19901109Faull Direct.pdf

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BEFORE THE IDAHO PULIC UT COMMSSION
IN TI MA'l OF TH APPLCATION OF ) CASB NO. IP-B-902mAHO POWER COMPAN FORAUTORl )TO RATEE TH IN BEUID )FOR TH REBun OF TI SWAN FAL )HYROBLECTC PROJE. )
)
DIRCT TEONY OF THOMA FAUL
IDAHO PUC um COMMSSION
NOVEMBER 9, 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. Exhibi t 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 project, to provide an engineering
opinion as to the appropriateness of the project, and
to recommend Commission action relative to the project.
Q.What is your understanding of the
purpose of this case?
A.I believe the purpose of this Case is to
determine whether the project concept is sound enough
to authorize IPCo to proceed wi th proj ect development.
The purpose is not to determine whether to grant at
this time rate base treatment of unknown future costs
IPC-E-90-211/9/90 FAUl,L (Di)Staff 1
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of the Swan Falls Power Plant upgrade.
Q.Why is it important to know the cost
effectiveness of a project when determining whether or
not to authorize continued project development?
A.It is important to know the relative
cost effectiveness of a specific project to judge the
potential value of the project to ratepayers.
Q.Are there other criteria that should
guide the Commission in accepting or rejecting the Swan
Falls Plant concept for future rate making analyses?
A.Yes. As discussed by Staff witness
Eastlake, there may be features (intrinsic, extrinsic,
or both) other than project costs that should be
considered. However, I believe the primary guideline
ought to be cost effectiveness, wi th consideration of
other factors being supplementary.
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
proj ect wi 1 1 be?
A.Rather than estimating the construction
cost of the project, I have accepted IPCo' s proposed
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cap on capital costs of $80,285,000 as a maximum (or
worst-case) cost. Then, from that I estimate the
50-year levelized cost to ratepayers for this project
will be $73. 05/MWh.
Q.Why did you use a 50-year life rather
than some longer or shorter period?
A.Fifty years is an arbitrary but common
life over which to analyze the value of hydro electric
proj ects. I looked at, but rej ected three other
project life lengths: 1.) The 17 years that will be
left to the FERC license at the time the plant comes on
line in 1993 ($84. 72/MWh), 2.) a longer arbi trary but
also commonly used life of 60 years ($72. 57/MWh), and
3.) a shorter arbitrary but also commonly used life of
40 years ($73. 88/MWh) . As these numbers show, there is
little difference among the 40-, 50-, and 60-year
estimates.
Although the 17-year life corresponds to
IPCo' s maximum assured right to operate a plant at the
project site, I believe it is reasonable to use longer
lives for economic comparisons because if IPCo is
unable to obtain a renewal of the license as a result
of losing the site to a competitive applicant, it would
be entitled to receive any unrecovered value remaining
in the plant from the new licensee. Of the three
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potential arbitrary life lengths I considered, I chose
50 years because it is, I believe, the most commonly
accepted hydro project life used for analyzing and rate
basing IPCo projects. Using 60 years, 40 years, or any
of a wide range of arbitrary project life lengths would
be equally as reasonable as using the 50 year life that
I chose, provided the analytic life does not exceed the
reasonably expected physical life of the plant.
However, if project costs are approved for rate making
purposes based on an economic anaiysis, the
depreciation period for rate making purposes should
correspond to the economic life used in the economic
analysis -- in this case 50 years.
Q.How did you determine the uni t costs you
cite?
A.I used a "net present value" computer
model similar to the one IPCo used to evaluate its
Milner Plant. In addition to the Swan Falls capital
cost cap, I input the following key data as variables.
.The average annual generation from
the plant as included in IPCo' s
second amended FERC license
application, using 60 years of
historic water data (166,102
MWh/yr) i
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.the capital structure and rates
required by Order No. 23357 for
determining avoided cost rates
(lL. 447%) i
.tax variables used by IPCo in its
evaluation of the Milner plant,
operating and maintenance (O&M)
costs of $450,000 ($18. OO/kW);
.an escalation rate of 4.5% per
year i
.a property tax rate of 0.7381% of
capi ta 1 costs;
.insurance costs of 0.06854% ofcapi ta 1 costs i
.FERC licensing costs of $60,743
(the reported cost of IPCo' s
licensing activities relative to
the Milner Plant, which is
probably lower than that of theSwan Falls Plant) i
.a ki lowatt-hour tax rate of 0.5
mills/kWh; and
.values of 25.00/58.27 times the
amount recommended by IPCo for its
Milner Plant to estimate the
expenses associated wi th headwater
benefit payments, environmental
mitigation, and water bank
payments.
