
J. R. SIMPLOT COMPANY
P. O. BOX 27
BOISE, ID 83707-0027
DAVID H. HAWK, DIRECTOR
ENERGY NATURAL RESOURCES
J. R. SIMPLOT COMPANY
P. O. BOX 27
BOISE, ID 83707-0027
lCERT/142
CERTIFICATE OF SERVICE
GRANT E. TANNER, ESQ.
DAVIS WRIGHT TREMAINE
SUITE 2300
1300 S. W . FIFTH AVENUE
PORTLAND, OR 97201
PETER J. RICHARDSON, ESQ.
DAVIS WRIGHT TREMAINE
400 JEFFERSON PLACE
350 N. NINTH STREET
BOISE, ID 83702
JAMES N. ROETHE, ESQ.
PILLSBURY, MADISON & SUTRO
P.O. BOX 7880
SAN FRANCISCO, CA 94120
R. MICHAEL SOUTHCOMBE, ESQ.
CLEMONS, COSHO & HUMPHREY,
815 W. WASHINGTON STREET
BOISE, ID 83702-5590
OWEN H. ORNDORFF
ORNDORFF & PETERSON
SUITE 230
1087W. RIVER STREET
BOISE, ID 83702-7035
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