HomeMy WebLinkAbout20061010Sterling direct.pdfBEFORE THE RECEIVED
2006 OCT I 0 PM 2: 30
IDAHO PUBLIC UTILITIES COMMISS-ONUI
UT1UTrES COivlMiSSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR A
CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY FOR THE EV ANDER
ANDREWS POWER PLANT
) CASE NO. IPC-O6-
DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
OCTOBER 10, 2006
ALLEGEDLY PROPRIETARY DATA HAS BEEN
DELETED FROM THIS DOCUMENT
Please state your name and business address for
the record.
My name is Rick Sterling.My business address
is 472 West Washington Street Boise Idaho.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
Commission as a Staff engineer.
What is your educational and professional
background?
I received a Bachelor of Science degree in Civil
Engineering from the University of Idaho in 1981 and a
Master of Science degree in Civil Engineering from the
University of Idaho in 1983.I worked for the Idaho
Department of Water Resources from 1983 to 1994.In 1988
I became licensed in Idaho as a registered professional
Civil Engineer.I began working at the Idaho Public
Utilities Commission in 1994.My duties at the Commission
include analysis of utility applications and customer
petitions.
What is the purpose of your testimony in this
proceeding?
There are three primary purposes of my
testimony:
1) To address whether Idaho Power has
demonstrated a sufficient need for a new
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gas-fired peaking plant,
2) To address whether there are other, better
al ternati ves to meeting future load than
building a new generating plant, and
3) To address whether Idaho Power conducted a
fair Request for Proposals (RFP) process and
chose the best proposal.
Please summarize your testimony.
My testimony begins by reviewing Idaho Power
2004 IRP , which is the Company s basis for contending that
it needs to acquire a gas-fired peaking plant.I also
look at the 2006 IRP to see whether changes in loads,
resources, fuel prices and other factors since the 2004
IRP still support a new gas peaking plant.Based on my
reviews, I conclude that a gas peaker is needed.
Next, I discuss a variety of other options for
addressing Idaho Power s peak loads, including non-
Company-owned generation, conservation, demand response
transmission upgrades and others.I conclude that while
these are viable al ternati ves, they cannot be relied on
excl usi vely, and should continue to be pursued in
conjunction with a new gas-fired peaking plant.
Next, I review the RFP process followed by Idaho
Power.I discuss the method used to evaluate bids and
address the price and non-price differences between the
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two top-ranked proposals.I conclude that Idaho Power has
not provided sufficient justification for selecting a
proj ect that is approximately $11 million more costly than
the second place proposal , and I recommend that this
difference in cost not be allowed into rate base in the
future.
Finally, I discuss the proposal selected by
Idaho Power.I recommend that only the proj ect contract
amount of $49.999 million be accepted at this time, and
that all additional amounts spent on the project,
including transmission, be subject to future audit and
prudence reVlew.
Because your testimony is lengthy, please
provide a table of contents for the aid of readers.
A table of contents is provided below:
Sub-j ect Page
BACKGROUND
NEED FOR POWER
Transmission Constraints . 12
OTHER RESOURCE ALTERNATIVES . 13
New Customer-Owned Generation . 13
PURPA QFs . 15
Market Purchases . 16
Conservation . 18
Demand Response . 19
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Al ternati ve Rate Designs . 21
Transmission Upgrades . 22
Shoshone Falls . 23
REQUEST FOR PROPOSALS/OVERVIEW OF PROCESS . 24
Bids . 25
Evaluation of Bids . 28
Short List Analysis . 35
Analysis of Final Candidate Proposals . 36
PROJECT DESCRIPTION . 52
Operation . 52
Fuel Supply and Transportation . 53
Water Supply and Wastewater Treatment . 55
Electrical Interconnection . 55
Project Permits . 56
Environmental Impacts . 58
proj ect Risks . 58
proj ect Benefits . 58
FUTURE NEEDS . 60
CAPITAL COST COMMITMENT ESTIMATE . 61
TOTAL EXPECTED POWER COST . 67
SUMMARY AND RECOMMENDATIONS . 70
BACKGROUND
What is Idaho Power seeking in its Application
in this case?
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On April 14, 2006, Idaho Power Company filed an
Application for a Certificate of Public Convenience and
Necessi ty to construct a new generating plant at the site
known as the Evander Andrews Power Complex near Mountain
Home, Idaho.Idaho Power requested that the Commission
issue an Order granting a Certificate of Public
Convenience and Necessity to construct the proj ect with
upper limit of $60 million allowed for the Company
investment in the proj ect, excluding transmission costs
and subj ect to adjustment for legally-required changes and
material changes in assumed escalation rates not foreseen
at the time of the Application.Idaho Power also
requested that the Order note that, in the ordinary course
of events, Idaho Power can expect to rate base the prudent
capi tal costs for this proj ect and to recover prudent fuel
costs in the Company s Power Cost Adjustment mechanism.
NEED FOR POWER
What is the basis for Idaho Power s request to
construct a new generating plant?
Idaho Power maintains that its decision to
construct the new generating plant is based on its 2004
Integrated Resource Plan (IRP).The IRP process evaluated
the Company s future loads and resources and evaluated
various options for meeting proj ected loads.The opt ions
for meeting load include: the purchase of power from the
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wholesale market; the acquisition of additional generating
resources; the implementation of pricing options; and/or
implementing demand-side management programs.In short,
the IRP is a planning process on how Idaho Power intends
to meet its statutory obligations to serve its customers'
loads.
According to the 2004 IRP , what is Idaho Power
strategy for meeting future loads?
Idaho Power s strategy for meeting future load
was described in the 2004 IRP as follows:
Fall 2004
Issue an RFP for an 88 MW combustion turbine
peaking resource (the proposed Evander Andrews
plant in this case)
Issue an RFP for a 200 MW wind resource
Proceed with the Borah-West transmission upgrade
File a supplement to the 2004 IRP presenting the
results of the ongoing demand-side management
studies
File for an energy efficiency tariff rider with
the Oregon PUC
2005
Design demand-side measures in coordination with
the Energy Efficiency Advisory Group and Public
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Utility Commissions
Issue an RFP for a 12 MW Combined Heat and Power
(CHP) resource
Issue an RFP for a 100 MW geothermal resource
For the most part, Idaho Power has followed the
plan as set forth above, although it has deviated
somewha t .The RFP for an 88 MW combustion turbine, the
subject of this case, was delayed until March 2005 rather
than being issued in the Fall 2004.The RFP for a wind
resource was issued in December 2004, and was scaled back
to 100 MW due to the unexpected influx of PURPA wind
proj ects.An RFP for 12 MW of CHP has been delayed
indefini tely, and the RFP for the geothermal resource was
not issued until June 2006.
Do you believe that it is appropriate for Idaho
Power to base the need for a new peaking plant on its 2004
IRP?
At the time the Company began the RFP process
for a new peaking resource, the 2004 IRP was the best
information available to assess existing resources,
forecasted loads and potential new resource options.
However , because the 2006 IRP has just been completed, I
believe that the need for the plant must also be further
evaluated using the most up-to-date information available.
Without a doubt, changes have occurred since the 2004 IRP
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was prepared.Load forecasts have been revised, fuel
costs have increased and new resource costs have been
updated.