Q.Can you further explain the analysis by
which you estimated annual O&M costs?
IPC-E-90-211/9/90
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
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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 capacity 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 years
of data for each plant. I then graphed the cost per
kW relative to the rated capaci ty. The resulting
graph is included as Exhibi t No. 102, and the data
from which Exhibi t No. 102 were 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
signif icant hydro plant, so it is reasonable to
interpolate between data points provided there is a
reasonable 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
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
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developed (Exhibi t No. 103) that one should expect
IPCo to experience O&M costs of about $18/kW for a 25
MW hydro plant. This is the rate I used in my
analysis of the Swan Falls Plant.
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))
coming on line in 1993 is $61.44/MWh. In light of
this, do you consider your estimated cost of
$73.05/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
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
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determined that the comparable avoided cost rate
(without "tilting") would be $59.17/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 wi th the actual project.
When this adjustment is made the comparable 20 year
avoided cost rate (without "tilting") is $64.77/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, f rom a ratepayer viewpoint, IPCo' s
50-year project should be compared to 50 years of
avoidable costs. That is, when IPCo bui lds a resource
wi th a 50 year life ratepayers can reasonably expect
that they will have access to the energy from that
resource for the ful 1 50 years, so other resource
costs can be avoided for the full 50 years.
Using the Surrogate Avoidable Resource
(SAR) methodology specified by the Commission,
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assuming a new SAR wi 1 I be bui 1 t at the end of the
35-year life of the first SAR, assuming a first
defici t year of 1994, assuming that the adjustable
portion will escalate, and assuming an on-line year of
1993 yields a 50-yea r avoided cost of $70. 54/MWh.
Taking into account the seasonality weighting of
avoided costs relative to the availability of the Swan
Falls Plant reduces the value of the avoided costs
applicable at Swan Falls to $69. 48/MWh. I believe
this is the appropriate avoided cost rate to use for
determining the cost effectiveness of the Swan Falls
Plant.
Thus, the Swan Falls Plant, with an
estimated cost of $73. 05/MWh, is approximately as cost
effecti ve as the comparable avoided cost rate, wi thin
the reasonable limits of accuracy for the
methodologies used to determine the costs and rates.
(73.05/69.47 = 105.2%)
Q.You indicate that there has been a
Petition for Reconsideration of Order No. 23357 filed
that could affect the Ufirst 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 Swan Falls Plant?
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A.There is a potential 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 Swan Falls Plant. I would expect that change to
be less than 3% of avoided costs. Otherwi se, 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
Swan Falls Plant.
Q.You discuss the Swan Falls Plant as
though IPCo could avoid all the costs of the project
by simply walking away from it. Isn't it true that
IPCo must incur costs at the Swan Falls site no matter
what course of action it chooses?
A.Yes. Even if IPCo were to decide to
abandon the Swan Falls site, it would be required to
return the site and reservoir area to a condition
approximating natura 1 condi tions. This would be an
expensive undertaking, making the abandonment option
totally impractical. However, if this was the only
option to the proposed Swan Falls upgrade, these costs
would have to be subtracted from the upgrade
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construction costs for avoided cost analysis because
they would be non-avoidable costs. Nonetheless, these
costs could be avoided by selecting some different,
more practical alternative to IPCo's proposed Swan
Falls upgrade.
The most practical alternatives to the
proposed project are either an up-(down-)sizing of the
proposed plant or an alternative stabi lization method
for the powerhouse that permits using the existing
turbine bays for new or modified turbines. The
up~(down-)sizing option is just a matter of project
optimization and wi II be discussed later. But the
option of using the existing turbine bays presents a
more complex si tuation. In that case, powerhouse
stabilization can be expected to be more expensive and
net annual generation can be expected to be less. It
is difficult to guess whether this option would have
presented a more cost effective solution to the Swan
Falls problem, but the comparison could only be made
by comparing the projected uni t costs of the most
optimal arrangement of the options.
In any event, with that in mind it could
easily be argued that, regardless of which option is
being considered, historic preservation costs and
dam/powerhouse stabi lizat ion costs a re unavoidable.
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Had I used this approach, I would have reduced Swan
Fa lIs capi ta I costs by about $4,000,000 (5%), thus
improving the cost effectiveness of the project.
