20061011Reading direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COl\1P ANY FOR A
CERTIFICATE OF CONVENIENCE AND
NECESSITY FOR THE EV ANDER ANDREWSPOWER PLANT CASE NO. IPC-O6-
Direct Testimony of
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Don C. Reading, Ph.
Ben Johnson Associates, Inc.
On behalf of the
Industrial Customers of Idaho Power (ICIP)
(October 10 2006)
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INTRODUCTION
PLEASE STATE YOUR NAME AND BIDSNESS ADDRESS.
My name is Don Reading and my business address is Ben Johnson Associates
6070 Hill Road, Boise, Idaho.
HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR
QUALIFICATIONS AND BACKGROUND?
Yes. Exhibit No. 201 serves that purpose.
WHAT IS THE PURPOSE OF YOUR TESTIMONY IN TIDS CASE?
I have been retained by the Industrial Customers of Idaho Power ("ICIP") to
review Idaho Power s request for a Certificate of Public Convenience and Necessity
Certificate ) for the proposed Evander Andrews 170 MW gas-fired peaking plant
proposed to be constructed near Mt. Home Idaho. I am offering this testimony in order to
present the evidence supporting my conclusions that Idaho Power has not demonstrated
that the public convenience and necessity requirements have been met for the
construction of the Evander Andrews plant.
COULD YOU PLEASE PROVIDE A BRIEF DESCRIPTION OF ICIP AND
ITS INTEREST IN TIDS PROCEEDING?
ICIP is an unincorporated association of Schedule 19 customers ofIdaho Power.
All ICIP members receive electric utility services from Idaho Power Company. ICIP is
very concerned with making sure that Idaho Power makes wise resource decisions and
chooses the best and most cost-effective alternatives for meeting its power supply
obligations.
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COULD YOU PLEASE PROVIDE A BRIEF SUMMARY OF YOUR
TESTIMONY?
Yes. For the numerous reasons set forth in my testimony, the proposed Evander
Andrews project is the wrong resource for Idaho Power to be constructing at this time.
The Commission should reject Idaho Power s application for a Certificate to construct the
Evander Andrews project because it has not demonstrated that the public convenience
and necessity requires it.
As discussed in detail below, there are several fundamental problems with Idaho
Power s application and the proposed project. These problems include: 1) the proposed
project was only evaluated using information known by Idaho Power to be outdated and
inaccurate; 2) the proposed project does not comply with Idaho Power s 2004 Integrated
Resource Plan (IRP) and is not supported by the more recent 2006 IRP; 3) Idaho Power
failed to take an accurate and comprehensive look at several alternatives it has for
meeting its peak demand and the actual loads it will be serving; and 4) Idaho Power has
not justified its selection of a natural gas plant which is substantially more expensive than
other similar projects.
II.PUBLIC CONVENIENCE AND NECESSITY
DO YOU HAVE ANY CONCERNS ABOUT IDAHO POWER'
APPLICATION THAT STEM FROM THE FACT THAT THE PROPOSED
PLANT IS A NATURAL GAS-FIRED COMBUSTION TURBINE?
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Yes I do. Natural gas electrical plants are increasingly being viewed as high risk
and costly resource choices. Natural gas plants are generally expensive to operate, and
have highly volatile fuel costs, which makes most of their operating costs highly variable.
Additionally, there are questions about whether it is prudent to use gas solely to create
electricity, given the relatively low energy efficiency of burning natural gas solely for
power generation purposes.
This Commission has also expressly stated concerns about Idaho Power s reliance
on new natural gas-fIred electric plants. In reviewing Idaho Power s 2004 IRP, this
Commission stated
We are also pleased to see that the Company s preferred
portfolio includes larger acquisitions of renewable resources
namely wind and geothermal resources. However, the
Company s continued reliance on new gas-fIred generation to
meet summer peak causes us particular concern for two
reasons. First, natural gas prices continue to be volatile.