Do you agree that the 2004 IRP demonstrates a
need for the Evander Andrews proj ect?
Yes, the 2004 IRP shows peak hour deficits in
the months of May-September and November-December in every
year of the planning period under 90 th percentile water
and 70th percentile load conditions (the conditions
adopted by Idaho Power for peak capacity planning) .See
Exhibit No. 101.Even under median water and load
conditions, the Company projects deficits of approximately
200 MW in the July-August time periods. See Exhibit No.
102.When it was assumed that power would be imported
subject to the limits of Idaho Power s transmission
capaci ty, the analysis shows peak hour deficits beginning
in the summer of 2006 and growing rapidly thereafter.See
Exhibit No. 103.
By the time this testimony is filed, Idaho Power
will have submitted its 2006 IRP for Commission approval.
What does the draft 2006 IRP show with regard to Idaho
Power s need for peaking resources?
The addition of the Bennett Mountain plant, a
revised load growth forecast, and the impacts of peak load
reduction DSM programs have been included in the new load-
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resource balance.In addition , the analysis assumes that
the proposed new Evander Andrews plant is approved.
Exhibit No. 104 indicates that under the planning criteria
used to evaluate peak-hour conditions, deficiencies exist
during summer months throughout the planning period.
Summer deficiencies from 2006-2010 vary between 350 to 400
MW even with the assumed addition of the new Evander
Andrews plant in April 2008 and the expansion of the
Shoshone Falls proj ect in 2010.For the remainder of the
planning period, deficiencies in July increase from 450 MW
to 1,800 MW in 2025.
Even with the recent addition of the Bennett
Mountain plant, the assumption of the new Evander Andrews
plant and the implementation of new DSM programs, the
Company s most recent load-resource balance still
demonstrates an inability to meet peak-hour loads in the
summer and winter beginning in 2009.
What does the preferred resource portfolio
consist of in the Draft 2006 IRP?
Over the next 10-year time horizon , the
preferred resource portfolio consists of a blend of wind,
geothermal and CHP through 2012 , followed by increased
transmission capacity, a pulverized coal plant and a coal-
fired integrated gasification combined cycle (IGCC) plant
in the 2012-2017 time frame.The entire resource
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portfolio is summarized in Exhibit No. 105.
Are there any gas-fired peaking plants included
in the preferred portfolio in the 2006 IRP?
No, there are none.In the draft 2006 IRP,
Idaho Power s existing gas-fired peaking resources at the
Evander Andrews Power Complex and the Bennett Mountain
facility continue to provide approximately 250 MW of
peaking resource capacity.Beginning in 2008, if
approved, the new peaking resource at the Evander Andrews
Power Complex (the unit for which Idaho Power is seeking
approval in this case) will contribute approximately 170
MW of additional gas-fired peaking capacity, bringing the
total gas-fired peaking capacity to approximately 420 MW.
The CHP called for in the plan is likely to be gas-fired
because the proj ects would presumably be located at
industrial facilities.
The four finalist portfolios selected for more
detailed risk analysis in the current draft of the 2006
IRP contain limited amounts of natural gas-fired
generation.With the possible exception of combined heat
and power (CHP) projects, which are likely to be natural
gas fired, there is only one natural gas fired resource in
the four portfolios.Finalist portfolio F-3 calls for a
170 MW combustion turbine in 2018.The preferred
portfolio, F-2 does not include any resources specifically
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identified as natural gas-fired, however, the portfolio
includes 150 MW of CHP.
If the 2006 IRP analysis were to be repeated,
this time assuming that the Evander Andrews proj ect is not
already part of the existing resource portfolio, would a
natural gas fired peaking plant be selected?
In response to production requests (Staff
request No. 95), Idaho Power states that it is almost
certain that a gas fired peaking plant would have been
selected as part of the preferred portfolio.The Company
cited its continued growth in summertime peak-hour loads
and concluded that it needs either generation resources
internal to its system or additional firm transmission
capacity to markets with availability of firm summertime
peak - hour energy.
Although Idaho Power may be correct in its
belief that a gas fired peaking plant would be selected,
the Company has not supported its belief by providing any
analysis.Wi thout any analysis, there is no way to verify
whether a gas fired peaking plant would, in fact, still be
selected.
Current gas prices, and those assumed in the
2006 IRP , are considerably higher than was assumed in the
2 0 04 I RP .Consequently, IRP analysis today is much less
likely to select gas-fired plants due to high fuel costs
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and high fuel price volatility as evidenced by the fact
that there are no gas-fired facilities in the preferred
portfolio in the 2006 IRP.
Transmission Constraints
What does the 2006 IRP analysis show with regard
to the Company s ability to import power into its system
in order to meet peak hour deficits?
Exhibit No. 106 indicates the amount of the peak
hour deficit that cannot be imported from the Pacific
Northwest over the existing transmission system based on
peak-hour planning criteria.In this analysis, a
deficiency exists in July 2007 due to the postponement of
the proposed Evander Andrews proj ect .Beginning in 2009,
long-term transmission deficiencies occur in summer months
and are expected to grow to approximately 1,550 MW by
2025.
The durations of Idaho Power s northwest
transmission constraints are very limited, amounting in
some cases to relatively few hours during the months.
Al though these hours seem fairly minimal, the consequences
of the transmission constraints during these hours could
be severe.Unless some other means could be found to
either reduce peak hourly loads or increase generation,
load curtailment would be necessary.
Given Idaho Power s load-resource balance under
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various water and load conditions, and its transmission
constraints that limit its ability to import power during
critical times of the year , do you believe that a gas-
fired peaking plant is necessary?
Yes, I do.Without it, I believe there could be
times when load could not be met, either with Idaho
Power s own resources or with resources from outside its
system.
OTHER RESOURCE ALTERNATIVES
New Cus tomer - Owned Generation
Are there customer-owned generation alternatives
to the proposed Evander Andrews plant?
Possibly.One al ternati ve would be to make a
firm wholesale purchase or exchange involving an existing
resource located wi thin Idaho Power s control area.
Except for PURPA proj ects, which I will discuss next,
these types of resources are generally few and far
between.This section (Pages 13 to 15) of Staff's direct
testimony contains confidential information subj ect
protective agreement.This section is attached as
Confidential Exhibit No. 114.
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PURPA QFs
Do you believe that more PURPA QFs could satisfy
Idaho Power s need for new peaking generation?
Nearly all of the recent PURPA development has
been small wind proj ects.It is unknown how much
additional capacity might be developed and when such
development might occur.There is currently a moratorium
on development of new wind QFs larger than 100 kW until
wind integration issues can be resolved (Order No. 29839,
Case No. IPC-05-22).
Because nearly all new QFs are wind proj ects,
however , it is unlikely that they could prove to be an
acceptable replacement even if they could be timely
developed.Wind generation is intermittent, thus there is
no guarantee that the generation would be available during
the peak hours when needed.I do not believe that PURPA
QFs, especially wind, are well suited to meet the extreme
peaking needs of Idaho Power.
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Market Purchases
Are market purchases a reasonable alternative
for meeting future peak loads?