Q.Suppose for a moment that, as a result
of this (or some future) proceeding, the estimated
cost of the Swan Falls 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 Swan
Falls 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 Swan Falls Project to be cost effective?
A.No. Under those ci rcumstances I believe
IPCo should be limited in its recovery to the
Commission determined comparable avoided cost rate.
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 Swan Falls 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
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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
elsewhere, including in Order No. 22636), it could
easily be argued that it is not appropriate for
evaluating the utilities' 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 wi th little
avai 1. Now, when it appears that new resources are
needed, the utilities have little conservation
"on-line", and are essentially unprepared to
aggressively bring such resources on line. Therefore,
it appears inequitable to ascribe a benefit to IPCo in
evaluating its supply side resources by ignoring the
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' s avoided cost computation for the
purpose of evaluating proposed utility owned supply
side resources, including the Swan Falls Plant.
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Q.Wouldn't limitations such as described
in your two prior answers unfairly deny IPCo from
recovering prudently incurred investment costs?
A.No. IPCo made its decisions,
commi tments, and contracts relative to this proj ect
whi le 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 while
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
resul t of chance that it now appears that those
decisions may have turned out to be marginally prudent
(at least as determined by my analyses). Therefore,
if it is determined that my analyses are in error and
that the Swan Falls Project costs are not competitive
wi th avoided costs, IPCo should be imputed to have
known that the project was not cost effective, at
least to the extent that Swan Falls costs exceed
avoided costs using the assumptions included in IPCo' s
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recommended avoided costs in Case No. IPC-E-89-11 and,
perhaps, iinputed 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 proposal being the most
cost effective development from the family of
reasonably 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?
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.
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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 that the Swan
Falls Plant appears to have been under-sized for the
flows at the site. The overall average capacity
factor of the project is more than 72%. The standard
in the industry is typically for overall capacity
factors of between 45% and 65%.
Al though I cannot say wi th certainty
that a higher capacity plant (yielding a lower
capacity factor) would be more cost effective, I
believe it would. Most of the civil costs of this
project are fixed, regardless of the mechanical and
electrical capacities of the turbine-generators.
Therefore, it is very likely that the increased costs
of up-sizing the plant to yield about a 50% plant
factor would be more than recovered over the life of
the project.
Note that the average generation
estimated by IPCo in its license application (and
accepted by me for economic analyses) results from
analysis of historic river flows, ignoring the
poss ibi 1 i ty that future f lows may be reduced due to
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consumptive uses upstream of Swan Falls. Although
this may be the reason IPCo sized the proposed plant
at 25 MW rather than something larger, it ignores the
possibility that Swan Falls flows may increase (rather
than decrease) in the future due to increased
irrigation efficiencies on upstream farms.
Furthermore, IPCo' s sizing of the Swan Falls Plant is
contradicted by its sizing of the proposed Mi Iner
Plant, which has a capacity factor under 35%. If IPCo
expects future f low reductions in the Snake River due
to consumptive use developments, surely it must expect
at least a few of those developments to be upstream of
the Milner site.
Another criticism I have of the Swan
Falls project costs as now estimated is the type of
mechanical technology selected. IPCo has specified a
system known as a modified bulb turbine for this
project. Bulb turbines and modified bulb turbines
have been around for years and are advertised as very
cost effective for low head sites such as Swan Falls.
Although there are good physical reasons why bulb-type
systems should be the most cost effective technology
available for low head sites, my experience has been
that vertical shaft kaplan turbines and S-type
turbines are always more economical than bulb
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turbines, even though they require more draft tube
excavation. Although I have no evidence that modified
bulb turbines are not the most cost effective
technology for the Swan Falls Plant, it is my
understanding that IPCo did not make a rigorous
comparison to assure that they are.
A thi rd criticism I have of the Swan
Falls project costs as now estimated is that IPCo
appears to be using 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 costsi especially on
large, complex projects such as the Swan Falls 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
timing, wi th minimal input from suppliers; whereas in
competitively negotiated contracts based on RFPs the
suppliers are challenged to provide their most
innovati ve combinations with f rui tful give-and-take
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discussions 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 probabi li ty of suppliers
receiving cost over-run payments for extra work,
unexpected conditions, 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).