Second, the continued effects of the drought on irrigation
pumping and other state actions that reduce the amount of
irrigation pumping creates uncertainty regarding the need for
additional peaking resources. We are also concerned about a
possible over-reliance on natural gas peakers as a fall back
position due to a lack of transmission capacity.
(Order No. 29762, IPC-04-, p. 10). The Commission s concerns are as
valid today as they were in 2004.
WHY DOES THE COMPANY CLAIM IT NEEDS A NATURAL-GAS
PEAKING RESOURCE AT THIS TIME?
Idaho Power states that customer growth is the primary driving force behind the
Company s need for additional generating resources. (Said Direct, pp. 3-4). The
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Company s stated main reason for seeking a natural gas peaking plant is that its 2004
Integrated Resource Plan ("IRP") Near-Term Action Plan included an 88 MW natural gas
combustion turbine peaking resource. (Idaho Power Application pp. 3-4). The proposed
Evander Andrews project is a 170 MW resource. Although the proposed plant is nearly
double the size of the plant called for in Idaho Power s 2004 IRP, Idaho Power argues
that it is consistent with the 2004 IRP. (Idaho Power Application pp. 3-4).
WHY HAS IDAHO POWER COMPANY DOUBLED THE SIZE OF THE
PROPOSED PLANT FROM WHAT WAS CALLED FOR IN THE COMPANY'
2004 IRP?
The Company s explanation is that it was able to obtain economies of scale, or
more capacity at a competitive price. (Exhibit No. 202, Response to ICIP Request for
Production No.1). The Company is not claiming that it requires such a large plant in
order to ensure that it can meet its peak loads.
DO YOU AGREE THAT BECAUSE THE 2004 IRP CALLS FOR A
PEAKING RESOURCE, COUPLED WITH IDAHO POWER'S CUSTOMER
GROWTH, IDAHO POWER HAS JUSTIFIED THE NEED FOR THE EV ANDER
ANDREWS PROJECT?
No. It has been more than two years since the Company filed its 2004 IRP with
the Commission. (IPC-04-18). The information used to prepare the 2004 IRP
(obviously complied in the months before that filing) is substantially outdated. There
have been significant changes in both the energy picture and Idaho Power s situation
since the filing of the 2004 IRP that cast doubt on the need for a large natural gas
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powered peaking unit at this time.
In addition, the Company has developed and provided the ICIP with a draft of its
2006 IRP in this proceeding. (Idaho Power filed its Final 2006 IRP on October 2, 2006).
The draft and final 2006 IRPs contain updated information, on a more current basis. It
would be more appropriate to use the current 2006 IRP information to evaluate the
question of whether to construct the Evander Andrews project, or acquire other
alternative resources to meet the Company s load.
YOU SEEM CONCERNED THE PROPOSED 170 MW FACILITY IS
BEING JUSTIFIED BASED ON THE COMPANY'S 2004 IRP RATHER THAN
CURRENT INFORMATION. COULD YOU EXPLAIN YOUR CONCERNS
FURTHER?
It is not prudent for a utility to base expensive resource decisions on outdated
information. Although one can always second guess a decision with the benefit of
hindsight, basing a current decision on outdated and inaccurate data is a different
situation-one that can and should be avoided.
In its decision approving the Danskin unit (currently on the site of the plant
proposed in this case), the Commission stated
The Commission fmds that Idaho Power is entitled to include Danskin
plant costs in rate base. The extraordinary conditions that existed at the
time Danskin was developed warranted a rapid response by the Company
and justify the investment in a peaking facility that by design is more
costly to operate than other types of facilities.