According to Idaho Power, it may be possible to
purchase a custom-made product from a marketer that
provides structured products, but such a purchase would
require transmission from Mid-C across one or more of the
Bonneville Power, PacifiCorp, Avista or NorthWestern
transmission systems, in conj unction with transmission
across Idaho Power s transmission system from the Hells
Canyon Complex to its load center.Because one or more of
these paths are subj ect to congestion, energy purchased at
Mid-C cannot be used at all times to meet the load
requirements of Idaho Power.In addition, because custom-
made products provide a significant amount of optionality,
they carry a significant premium to fixed price term
products as well as credit exposure to the selling party
according to Idaho Power.
Another alternative would be to make firm
wholesale purchases and to acquire the necessary
transmission to deliver the energy to the east side of
Idaho Power s system.In fact, as stated in Company
wi tness Said's testimony, Idaho Power did just that for
the summer of 2007 to meet heavy load hour requirements.
Idaho Power made a 50 MW market purchase including the
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associated transmission.Al though such purchases may be
available from time to time, I do not believe it would be
wise to rely on them indefinitely to meet peak hour needs,
especially during a time when surplus generation may be in
short supply.Moreover , firm wholesale purchases
delivered to the east side of its system use an increment
of import capacity that , because it is being used for a
purchase, would be unavailable in the event of a system
emergency.
If it could, do you believe it would be wise for
Idaho Power to rely on the market to meet its peaking
needs?
Even if Idaho Power could rely on the regional
power market as an al ternati ve to building new
generation , I believe, as was demonstrated in 2000 and
2001 , that relying on the market carries greater risk.
Over the long term , the market could arguably be the
least cost source for new supply.However, most
customers are unable or unwilling to tolerate the price
volatility that comes with significant exposure to the
market.Moreover , besides its effect on customers, the
risk of over-reliance on the market can potentially
weaken the financial strength of utilities if extreme
price excursions occur.
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Conservation
Do you believe that conservation is a viable
alternative to adding a new generating resource?
Energy conservation should certainly be an
ongoing part of all utilities ' strategies whenever cost
effecti ve.In its 2004 IRP , Idaho Power identified six
programs for implementation, all of which were in place
and operating by the end of 2005.The two demand response
programs, I rriga t ion Peak Rewards and A/ C Cool Credi t
resul ted in a reduction of summertime peak-hour load of
over 43 MW.The other programs, although they will reduce
peak load somewhat, are primarily targeted towards
achieving energy savings.
Conservation programs of the past, as well as
programs underway now, have certainly proven that energy
usage can be reduced cost effectively.However, even the
most successful conservation programs take time to have an
impact and can rarely keep pace with the increasing load
growth that must be met.Conservation programs cannot, in
my opinion , achieve enough demand reduction, nor can they
achieve it quickly or reliably enough, to realistically
satisfy the Company s immediate need to meet growing peak
loads.Furthermore, traditional conservation is usually
spread over all hours and is not necessarily focused on
the super peak hours of need identified by Idaho Power.
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As a result, I do not believe conservation can be
considered a viable stand-alone option to issuance of an
RFP for new generation.
Demand Response
Is Idaho Power pursuing demand response programs
for the purpose of reducing peak-hourly loads?
Yes, the Company has implemented two programs
aimed primarily at peak load reduction.I discuss each of
them below.
1. A/ C Cool Credi t
Under this program, Idaho Power manages air
conditioning use between 1 p. m. and 9 p. m. for up to 10
days a month from June through August, turning it off no
more than 15 minutes at a time.The air conditioner
cycling program targets heavy-load hours between June and
Augus t .After two summers of a pilot program, the second
season of full operation of the program is just now
conc 1 uding .Idaho Power will continue to ramp up the
program by increasing participation levels.The Company
expects the program to be fully implemented in 2009.
Through the end of July 2006 , approximately 3600 customers
were participating in the program.Idaho Power reported
in its 2005 DSM Annual Report that it expects to achieve a
16 kW reduction per participant.
2. Irriqation Peak Rewards
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This voluntary program targets irrigation
customers with pumps of 100 horsepower or greater with an
obj ecti ve of reducing peak electrical load during summer
weekday afternoons by providing control over load demand.
The program utilizes electronic time-activated switches to
turn off pumps of participating irrigation customers
during predetermined intervals.Participants are given a
demand credit based on the number of interruptions per
week.In 2005, Idaho Power reported that peak energy
savings amounted to approximately 40 MW.Results for 2006
have not yet been reported.
Has Idaho Power explored a program to interrupt
large commercial, industrial and irrigation loads during
peak periods in exchange for credit?
During 2001, in response to extremely high
market prices and low water conditions, Idaho Power
implemented an Energy Exchange program for its largest
commercial, industrial and large irrigation customers.
Participating customers were required to be able to reduce
their electrical load by 1000 kW at each meter point.
Under this voluntary load reduction program, Idaho Power
offered to credit customers half of the then current
market price for each kWh reduced during declared Exchange
Events.An Exchange Event was a set of hours during which
Idaho Power would ask participants to reduce their
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electric load during specific hours on specific days.
The Company reported that of 35 eligible
customers, only two customers participated, representing
five metering points.These five service points had the
combined potential of providing a maximum of 13 MW of load
reduct ion.Most customers, Idaho Power claims, chose not
to participate in the program because of their inability
to curtail load or because the incentive represents such a
small part of the customers ' total operating costs.Idaho
Power chose to not request an extension of the program.
Alternative Rate Designs
Are there al ternati ve rate designs that can
reduce peak hourly loads?
Time-of -use (TOU) rates and seasonal rates,
particularly for those customer classes whose summertime
usage is most responsible for causing the high hourly
peaks, are al ternati ve rate designs that can be viable
options.In June 2004, Idaho Power implemented seasonal
pricing for all residential, commercial and industrial
customers and established TOU pricing in addition to
seasonal pricing for all industrial customers.The
primary obj ecti ve in implementing these rates was to more
closely match prices to the actual cost of power , and to
more fairly charge customers based on their pattern of
usage.A secondary goal , however, was to encourage
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customers to shift usage from on-peak to off -peak hours.
Idaho Power is still exploring time-of -use rates
for residential customers.On March 22 , 2005, the
Commission issued Order No.2 973 7 approving Schedule 4
the Energy Watch Pilot Program , and Schedule 5, the Time-
of-Day pilot Program.The programs are offered in
conjunction with an AMR pilot project involving
approximately 23,500 customers in Idaho Power s Emmett and
McCall operating areas.On March 3 , 2005, the Company
requested that the Company be allowed to continue to offer
the Time-of-Day and Energy Watch pilot programs until
April 1, 2007.So far, the Company has not done an
assessment to determine the extent to which peak hour
loads have been shifted.
Transmission Upgrades
Idaho Power has contended that the primary
reason for needing new generation to be located near its
load center is because of transmission constraints on
imports from the Northwest.Are transmission upgrades a
viable alternative to the Evander Andrews plant?