An example of the limi tations inherent
in the firm bid system can be seen in IPCo's
acquisition of the Swan Falls Plant. s speed
increaser. I understand that, based on subj ecti ve
considerations, IPCo specified a concentric shaft
speed increaser with helical gear teeth, using a
specific manufacturer' s design (perhaps the only
supplier of that technology) as the standard to meet
for determining bid responsiveness. The specification
presumes, by definition, that this technology is the
most cost effective for the application. Although
that presumption may be true, there is no way to be
assured that it is. Under an RFP procurement method,
suppliers would have proposed competing technologies
as well as competing prices. Then IPCo could have
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negotiated the trade-offs between their preconceived
preferred technology and the simpler, less expensive
technologies to assure that the purchased equipment
was, in fact, the most cost effective.
Another example shows up in the limited
number of suppliers asked by IPCo to bid on the
turbine-generator package for the Swan Falls Plant.
It is probably reasonable under the firm bid
methodology that IPCo limited the list of potential
bidders to the four known suppliers of the type of
equipment specified. However, under the RFP method
there would have been a much larger number of
potential suppliers. Competition between other
suppliers and other technologies would have encouraged
manufacturers of modified bulb turbines to propose
their very best combination of technologies and
prices. Under the firm bid method actually used by
IPCo, all four bidders knew their competition's
approximate costs, present work loads, and the
approximate extent of interest in the project. (The
results of this particular bid process currently
appear to be three "courtesy" bids and one serious,
but not "hungry" ,bid. )
IPC-E-90-211/9/90 FAULL (Oi)Staff 20
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Q.Do you propose that project costs should
be disallowed for ratemaking purposes because you
believe IPCo has not optimized its Swan Falls resource?
A.No, at least not at this time. My
speculative cri ticisms do not provide evidence of
imprudent management. I merely include this part of
my testimony to provide support for the posi tion that
.IPCo should be held to a standard of avoided cost to
cap the ratemaking allowability of new resource costs,
and should have a heavy burden of proof to fully
justify its design and construction decisions prior to
such costs being allowed for rate making purposes.
Clearly the Swan Falls Plant could not 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
Swan Falls site may have been developable under the
23357 rates by a QF developer, albei t only after
hard-nosed negotiations and extensive design
modifications.
However, because it would be nearly
impossible to provide evidence to prove that IPCo had
not provided the optimum development for the resource,
the Commission is li.mited to using avoided cost as the
IPC-E-90-211/9/90 FAULL (Di)Staff 21
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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 perfect ly capable of
estimating 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 that are below avoided costs.
Q.What are your recommendations in this
case?
A.I recommend that, based on the estimate
tha t the Swan Fa i ls Proj ect (as proposed by IPCo)
could possibly provide energy at less than avoided
costs, the Commission find that the Swan Falls Hydro
Electric Plant concept is competi tive enough for costs
incurred in developing the project to be potentially
reasonable for future rate making consideration, with
the specific caveat that costs in excess of the
appropriate comparable avoided cost rate (to be
IPC-E-90-2
11/9/90 FAULL (Di)Staff 22
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determined in future proceedings) are, by defini tion,
imprudent ly incurred. I further recommend that the
Commission advise IPCo that this Certificate in no way
implies that all costs incurred in developing the
project are necessarily 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 proj ect was prudent in light
of the genera lly accepted standa rds of the hydro
electric construction industry. In determining the
comparable avoided cost rate the Commission should
consider and estimate all non-quantifiable risks.
Q.What kinds of non-quantifiable relative
risks should be considered, and how?
A.A few of the "relative risks" that come
to mind immediately are, for the Swan Falls Project,
the risk that future Snake River flows at the site may
be more (less) than the historic flows, that the Swan
Falls water rights playa pivotal role in IPCo' s
system-wide hydro electric operations and their loss
could severely reduce generation at other Snake River
power plants, and that the environmental impacts of
the proj ect may be more (less) than expected. For
potential thermal projects that could compete
economically with the Swan Falls Project, a couple of
IPC-E-90-211/9/90 FAULL (Di)Staff 23
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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 unquantifiable,
decision makers must make their own best estimate of
the level and impact of each of the potential
occurrences actually happening and then decide how to
factor that risk into granting or denying
Certification and/or rate making application of
project costs. wi th adequate evidence, the Commission
could convert its estimates into approximate costs for
compar ison purposes.
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 hydro has been more cost effective
than thermal is that fuel costs have escalated much
more rapidly than expected. Thus, the cri t ica 1
question when comparing a specific hydro plant to
potential thermal plants is "How does the probability
that we have over (under) estimated water flows
IPC-E-90-211/9/90 FAULL (Di)Staff 24
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compare to the probability that we have over (under)
estimated fuel costs?". The answer to this question
could be assigned an estimated cost value for
comparing potential projects.