(IPUC Order No. 29505, IPC-03-, p. 18) (emphasis added). Unlike the Danskin
project, however, which was conceived and constructed in the middle of the California
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energy debacle, the situation for the proposed Evander Andrews project differs because
the Company is not facing an energy crisis like the one that was occurring when the
certificate for Danskin was issued. In the case of Evander Andrews, the Commission and
Idaho Power have the ability to make a deliberative and thoughtful resource decision
based on current, accurate information, before Idaho Power begins construction of the
project. In this instance, the requested Certificate should be denied based on an analysis
of current information. The Commission s determinations should not be based on the
conditions that existed in the 2004 IRP, or even those that existed at the time Idaho
Power issued its Request for Proposals for a peaking resource.
Basing a Certificate determination on current information only makes good sense
and seems to be the standard backed by the Idaho Supreme Court, that stated in
Cambridge Telephone Co. v. Pine Telephone (t)he concept of 'public convenience and
necessity' should be considered in light of current and changing circumstances." 1 09
Idaho 875, 879 (1985).
CAN YOU GIVE AN EXAMPLE OF HOW RELEVANT INFORMATION
HAS CHANGED BETWEEN THE TIME OF THE 2004 IRP AND THE 2006 IRP?
Yes. As an example, the forecast for natural gas prices in 2006 was projected to
be $4.89 per therm in the 2004 IRP, but the 2006 IRP shows that they are now more than
65% higher at $8.23 per thermo Additionally, as compared to the assumptions in the 2004
IRP, the Company now expects natural gas prices to be more than $1.00 per therm higher
over the next 29 years. Graph 1 below depicts this. Natural gas prices are now expected
to be especially high in the near term.
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$11.
Graph 1
IPCo IRP Natural Gas Price Forecast
$10.
.-----------.---------..---- ----
$9.
-.------.- -------------
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-- -- - -----
____n_~--
--_.__._-------_._--_.
$8.00 -
$6.
$5.kOO
~20041PR -4- 2006 IRP
I created this graph using the 2004 IRP and the Draft 2006 IRP.
YOU STATE THAT NATURAL GAS PRICES HAVE CHANGED
SUBSTANTIALLY SINCE THE 2004 IRP. DIDN'T IDAHO POWER UPDATE
THOSE NUMBERS IN ITS EVALUATION OF WHETHER THE EV ANDER
ANDREWS PROJECT WAS AN APPROPRIATE RESOURCE TO BUILD?
, it did not. In direct testimony, Mr. Said states even though natural gas prices
have risen substantially since the 2004 IRP, all the units bid in response to the Request
For Proposals ("RFP") for a peaking resource were evaluated with the same gas price-a
price known to be significantly outdated and inaccurate. Mr. Said states
Forecasted natural gas prices from the 2004 IRP were used in the bid
evaluation. Forecasted natural gas prices have gone up substantially since
the issuance of the 2004 IRP, but the same price forecast was utilized in
the evaluation of all of the natural gas- fired project proposals and, as a
result, projects with lower guaranteed heat rates had lower fuel costs on a
dollar per megawatt basis.
(Said Direct, p. 15).
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The ICIP followed up with a Request for Production, asking "At any time during
its evaluation of the various responses to Idaho Power s RFP, did Idaho Power use an
updated forecast of natural gas prices?" Idaho Power responded
Idaho Power did not use, nor was it necessary to use, an updated forecast
of natural gas prices to evaluate the responses to the RFP. In bid
evaluations, it is only necessary that the same gas price forecast be used to
calculate estimated variable operating costs for all of the bids to allow for
a consistent cost comparison among the bids.
(Exhibit No. 203, Idaho Power s Response to Request for Production No. 23 ofICIP)
(emphasis in original).
IF ALL OF THE BIDS WERE EVALUATED USING THE SAME GAS
FORECAST, AREN'T YOUR CONCERNS ABOUT RELYING ON OUTDATED
INFORMATION ALLEVIATED?
No. Although using the same gas forecast (even if outdated) may have allowed
the Company to determine which natural gas plant bid in response to the RFP was the
least cost, Idaho Power s use of a significantly outdated gas price forecast prevented them
from considering the fundamental question that must be answered before seeking a
Certificate to build the gas-fired plant. That question is: given the known "substantial"
increase in natural gas prices, is this gas-fired resource the best resource choice?