I would characterize transmission upgrades as a
necessary component, rather than an al ternati ve, in Idaho
Power s plans to meet future peak loads.The Company has
been upgrading portions of its transmission system to
reduce constraints.The Brownlee to Oxbow proj ect was
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completed in late 2003.It increased the Brownlee East
capacity by approximately 100 MW.Even with this
improvement, however, Idaho Power s transmission system is
still constrained at certain times for imports of energy
from the Pacific Northwest.Idaho Power is presently
upgrading the capacity of the Borah-West path.This will
increase the Borah-West transmission capacity by 250 MW
and is scheduled for completion in May 2007.The
increased transmission capacity will be available to serve
Idaho Power s native load requirements with new generating
resources located east of the Borah-West constraint
(eastern Idaho)
In its 2006 IRP , Idaho Power has expanded its
analysis of possible transmission proj ects, associated
costs, and potential risks.Based on its analysis, the
preferred portfolio in the draft 2006 IRP incorporates a
285 MW transmission upgrade from McNary (Mid-C) to Boise.
Shoshone Falls
As early as 1993 , Idaho Power identified an
upgrade to its Shoshone Falls plant as one means of
helping to meet future load, but the upgrade has yet to be
started.What is the status of the proposed proj ect?
It was initially anticipated that capacity
expansion of the Shoshone Falls plant would be completed
in conjunction with its scheduled FERC relicensing
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application to be filed in 1997 , and that the expansion
would be completed in 2004.However , rather than
modifying the re-licensing application, Idaho Power
decided to wait until a new license was issued before
proceeding with permitting for the Shoshone Falls upgrade.
Idaho Power received the new license on August 4 , 2004.
On August 17 , 2006 , Idaho Power filed for an amendment to
its recently issued license seeking permission to expand
the plant to provide an additional 50 MW.During July,
when the Company s future peak generation needs are
greatest, the upgrade would provide 18 MW under the
percent water condition used for capacity planning.
Do you believe that the other resource
al ternati ves that you just discussed can collectively
substitute for a new gas fired peaking plant?
No, I do not.While I believe each of these
other al ternati ves is important, all of them are either
already being pursued and are a part of the Company s plan
going forward, or they cannot be counted on with
certainty.There may be room for increased efforts,
particularly with regard to conservation and demand
response, but I believe a new peaking resource is still
necessary.
REQUEST FOR PROPOSALS/OVERVIEW OF PROCESS
Please provide a brief overview of the request
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for proposals (RFP) issued by Idaho Power.
As called for in its 2004 IRP , Idaho Power
issued the RFP on March 30, 2005.The RFP sought
proposals for a turnkey electric generation resource
located within the Company s service territory to meet
peak energy demands beginning no later than April 1, 2007.
Idaho Power anticipated acquiring 88 MW of delivered
capaci ty, but stated that based on present market
conditions of combustion turbines , it was willing to
consider acquiring resources from 80 MW to 200 MW.The
RFP clearly stated that power purchase agreements where
legal title of the generating facilities is not conveyed
would not be considered in the RFP.Combustion turbines
were identified as the preferred technology.The RFP
stated that the primary need for the new resource is to
provide electricity during peak energy requirements for
the Treasure Valley load center.Idaho Power invited
respondents to offer proposals to locate turnkey
generating facilities at 1) the Evander Andrews Power
Complex site located near Mountain Home, 2) the Bennett
Mountain Power Plant site also located near Mountain Home,
or 3) at a site of the respondent's choosing.
Bids
Please summarize the response Idaho Power
received to its RFP.
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Idaho Power received 31 proposals from nine
companies by the June 2 , 2005 RFP deadline.Generating
units ranged in size from 71 MW to 171 MW.The proposal s
included large and small frame combustion turbines,
aeroderi vati ve combustion turbines, and reciprocating
engines.proj ects were proposed at four sites, including
the existing Evander Andrews site and the Bennett Mountain
site.Both new and secondary market machines were
proposed.All of the bids proposed to use natural gas for
fuel.
Did Idaho Power prepare a self-build option?
No, it did not.
Why not?
Idaho Power Company previously issued an RFP for
a peaking resource in February 2003.A self-build
proposal was prepared during that RFP.However , because
the Company does not maintain a significant power plant
design and construction workforce, the self -build option
represented Idaho Power as a general contractor that
subcontracted for materials, design and labor.Idaho
Power ultimately determined that not only were bids
received in the 2003 RFP process competitive, but also
that the selected Mountain View Power bid for the Bennett
Mountain proj ect was superior to the self -build option.
Wi th the 2005 RFP, the Company was convinced that based
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upon recent experience with the 2003 RFP process, it would
receive sufficient competitive bids, the Company had
reasonable benchmarks for peaking unit prices , and that
expenses associated with self -build bid preparation could
be avoided.
Do you agree with the Company s decision not to
include a self-build option?
Yes, I do.If Idaho Power had prepared a
proposal in which it acted as a general contractor and
subcontracted for engineering, materials and construction
I have no reason to believe it could build the project
less expensively than a contractor who specializes in
building power plants.
Do you believe that the number and variety of
proposals received was sufficient to give reasonable
assurance that all realistic options could be considered
and that a competitive price could be obtained?
Yes, I do.Each of the nine companies
submitting bids had previous experience developing similar
proj ects .Moreover , the 31 bids included several types
and sizes of equipment.Approximately one-third of the
bids were for aeroderivative units close to the 88 MW
capaci ty sought in the IRP, approximately one- fourth were
for small frame units in the 70-100 MW size range, and the
remainder were large frame units in the 150-170 MW range.
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In addition, there was one bid for reciprocating engines.
There were considerably more bids received in this RFP
than in previous RFPs for the Bennett Mountain and Danskin
proj ects .
Evaluation of Bids
please briefly describe the bid evaluation
process used by Idaho Power.
To review and score proposals, Idaho Power
assembled an evaluation team consisting of six employees -
three from the Power Production business unit, one from
Power Supply Reporting, one from Load Research , and one
from the Pricing and Regulatory Services business unit of
the Company.In addition , two advisors - one from the
Company s Legal Department and one from Power Engineers, a
third party consultant - provided guidance to the
evaluation team.
The evaluation team ranked the proposals using
the procedures and criteria outlined in an Evaluation
Manual prepared prior to the receipt of bids.Idaho Power
prepared the Evaluation Manual with the assistance of
Power Engineers, its consultant.The Evaluation Manual
identified the criteria upon which the proposals would be
scored, assigned a maximum number of points to each
criterion, and provided a scoring guide to be used in
determining how points would be awarded for each
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criterion.
This section (Pages 29 to 30) of Staff's direct testimony
contains confidential information subject to protective
agreement. This section is attached as Confidential
Exhibi t No. 115.
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How were non-price scores determined?
To evaluate the bids based on non-price
criteria, Idaho Power s evaluation team reviewed the
proposals and collectively awarded a single set of points
to each proposal in each category.Scores for all factors
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STAFF
were then totaled for each bid.
Do you believe that the non-price criteria used
in the evaluation were reasonable?
I believe the evaluation criteria were
reasonable and not intended to favor one proposal over
another.The criteria were established prior to the
receipt of bids with the guidance and assistance of a
third-party consultant.However, many of the non-price
criteria required subjective judgment in point factoring,
which made them prone to bias.
Were all of the exact evaluation criteria and
the points associated with each made known to bidders in
advance?
No, all of the price and non-price scoring
criteria, including the methods by which scores would be
awarded, were kept confidential , both before bids were
submitted and after the evaluation process was complete.
Although details of the price evaluation methodology were
not disclosed , bidders should have obviously known that
price would be a maj or factor in the scoring.The non-
prlce evaluation criteria were not nearly as well known by
bidders , although the RFP did give some indication of what
cri teria might be used.For example, the RFP stated
proj ects that provide advantageous siting, demonstrated
communi ty acceptance, completed environmental analysis,
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completed archaeological analysis, and completed
permitting may be viewed favorably in the selection
process." Reference RFP page 14.