Q.Doesn' t the consideration of relatively
unquantifiable 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
Cominission should use avoided cost as the presume
measure of prudence. Thus, as part of its application
for rate making treatment of any project, a utility
should be 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( s) of technology selected, method of
proj ect management, etc. Whether the Commission
should attempt to quantify its judgments on these
issues should be determined after accumulation of the
appropriate evidence impacting those judgments.
Q.Does this conclude your testimony?
A.Yes, it does.
IPC-E-90-211/9/90 FAULL (Oi)Staff 25
..
QUALIFICATIONS
OF
Thomas G. Faull, P.E.
of the
Idaho Public utilities Commission
Mr. Faull received a Bachelor of Science
degree from the University 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.
PROFESSIONA 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 i Mechanica 1
Colorado ¡General
New Mexicoi GeneralOregoni 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 capacities of
Mechanical Engineer,Contract Administrator,and
IDAHO POWER COMPANY
Case No. IPC-E-90-2
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 Res ident Engineer he supervised up to 50 engineers,
surveyors, and technicians providing quality control of
electrical, mechanical, and civil works of a 100,000
acre irrigation projecti including roads, highways,
canals, pumping plants, pipelines substations, and a
115kV transmission line.
From 1978 through 1986 Mr. Faull worked in
various capaci ties of consulting engineering. As such,
he did (or supervised) financial feasibility analyses,
design,construction management,construction,and
start-up of chemical, water, and energy projects,
including PURPA hydro, coal, and MSW proj ects. He also
did business development, bi 1 ling, personnel manage-
ment, and hiring/firing.
IDAHO POWER COMPANY
Case No. IPC-E-90-2
Exhibit No. 10l
T. Faull, Staff11/9/90 Page 2 of 4
..
From 1987 through the present Mr. Faull has
served as a Utilities Engineer at the Idaho Public
utilities Commission. In that capacity he has analyzed
Cogeneration and Small Power Producers ·(CSPPs' )
projects i developed computer models to represent
uti lities' Avoided Costs, power supplies, cash flows,
and other featuresi testified in electric avoided cost
cases i authored Proposed Orders pertaining to avoided
costs,CSPPs ·security arrangements,utility sur-
charges, and uti Ii ties' conservation/least-costplanning
programs i 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 Uti li ty 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, a NARUC 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-90-2
Exhibi t No. 101
T. Faull, Staff11/9/90 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."I rreconci lable Conf 1 ictsinherent in VerticallyElectr ic uti li ties" ,
of InterestIntegrated
2. "Solving the Overpayment Di lemma 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".
- = =.. _._. - -==-= _.- -- -=.=-_..- -=. --_. --- ... ----
IDAHO POWER COMPANY
Case No. IPC-E-90-2
Exhibit No. 101
T. Faull, Staff11/9/90 Page 4 of 4
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Case No. IPC-E-90-2
Exhibi t No. 102
T. Faull, Staff11(9(90 Page 1 of 2
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Case No. IPC-E-90-2
Exhibit No. 102
T. Faull, Staff11/9/90 Page 2 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. ° 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.AVa.41,0 YEARS OLD
BLISS '89 1989 Ava.Ava.
BLISS '88 1988 Ava.AVG.
BLISS '87 1987 $1.29 $6.79 BLISS
BLISS '86 1986 AVG.AVG.75.0 MW
BLISS '85 1985 Ava.AVG.40. ° YEARS OLD
STRIKE '89 1989 AVG.AVG.
STRIKE '88 1988 AVG.Ava.
STRIKE '87 1987 $1.32 $7.73 STRIKE
STRIKE '86 1986 Ava.AVG.82.8 MW
STRIKE '85 1985 AVG.AVG.38. ° YEARS OLD
AMERICAN FALLS '89 1989 AVG.AVG.
AMERICAN FALLS '88 1988 AVG.AVG.
AMERICAN FALLS '87 1987 $3.02 $11. 35 AMERICAN FALLS
AMERICAN FALLS '86 1986 Ava.AVG.92.3 MW
AMERICAN FALLS '85 1985 AVG.AVG.12.0 YEARS OLD
OXBOW '89 1989 AVG.AVG.
OXBO '88 1988 AVG.AVG.