As I discuss in my testimony, there are viable alternatives to gas fired
generation, such as combined heat and power, also known as cogeneration or CHP
increased Demand-Side Management ("DSM") activity, and other proven methods for
decreasing or meeting peak demand. The approach used by Idaho Power to determine
that it should build the Evander Andrews plant-relying on an outdated IRP, and on stale
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gas price information known to be inaccurate-simply short-circuited a meaningful
inquiry into whether the plant is the best resource option given the significant changes
over the past few years and current proj ections into the future.
ASIDE FROM SIGNIFICANTLY IDGHER NATURAL GAS PRICES,
WHAT OTHER EVIDENCE SUPPORTS YOUR CONTENTION THAT
CURRENT INFORMATION UNDERMINES THE PURPORTED NEED FOR A
170 MW NATURAL GAS FIRED TURBINE?
The "preferred portfolio" in Idaho Power s own 2006 IRP does not call for any
gas-fired combustion turbines like the Evander Andrews plant. In fact, of the four
resource portfolios examined in the 2006 IRP, only one contained a natural gas-fired
resource (other than CHP).
In its 2006 IRP, the Company explains how current and forecasted natural gas
prices have affected the Company s decisions regarding future use of natural gas-fired
combustion turbines. The Company states that "(g)iven current and forecasted natural
gas prices, purchasing energy from the regional markets, up to the limits of the
transmission system, will most likely be more economical than operating the (natural gas)
combustion turbines as an energy resource." (Exhibit No. 204, Idaho Power Final 2006
IRP, p. 98). Additionally, the Company explains that it expects to operate combustion
turbines only when customer load exceeds the generation capacity of its other generation
units and the import capacity of the transmission system. (Exhibit No. 204, Idaho Power
Final 2006 IRP
, p.
98).
Thus, according to Idaho Power, it is expected to be less expensive to purchase
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power on the market than to incur the variable running costs of gas fired power. This
would mean that the proposed plant in this case would not be run for off-system sales
and the plant would be run only when transmission constraints prevent the importation of
power. The results of the Company s model runs which show the plant producing only
331 MWh over the next 25 years (discussed later in my testimony) also support the
conclusion that Idaho Power would use the Evander Andrews plant very little.
YOU STATE THAT THE 2006 IRP DOES NOT SUPPORT THE
CONSTRUCTION OF THE EV ANDER ANDREWS PLANT. BUT, DOESN'
THE 2006 IRP ASSUME THE EV ANDER ANDREWS PLANT IS ALREADY
PART OF IDAHO POWER'S RESOURCE MIX?
Yes. For that reason, the 2006 IRP does not provide any evaluation by Idaho
Power of whether the Evander Andrews plant is a good resource choice at this time.
GIVEN THAT THE 2006 IRP SIMPLY ASSUMES THE EVANDER
ANDREWS PLANT IS BUILT, IS THERE ANY WAY THE 2006 IRP, OR THE
INFORMATION SUPPORTING IT, CAN BE USED TO DETERMINE
WHETHER EV ANDER ANDREWS IS A GOOD RESOURCE CHOICE BASED
ON CURRENT INFORMATION?
Yes. The 2006 IRP information helps shed light on the usefulness and value of
the Evander Andrews plant in a couple of ways. Although Idaho Power did not
undertake the task of using the 2006 IRP information to evaluate the Evander Andrews
project, I have been able to do that to some extent using the information gathered in this
proceeding.
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The Commission Staff asked the Company for load-resource balance data by
month for each of the years 2006-2026, both with and without the Evander Andrews
plant using the data from the 2006 IRP. (Exhibit No. 206, Commission Staff 4th
Production Request, No.96). Commission Staff stated because "2006 IRP load-resource
balance data has been in use by the Company for several months during the preparation
of the 2006 IRP . . . Staff assumed it could also be used to re-examine the need for the
Evander Andrews plant." The Company did not undertake a model run to determine the
results requested by Staff. Instead, in its response the Company simply stated its guess
that, if 2006 IRP data were used and the Evander Andrews plant were considered an
option, rather than an assumed resource, a peaking resource like the Evander Andrews
plant "would have most likely been included" in the 2006 IRP's preferred portfolio.