The RFP also included the following in its list
of non-price attributes to be considered in the evaluation
of proposals:
Provide an advantageous proj ect location
considering: grid location , zoning, community
acceptance, use of existing IPC operation and
maintenance personnel, local water supply and
other environmental impacts and
Demonstrate enhancement of IPC system
reliability, integrity, and utilization
through application of mature technologies.
Reference RFP page 22.
Do you believe that all evaluation criteria and
methods should be kept confidential in the future?
No, I do not.Obviously, I believe that bids
should be kept confidential and that price information
should not be publicly divulged at any time in the
evaluation process.However, I see no compelling reason
for the exact price and non-price evaluation methodologies
and criteria to be kept confidential.If all bidders know
in advance what criteria and methods will be used to
evaluate their proposals, I believe they are more likely
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(Di) 32
to make proposals that more closely match the utility
needs and preferences.By keeping evaluation criteria
confidential, competition between bidders is stifled.
recommend that all evaluation criteria and methods be
di vulged in future RFPs.
Were transmission costs considered in evaluating
bids?
Yes, transmission costs were considered when
evaluating all bids.The transmission cost estimates were
based on studies performed by Idaho Power s Transmission
business unit ("Delivery Studies were developed for
each of the four different sites included in the bids and
for various proposed equipment sizes.proj ects of similar
size at the same proposed locations were consistently
assigned the same transmission costs.Al though considered
in the bid analysis, transmission costs have not been
included in the Company s Commitment Estimate.
Did the RFP inform bidders of the likely
transmission cost differences based on where proj ects
might be located?
Respondents were advised in the RFP that
proposals for proj ects to be located at sites other than
Evander Andrews or Bennett Mountain that depend on
transfer of energy across the transmission constraints for
delivery to the Boise area will have an extremely heavy
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burden to demonstrate to Idaho Power s satisfaction that
sufficient transmission capacity can be made available in
time to meet the April 1, 2007 provisional acceptance
deadl ine .The RFP included approximate transmission
pricing information based on proximity to the Boise area.
Four cost zones were identified.Costs of $3 to $10
million were estimated for the zone encompassing the
Boise-Caldwell area.An estimated cost of $15 to $25
million was given for the zone reaching from the greater
Boise area to Ontario.Costs of $20 to $40 million were
estimated for the zone between Boise and Midpoint
(including the Mountain Home area) .Finally, costs of $30
to $60 million were estimated for sites east of Midpoint.
Do you believe bidders took this information
into account when preparing their bids?
Absolutely.There were only four locations at
which proj ects were proposed to be built - the Evander
Andrews and the Bennett Mountain sites near Mountain Home
that were identified in the RFP , and two other sites.
Both of the other sites were within the zone encompassing
the Boise load center in which transmission costs were
expected to be lowest.Some bidders apparently recognized
that their proposals could win an immediate price
advantage of from $17 to $30 million over the Evander
Andrews and Bennett Mountain sites if they found sites
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close to Boise.
What natural gas price was used in performing
the price analysis?
Gas prices were assumed to be $4.61 per MMBtu in
2007 and were escalated throughout the life of the
project.These were the same gas prices assumed by Idaho
Power in its 2004 IRP.
Were the gas prices assumed in the cost analysis
critical to the results?
Because the same gas price was utilized for all
proj ect proposals, proj ects with lower guaranteed heat
rates had lower fuel costs on a cost per MWh basis.
However , because variable costs were only used to
determine relative variable cost scores, the exact gas
price used was not critical as long as it was the same for
all proposals.
Short List Analysis
Please describe how Idaho Power developed a
short list of proj ects and completed further analysis of
the short list proposals.
After the stage 2 screening was completed, the
top fifteen proposals (from four different bidders) were
short-listed and meetings with representatives of the
short-listed entities were held in October 2005.The
Company sent a document to each of the short-listed
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bidders detailing the Company s understanding of each
respect i ve bid.The review of those documents and the
meetings with bidder s enabled Idaho Power to clarify
bids, such as definitively determining what things were or
were not included in the bid, so that a revised second-
round analysis could be completed.A copy of Idaho
Power s summary of the fifteen short-listed proposals,
along with a summary of the price and non-price factor
scores is attached in confidential Exhibit No. 108.
Following the meetings with the short-listed
bidders and based on the results of the second-round
evaluations, the Company pursued final negotiations with
two bidders who had each submitted three different
proposals.
Analysis of Final Candidate Proposals
Were the final candidate proposals modified
before Idaho Power made its final analysis of the
proposals?
During the final stage of the analysis, Idaho
Power decided to delay the proposed on-line date of the
project from June 2007 until April 2008.As a resul t, the
two finalist bidders were requested to modify their bids
to reflect the revised on-line date.The six modified
bids were then compared in the final analysis.A summary
of the six finalist bids is attached as confidential
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Exhibit No. 109.Based on the final analysis, the RFP
evaluation team made its recommendation to the Company
management, who in turn recommended to the IdaCorp Board
of Directors that the Siemens Power Generation, Inc.
Evander Andrews bid be selected.
This section (Pages 37 to 52) of Staff's direct testimony
contains confidential information subject to protective
agreement.This section is attached as Confidenital
Exhibi t No. 116.
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PROJECT DESCRIPTION
Please describe the proposed Evander Andrews
plant.
The proposed Evander Andrews plant will be a
nominal 170 MW natural gas fired, simple cycle power plant
to be located at the existing approximately 40-acre
Evander Andrews Power Complex located north of 1-
approximately two miles northwest of the City of Mountain
Home.In 2001, Idaho Power built two 45-MW simple cycle
combustion turbines at the site, which were formerly
sometimes referred to as the "Danskin Plant.The
proposed proj ect' s combustion turbine is a single Siemens
Westinghouse model 501F (also known as SGT6 -5000F) .
Opera tion
Please describe the expected operation of the
proposed Evander Andrews plant.
If approved, the Evander Andrews plant will be
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operated to meet peak-hour loads primarily in the summer
and winter.The plant is currently scheduled to be
available to meet peak loads in April of 2008.While
there may be occasional opportunities to market the output
of the Evander Andrews plant when it is not needed to meet
the Company s own load, Idaho Power does not anticipate
marketing a significant amount of the plant's output.The
opportunity for sales of surplus energy will depend on the
difference between the market price of power and the
Evander Andrews plant's cost of production.Because
Evander Andrews is a simple cycle plant, its dispatch cost
is higher than combined cycle plants in the region;
consequently, it may not often be cost effective to
operate the plant to make off-system sales.
Fuel Supply and Transportation
As a part of this Application, Idaho Power is
requesting that it be allowed to include the proj ect '
cost of fuel , fuel storage and fuel transportation for
recovery through the existing Power Cost Adjustment (PCA)
mechanism.Do you agree that this is appropriate?
A maj or component of the operating costs of a
combustion turbine generating plant is the cost of natural
gas fuel.Staff agrees that reasonable fuel expenses
should be approved for PCA recovery prior to full review
of normal operational costs in a general revenue
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requirement case.Operation of the plant will displace
other more costly power supplies to the benefit of Idaho
Power customers; therefore, costs should be included in
the PCA.This is consistent with the manner in which fuel
costs are handled for the Bennett Mountain and Danskin
plants.