OXBO '87 1987 $0.96 $4.81 OXBOW
OXBOW '86 1986 AVG.AVG.190.0 MW
OXBO '85 1985 AVG.AVG.29.0 YEARS OLD
HELLS CANYON '89 1989 AVG,AVG.
HELLS CANYON '88 1988 Ava.. Ava.
HELLS CANYON '87 1987 $0.56 $2.90 HELLS CANYON
HELLS CANYON '86 1986 Ava.Ava.391. 5 MW
HELLS CANYON '85 1985 Ava.Ava.23.0 YEARS OLD
BROWNLEE '89 1989 Ava.Ava.
BROWNLEE '88 1988 Ava.AVG.
BROWNLEE '87 1987 $0.53 $2,08 BROWNLEE
BROWNLEE '86 1986 Ava.Ava,585.4 MW
BROWNLEE '85 1985 AVG.Ava.23.0 YEARS OLD
IDAHO POWER COMPANY
Case No.IPC-E-90- 2ExhibitNo.103
T.Faull,Staff
11/9/90 Page 1 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 34,495 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%
OXBO '89 1989 190.0 980,413 111. 9 58.9%
OXBO '88 1988 190.0 677 ,644 77.4 40.7%
OXBO '87 1987 190.0 878,563 100.3 52.8'OX!r '!J6 1986 190.0 1,397,061 159.5 83.9%
OXBO '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%
IDAHO POWER COMPANY
Case No. IPC-E-90-2
Exhi1ìit No. 103
T.Fauii,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 $3.815 $29.20
TWIN FALLS '88 $263,923 $308,753 $5,619 $36,60
TWIN FALLS '81 $139,252 $169,421 $2.566 $20,08
TWIN FALLS '86 $132,680 $167,883 $2,292 $19,90
TWIN FALLS '85 $127,9::3 $'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 $590,262 $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 $204,341 $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. .19
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 $ ~ 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..l 1
SLISS '87 $469,001 $570,611 $1.458 $7.51
BLISS '86 $427,579 $541,024 $1.116 $7. 21
SLISS '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 $521,101 $693,629 $1. 171 $8.33
AMERICAN FALLS '89 $877 ,496 $987,064 $3.659 $10.69
AMERICAN FALLS '88 $919,701 $1,015,920 $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 $1.010 $5.52 .
OXBOW '88 $812,699 $950,743 $1. 403 $5,00
OXBO '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 $139,280 $0.539 $1,89
HELLS CANYON '87 $813,807 $990,121 $0,513 $2.53
HELLS CANYON '86 $1,133,393 $1,434,104 $0.512 $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- 2ExhibitNo.103
T.Faull,Staff
11/9/90 Page 3 o! 3
..
cimiCATE OF SEVI
I HEREBY CERTIFY THAT I HAVE THIS 9TH DAY OF NOVEMBER,
1990, SERVED THE FOREGOING DIRET ttSTIMOlI OP THS PAUL,
CASE NO. IPC-E-90-2, ON ALL PARTIES OF RECORD BY MAILING A COPY
THEREOF, POSTAGE PREPAID, TO THE FOLLOWING:
LARRY D. RIPLEY, ESQ.
IDAHO POWER COM.PANY
P. O. BOX 70
BOISE, 10 83707
GRANT E. TANNER, ESQ.
DAVIS WRIGHT TREMAINE
SUITE 2300
1300 S. W. FIFTH AVENUE
PORTLAND, OR 97201
STEVEN L. HERNDON
IDAHO POWER COMPANY
P. O. BOX 70
BOISE, 10 83707
PETER J. RICHARDSON, ESQ.
DAVIS WRIGHT TREMAINE
400 JEFFERSON PLACE
350 N. NINTH STREET
BOISE, ID 83702AFTON ENERGY, INC.
CIO OWEN H. ORNDORFF
ORNDORFF & PETERSON
SUITE 230
1087 W. RIVER STREET
BOISE, 10 83702
JAMES N. ROETHE
PILLSBURY MADISON & SUTRO
P.O. BOX 7880
SAN FRANCISCO, CA 94120
HAROLD C. MILES, CHAIRMAN
IDAHO CONSUMER AFFAIRS, INC
316 FIFTEENTH AVENUE SOUTH
NAMPA, ID 83651
R. MICHAEL SOUTHCOMBE
CLEMONS COSHO & HUMPHREY
815 W. WASHINGTON STREET
BOISE, ID 83702
J,~
SECRETARY
lCERT/120
CERTIFICATE OF SERVICE