(Exhibit No. 207, Idaho Power Response to Staff 4th Production Request, No. 95)
(emphasis added). This statement speaks nothing of the size of such resource, or how
that determination was made.
Another way that the 2006 IRP data can be used to determine whether the
Evander Andrews plant is a good resource decision at this time is to use it to estimate
how often the resource is expected to run. Idaho Power did provide some information on
this topic at the request of Commission Staff, which demonstrated the plant is forecast to
be used only rarely, and only in the near-term.
In its Request for Production No. 26, Commission Staff asked Idaho Power to
provide estimates by month for the period from June 2007 to December 2027 ofthe
number of hours the Evander Andrews plant will be expected to operate. The Company
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answered generally that the number of hours the plant will be expected to operate will
depend on a variety of factors. (See Exhibit No. 208, Response to Commission Staffs
Request for Production No. 26).
Staff then asked a follow-up question, explaining that it was seeking an estimate
of the actual hours the Company estimated Evander Andrews would run, as predicted by
the AURORA simulation model, using the resource portfolio selected in the 2006 IRP.
(Exhibit No. 209, Commission Staff's Second Production Request at No.1 00). The
Company responded with an AURORA run under average water conditions, average load
conditions, and 90th percentile peak-hour loads. The results of that model run showed the
Evander Andrews plant producing only 60 331 MWh over the next 25 years (See Exhibit
209). Of the total projected production over the next 25 years, 93% or 56 300 MWh is
expected to occur in the three years between 2008 and 2010. Further, the results showed
that the Evander Andrews plant is expected to produce zero MWh under average water
conditions for any year after 2015.
The Company attempted to explain this surprising result by stating,
Under more severe conditions for the Idaho South "bubble" and the
remainder of the WECC zones, such as 90th percentile water and 95th
percentile peak-hour loads, the CTs are expected to dispatch more
frequently.
Thus, based on the Company s best estimate, it appears that the plant may only be
used to generate an amount of energy equal to 355 hours of running at full capacity under
average water conditions. Almost all of that would occur between 2008 and 2010, with
the plant sitting idle after 2015. Although the Company states that it would expect the
plant to be dispatched "more frequently" in more severe conditions, that is the extent of
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the Company s analysis.
U sing the $60 million commitment estimate for construction of the plant would
mean a cost of $995 per MWh under average water conditions. This does not include the
$22.8 million of estimated transmission costs required for the project, which push the
cost on a per MWh basis to over $1 350. Additionally, I would point out that the
Company expects the highest usage of the plant to be over the first few years after
construction, the time period over which natural gas prices are expected to remain
relatively high.
WHAT ELSE DOES THE 2006 DRAFT IRP SAY ABOUT SIMPLE
CYCLE COMBUSTION TURBINES, SUCH AS THE EV ANDER ANDREWS
PROJECT?
The Draft 2006 IRP, provided to ICIP in this proceeding states that
(F)easible sites and gas supply currently exist for future (Simple-Cycle
Combustion Turbine) development. However, the forecasted trend of high
natural gas prices has reduced interest in future SSCT generation plants.
(Exhibit No. 205, Draft 2006 IRP, p. 46). This statement was in the August 1 2006 Draft
of the 2006 IRP but was deleted from the final version, which I find unusual.
WHY DO YOU FIND IT UNUSUAL FOR THAT PARTICULAR
STATEMENT TO BE EDITED OUT OF THE FINAL 2006 IRP?
Because it an accurate description of the reason for waning interest in SSCT's in
the industry. The statement indicates how conditions have changed since the Company
issued their 2004 IRP, which is being used to justify the proposed project in this docket.