How will natural gas be delivered to the plant?
A natural gas fuel supply will be delivered from
the Williams Northwest Pipeline via an existing pipeline
to the Evander Andrews site.Idaho Power has not yet
negotiated or entered into any agreements for the purchase
of natural gas fuel supplies for the proposed Evander
Andrews plant.
How does Idaho Power manage the risk associated
with purchasing natural gas for fuel?
Idaho Power has an Energy Risk Management Policy
and natural gas is listed as a permitted commodity;
however , the policy does not specifically address
acquisi tion of natural gas.An internal Risk Management
Committee regularly quantifies, assesses, and manages the
Company s risk in accordance with the Risk Management
Policy.
Idaho Power also has gas hedging guidelines for
the existing Evander Andrews/Danskin Power plant.I f the
new Evander Andrews plant is approved, I would expect the
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Company to develop its fuel procurement strategy for both
natural gas and transportation capacity as well as
expanded hedging guidelines and risk management strategies
for all of the Evander Andrews plants and the Bennett
Mountain plant.
Does Idaho Power have adequate fuel
transportation rights on the Williams Pipeline to
accommodate the proposed plant?
Idaho Power already possesses firm fuel
transportation rights that can be used for both the
existing and new Evander Andrews plant and the Bennett
Mountain plant.Sufficient transportation rights to serve
the Evander Andrews plant are available without a pipeline
expans i on .
Wa ter Supply and Was tewa ter Trea tmen t
What is Idaho Power s plan for water supply and
wastewater treatment?
Water would be used by the plant primarily for
evaporative cooling, which is normally only required in
the summer months.Water can be supplied by an existing
well at the Evander Andrews site.Wastewater from the
plant will be retained in an existing retention pond and
then pumped out for irrigating landscaping.
Electrical Interconnection
What transmission work would have to be done in
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order to interconnect the proposed plant?
In order to interconnect the proposed plant, a
de-energized 132 kV transmission line between the Bennett
Mountain plant and the Mora substation near Boise would
have to be rebuilt to 230 kV.The route of this line
passes in the vicinity of the Evander Andrews site.
additional transmission improvement would be needed
between the Evander Andrews plant and the existing Bennett
Mountain plant.The estimated total cost for the
transmission work is estimated at $26 million, with
approximately $22 million allocated to the Evander Andrews
proj ect for the generator interconnection and the
remaining $4 million allocated to Idaho Power Delivery to
correct existing operational concerns.At this point,
costs are based on a feasibility study and are only rough
estimates.Detailed costs would be developed in a Design
Study.The $22.8 million amount for transmission
discussed in the Company s application is simply the
initial $22 million amount escalated by the one year the
proj ect was delayed.The cost of this transmission
upgrade is not included in the proj ect commitment estimate
and could be higher or lower.
Project Permits
Please discuss the air quality permit that will
be required for the proposed plant.
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Certainly one of the most critical permits
needed by the project is an air quality permit (Permit to
Construct) issued by the Idaho Department of Environmental
Quality (DEQ).Idaho Power has not yet made an
application for such a permit; however, the Company
environmental consultant has completed the necessary
studies to prepare an application for a permit.The
studies indicate that the expected emission from the
proposed plant will be less than half the emissions from
the recently completed Bennett Mountain plant.I ha ve
discussed the permit with DEQ staff and they do not expect
Idaho Power to have any difficulty in obtaining a permit.
The time needed to obtain a permit was estimated by DEQ to
be approximately 160 days.
Will the project requlre a Conditional Use
Permi t ?
A gas-fired combustion turbine is a permitted
use within the existing zoning designation where the
Evander Andrews proj ect is located.Consequently, Elmore
County will not require a Conditional Use Permit.
will other permits be required?
Yes, but because two smaller gas- fired turbines
are already operating at the Evander Andrews site,
additional required permits will be minor.Permits will
be necessary for such things as transporting materials and
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equipment on public highways; disposing of excavated
materials; insuring compliance with construction noise and
building permits.
Environmental Impacts
What will be the most significant environmental
impact of the proposed proj ect?
The most significant environmental impact of the
Evander Andrews proj ect will be air emissions.The
primary pollutants from gas-fired plants are NOx and
carbon dioxide.The DEQ Permit to Construct will specify
emission limits for the proj ect.
proj ect Risks
What are some of the risks associated with the
Evander Andrews proj ect
There will be some risk associated with the
Evander Andrews proj ect simply because it uses natural gas
for fuel.As evidenced by the past several years, gas
prices can be quite volatile.The proj ect would increase
the amount of gas-fired generation in Idaho Power s fleet
to 422 MW.Owning gas-fired generation could perhaps
ultimately lead to slightly greater rate stability than if
the same output were purchased from the market, but Idaho
Power cannot escape gas price risk.
proj ect Benefits
What would be some of the benefits of the
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Evander Andrews proj ect?
There are several notable benefits to the
proposed Evander Andrews proj ect First, the cost of the
proj ect, although slightly higher than the recently
completed Bennett Mountain proj ect, is still quite
attractive, primarily due to the availability of
combustion turbines at bargain prices.Turbine prices are
currently very low because equipment destined for new
plants now has nowhere to go due to numerous plant
cancellations, the financial difficulties of many
developers, and the demise of others.
Second, the Evander Andrews proj ect appears to
have strong local acceptance.This would be the third
gas-fired combustion turbine project in the Mountain Home
area.I am not aware of any local opposition.
Third , the new proposed Evander Andrews plant
would be located at the site of an existing plant
(Danskin) , and is only a few miles from the Bennett
Mountain plant, enabling sharing of operational staff and
equipment.
Finally, the Evander Andrews plant will be fully
dispatchable and available for use by Idaho Power at any
time.If another entity owned the plant and Idaho Power
purchased output under a power purchase agreement, this
would not be possible.
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FUTURE NEEDS
The proposed Evander Andrews proj ect would add
170 MW of peaking capacity to Idaho Power s portfolio,yet
the 2004 IRP upon which the RFP was based indicated a need
for only MW of peaking capacity.will this extra
peaking capacity be needed in the future?
Idaho Power s peak load is growing at a rate of
about 80 MW per year.The Company s average load is
growing at about half that rate.Idaho Power is currently
in the process of finalizing the 2006 IRP , which more
closely examines both the magnitude and timing of the
Company s future resource needs.The 2006 IRP does not
call for any near-term additions of peaking generation
resources, although it does call for expansion of some
demand reduction programs.In addition, it calls for
completion of the 100 MW RFP for wind, completion of the
100 MW RFP for geothermal, possibly the issuance of an RFP
for 50 MW of CHP , a 225 MW upgrade to the McNary-Boise
transmission line, and continued investigation into the
possibility of jointly developing a coal project.The
additional peaking capacity provided by the proposed
Evander Andrews plant will help to satisfy peak load
requirements in the future and enable the Company to add
mostly base-load generation that will be used to meet both
peak and average load growth.
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CAPITAL COST COMMITMENT ESTIMATE
Please discuss Idaho Power s capital cost
Commitment Estimate.
Idaho Power has negotiated a contract with
Siemens Power Generation Inc. containing a firm price for
the completed project in the amount of $49,999,000.Based
on this contract, Idaho Power states that it is able to
make a reliable estimate of the total capital cost of the
project.This estimate, which Idaho Power has termed a
Commitment Estimate" is a good faith estimate of the
proj ect I s total capital cost based on the contract with
Siemens plus certain additional costs the Company knows it
will incur but cannot quantify with precision at this
time.These additional costs include (but are not limited
to) sales taxes, AFUDC, the cost of Idaho Power oversight
of the project and the cost of capitalized start-up fuel.
These additional costs would be approximately the same
regardless of which proposal Idaho Power had selected.
The Commitment Estimate also covers contingencies such as
change orders and other unforeseen events.Idaho Power
Commitment Estimate for the project is $60 million, or
about $10 million more than Siemens contract amount.
Idaho Power states that it will commit to
procure and install the Evander Andrews proj ect for the
Commitment Estimate.The Commitment Estimate would also
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be subj ect to adjustment to account for documented legally
required equipment changes, such as to comply with new air
quality laws for example , and for extreme changes in
inflation and prices.If the final capital cost of the
proj ect exceeds the Commitment Estimate, Idaho Power
states that it will absorb the extra cost.The Company
will include in its Idaho rate base only the amount
actually incurred up to the Commitment Estimate.
If the proj ect is approved for rate base
treatment, Idaho Power has pledged to provide the
Commission with periodic percentage of completion and cost
expenditure reports during the construction phase.The
final report on the proj ect will compare the actual
completed cost to the Commitment Estimate.
What is not included in Idaho Power s Commitment
Estimate?
The Commitment Estimate does not include the
cost of constructing or upgrading transmission facilities
to interconnect the proj ect with the Company s existing
transmission system.The studies needed to fully define
interconnection and transmission upgrade costs have not
been completed.However, Idaho Power s Transmission
Business Unit (Delivery) has provided a preliminary upper
limit estimate of $22.8 million to interconnect the
project.
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Do you believe that the Commitment Estimate of
$60 million is reasonable?
Yes, I bel ieve that the Commitment Estimate for
the proj ect is reasonable.The Commitment Estimate for
the Bennett Mountain plant, which was a nearly identical
plant completed in 2005, was $54.0 million , excluding
transmission.The Bennett Mountain plant produces about 8
less megawatts than the proposed Evander Andrews plant,
but emits nearly twice as much NOx.I think both
proj ects, due to an ongoing abundance of turbines
available in the market, reflect excellent prices by
standards of the past several years.Siemens is able to
construct the proj ect at significantly lower costs than
similar proj ects constructed just a short time ago.The
commitment cost of $60 million for the 170 MW Evander
Andrews project is just $11 million more than the $49
million cost of the 90 MW Danskin proj ect completed in
September 2001.
Are you willing to accept costs up to the
Commitment Estimate for future inclusion in rate base?
The Idaho Power-Siemens contractNo, I am not.
amount of $49,999,000 is a known amount that, except for
possible change orders, will not change once Idaho Power
takes ownership of the plant.Moreover, the amount was
established through a competitive bidding process that the
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Staff finds acceptable.Consequently, I am willing to
accept cost up to this amount in rate base.However,
those costs above the $49,999,000 contract amount, up to
the Commitment Estimate of $60 million, cannot be
quantified with precision at this time according to Idaho
Power.Furthermore, those expected costs might not be
subject to a competitive bidding process, or to the
advance scrutiny of the Commission or its Staff.
Consequently, I recommend that these expected costs (up to
a maximum $ 10,001 000) be subject to audit by the
Commission Staff , and that the Commission withhold rate
base consideration of these costs until after the proj ect
is constructed and the audit is completed.
Idaho Power has provided a Commitment Estimate
of $60 million for construction of the proposed Evander
Andrews proj ect and has estimated that transmission costs
to interconnect and integrate the plant into its system
will be an additional $22.8 million.The $22.8 million is
not included in the $60 million Commitment Estimate,
however.Why did Idaho Power not provide a similar
commi tment estimate for transmission costs, like it did
for plant construction?
As explained by Company witness Said in his
direct testimony, a Certificate of Convenience and
Necessity is only required for construction of new
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(Di)
generation facilities.Such a certificate is not required
for construction of transmission facilities in a territory
already served by the utility.
Do you agree?
Yes, Idaho Code ~61-526 requires certificates of
publ ic convenience and necessity for generation proj ects
but not for extension of existing transmission systems.
Thus, once the new transmission line has been built and is
used to provide power to customers, Idaho Power will
presumably seek to include these transmission costs in
rate base.At that time, a judgment of whether
transmission costs have been prudently incurred would be
made.
However, whether a certificate is required or
not , I see little difference in the reason for requiring a
commitment estimate for new generation plant or for a new
major transmission addition needed to deliver that
generation.I believe it is necessary and prudent to
obtain a commitment estimate for transmission as well, for
two reasons.First, with a transmission cost estimate of
$22.8 million, transmission costs represent about 27.
percent of the entire proj ect cost.Second, the plant is
inextricably linked to the transmission.In other words,
the plant is not useful without the upgraded transmission
that Idaho Power says is necessary to bring generation to
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the Treasure Valley load center.
Would you be willing to accept the Company
estimate of $22.8 million for transmission costs as a
commitment estimate?
, the $22.8 million estimate for transmission
is only a preliminary cost estimate based on the initial
feasibility study; therefore, the estimate is not precise.
A more detailed analysis would be required in order to
establish a commitment estimate.In fact, based on its
response to Staff production request No. 94, even Idaho
Power itself is not willing to provide a commitment
estimate for transmission at this time.As stated by the
Company, "Idaho Power Company is unable to provide a
commitment estimate for transmission costs that would be
incurred to integrate the proposed new Evander Andrews
generating plant, similar to the Commitment Estimate
offered for the plant construction.
...
At the present time,
only feasibility and technical studies have been completed
for the transmission improvements required to integrate
the new facility into the Company s transmission system.
Furthermore, even if transmission costs are more
accurately determined and a commitment estimate provided
in the future, I would still recommend that the Company
not be allowed to recover costs in excess of the lower
cost proposal.Because the excess costs are due primarily
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STAFF
to transmission , I would expect this amount to be deducted
from the transmission cost commitment estimate.
Are there other ways to help insure that
transmission costs will be reasonable?
Yes, it is likely that Idaho Power would solicit
bids for the maj ori ty of the required transmission work
rather than complete the work using its own staff.
long as the job, including materials, is competitively
bid, it is reasonable to expect that a competi ti ve price
would be obtained.While this doesn t guard against the
possibility of transmission costs greatly exceeding the
estimate, it at least offers some protection that
transmission costs will be reasonable.Nevertheless, I
still believe that Idaho Power should develop and be bound
by a commitment estimate for transmission.
TOTAL EXPECTED POWER COST
What is the total expected power cost for the
proposed Evander Andrews plant?
Based on Idaho Power s economic analysis of the
proposal, including the estimate of $22.8 million for the
cost of transmission and the Siemens contract amount of
$49.999 million, the 30-year fixed levelized cost of
energy from Evander Andrews will be $4.23 per kW-month.
The 30-year levelized dispatch cost would be $61.09 per
MWh using the Company s assumed gas prices.The total
CASE NO. IPC-E- 06 - 9
10/02/06
STERLING, R.
STAFF
(Di) 67
cost of power is the sum of these two components.
Why didn t Idaho Power compute a total power
cost in dollars per MWh rather than computing two separate
cost components?
In order to compute the total power cost as a
single dollars per MWh figure, an assumption must be made
about the plant capacity factor i. e., the percentage of
time the plant is expected to operate.While it is easy
to assume a capacity factor, the assumption is invariably
going to be wrong because plants such as Evander Andrews
are usually operated in response to deviations from normal
water, load, or market conditions.For peaking plants
that are expected to operate relatively few hours per
year , this approach produces a total power cost that seems
very high because fixed costs get spread over very few
hours in the year.Moreover , this high cost per MWh is
frequently misused when it is compared to the cost of
other resources or alternatives with much higher capacity
factors.
It is also extremely important to recognize that
the price of energy computed for analysis purposes is
highly dependent on the cost of gas that is assumed in the
analysis.Idaho Power s analysis assumed a starting gas
price of $4.61 per MMBtu, with prices in future years
based on various forecasts available to the Company.
CASE NO. IPC-E- 06 - 910/02/06 STERLING, R.
STAFF
(Di)
These estimates may be reasonable based on today s gas
prices and forecasts, but prices could turn out to be much
different than assumed in the analysis.Because each of
the proposals considered by Idaho Power in the final
analysis proposed to use gas as fuel, the effect of
different gas prices was similar on each proposal's cost,
except to the extent some proj ects may have been more
efficient than others.
Can you compare the total cost of power from the
proj ect to other market al ternati ves?
It is difficult to make a comparison to other
market alternatives because it could be argued that the
market is not really an al ternati ve to the Evander Andrews
plant due to transmission constraints.However , just for
the sake of comparison , I asked Idaho Power to make
estimates of the monthly heavy load hour prices for the
next five and ten-year periods.The Company s estimated
average 5-year heavy load hour price is $68.44 per MWh,
and the average 10-year price is $70.24 per MWh.These
prices are almost certainly lower than the total costs of
the Evander Andrews plant because its estimated dispatch
cost alone is $61 per MWh.The addition of fixed costs
would increase that total substantially.
Are avoided cost rates for PURPA contracts a
fair comparison to expected costs of the Evander Andrews
CASE NO. IPC-E- 06 - 910/02/06 (Di) 69STERLING, R.
STAFF
plant?
I do not believe avoided cost rates used for
PURPA QF contracts is a fair comparison to the cost Idaho
Power will pay for power from the Evander Andrews plant.
Avoided cost rates are computed using a combined cycle
combustion turbine rather than a simple cycle turbine like
Evander Andrews.Avoided cost rates are not really
comparable to the Evander Andrews power costs because they
represent the price of two very different products.
Avoided cost rate computations assume that the plant is
operated nearly all of the time , not just during a limited
number of peak hours in the summer and winter.Avoided
cost rates are reflective of the cost of base load
generation , while Evander Andrews is dedicated to
providing peaking capacity.
SUMMARY AND RECOMMENDATIONS
Are you convinced that Idaho Power has
demonstrated a genuine need for the Evander Andrews plant?
Yes, I am convinced that peaking power is needed
by Idaho Power beginning in the summer of 2008, and that
construction of a peaking plant is the Company s best
alternative.Under the right set of circumstances,
believe it might be possible for Idaho Power to find
enough al ternati ves that collectively could eliminate, or
at least defer, the need for the Evander Andrews plant.
CASE NO. IPC-E- 06 - 910/02/06 (Di) 70STERLING, R.
STAFF
However , some of the possible alternatives - such as new
industrial cogeneration , increased PURPA development, or
significantly increased participation in DSM and demand
response programs - are mostly outside of the control of
the Company.Relying on them would be very risky.
Do you believe that the request for proposals,
the criteria used by Idaho Power to evaluate bids, and
analysis of the bids was fair to all proposals?
I believe that the RFP was fair and that the
evaluation criteria were reasonable.However , because
some of the non-price evaluation criteria were subjective
and because some of the scores would likely be different
based on what is known today, I do not believe that the
process produced a fair outcome.In addition, I recommend
that in future RFPs Idaho Power be required to divulge all
criteria and methods that will be used to evaluate
proposals so that bidders can more effectively compete.
Do you recommend that the Commission issue to
Idaho Power a Certificate of Public Convenience and
Necessi ty to construct the new Evander Andrews plant?
Yes, with reservations.I believe that in the
ordinary course of events the Commission may authorize the
rate basing of the amount of the Siemens Evander Andrews
Agreement amount of $49 999,000.I recommend that the
actual amount of capital costs to be rate based above the
CASE NO. IPC-06-10/02/06 (Di) 71STERLING, R.
STAFF
bid price of $49,999,000 up to the Commitment Estimate of
$60 million be subj ect to review in a subsequent case.
addition , I recommend that Idaho Power be ordered to
develop a commitment estimate for the cost of constructing
the transmission and substation facilities necessary for
the Evander Andrews plant.This section of Staff's direct
testimony contains confidential information subject to
protective agreement. This section is attached as
Conf ideni tal Exhibi t No. 117.
If the Commission approves a
Certificate of Convenience and Necessity for the proj ect
and rate base treatment in the normal course of events , I
recommend that Idaho Power be ordered to provide the
Commission with periodic percentage of completion and cost
expenditure reports during the construction phase.
What is your recommendation with regard to fuel
for the Evander Andrews plant?
I recommend that Idaho Power be allowed to
incl ude the proj ect I s cost of fuel , fuel storage and fuel
transportation for recovery through the existing Power
Cost Adjustment (PCA) mechanism.
Do you have any other recommendations?
I also recommend that the Company be strongly
encouraged to diligently continue to investigate and,
where warranted, begin implementing conservation, demand
CASE NO. IPC-06-10/02/06 STERLING, R.
STAFF
(Di) 72
response and pricing options that could potentially
displace or defer the need for additional future peaking
generation.
Does this conclude your direct testimony in this
proceeding?
Yes, it does.
CASE NO. IPC-06-
10/02/06
STERLING, R.
STAFF
(Di) 73
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STAFF EXHIBIT NOS. 107 THROUGH 117
CONT AIN CONFIDENTIAL INFORMATION
SUBJECT TO THE PROTECTIVE AGREEMENT
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 10TH DAY OF OCTOBER 2006
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN CASE
NO. IPC-06-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
MONICA MOEN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
(Confidential)
JAMES C MILLER
SR. VICE PRESIDENT, GENERATION
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
(Non-Confidential)
PETER J RICHARDSON
RICHARDSON & O'LEARY
515 N 27TH ST
PO BOX 7218
BOISE ID 83702
(Confidential)
DR DON READING
6070 HILL ROAD
BOISE ID 83703
(Confidential)
RONALD L WILLIAMS
WILLIAMS BRADBURY PC
PO BOX 2128
BOISE ID 83701
(Non-Confidential)
ROBERT D LOOPER
PRESIDENT
MOUNTAIN VIEW POWER INC
1015 W HAYS ST
BOISE ID 83702
(Non-Confidential)
SEC
~~--
CERTIFICATE OF SERVICE