It is a bit self-serving for Idaho Power s final IRP to eliminate talk of "reduced interest"
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in the very type of technology it is attempting to get this Commission to sanction in the
form of a Certificate for Public Convenience and Necessity.
GIVEN IDAHO POWER'S STATEMENT THAT RUNNING EV ANDER
ANDREWS WOULD ONLY BE ECONOMICAL WHEN TRANSMISSION
IMPORT IS IMPOSSffiLE, DOES THE 2006 IRP CALL FOR ADDITIONAL
TRANSMISSION UPGRADES TO ALLEVIATE THE LIMITATIONS ON
SERVING PEAK DEMAND ECONOMICALLY?
Yes. The 2006 IRP shows that Idaho Power is planning significant transmission
upgrades. It states that "(t)he 2006 IRP includes 285 MW of transmission upgrades
significantly improving Idaho Power s ability to import power." (Exhibit No. 204, Idaho
Power 2006 IRP, p. 98). In general, the 2006 IRP seems to recognize that building
natural gas plants is not a preferred approach to meeting future peak demand, and that
transmission upgrades may be a more sensible course of action in comparison.
ASIDE FROM UTILIZING EXISTING OR NEW IMPORT
CAPABILITIES, ARE THERE OTHER WAYS IN wmCH IDAHO POWER
COULD MEET ITS PEAK DEMAND WITHOUT CONSTRUCTING THE
EV ANDER ANDREWS PLANT?
Yes. Idaho Power s claim of a need for the Evander Andrews plant does not
appear to be based on an accurate and comprehensive look at the resources that are, or
will be available to Idaho Power, or the loads that Idaho Power will be serving..
comprehensive evaluation shows that the plant is not required at this time.
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PLEASE EXPLAIN WHAT OTHER RESOURCES ARE AVAILABLE TO
IDAHO POWER FOR MEETING ITS PEAK DEMAND.
There are several resources that Idaho Power has overlooked: 1) Idaho Power has
not taken advantage of significant combined heat and power (CHP) projects that would
obviate any need for Evander Andrews, 2) Idaho Power has overlooked proven methods
for utilizing diversified generation to meet peak demands, 3) Idaho Power has not
effectively utilized Demand-Side Management (DSM) resources and has failed to
account for future DSM savings, 4) Idaho Power has not accounted for the amount of
power that will be available to it through Small Power Producer and PURP A purchases
and 5) Idaho Power has failed to look into the costs of alternatives that it has
acknowledged it would turn to if the Certificate for the Evander Andrews plant were
denied.
* * * * *
CONFIDENTIAL INFORMATION FOLLOWS
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As stated earlier, given that Idaho Power projects the Evander Andrews plant to
run very little, the costs on a per MWh basis of the Evander Andrews plant could be as
much as $1 350.
ISN'T THE HIGH PRICE OF THE EV ANDER ANDREWS PROJECT ON
A PER MWh BASIS SIMPLY DUE TO THE FACT THAT IT WILL NOT RUN
VERY MANY HOURS AS A PEAKER PLANT?
That is characteristic of a peaker plant. However, the important question here is
at what cost will the Evander Andrews plant serve Idaho Power s customers during those
peak hours, and what cheaper alternatives may exist for serving load. As outlined in this
testimony, I believe there are many alternatives that Idaho Power could turn to. Many of
those could meet the limited role that the Evander Andrews plant would serve, at a lower
cost, or at a currently unknown cost, since Idaho Power appears to not have sufficiently
analyzed them.
* * * * *
CONFIDENTIAL INFORMATION FOLLOWS
* * * * *
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IN ADDITION TO DISCUSSING CHP AS A SUBSTITUTE FOR THE
EV ANDER ANDREWS PLANT, YOU STATED EARLIER THAT IDAHO
POWER HAS OVERLOOKED OTHER PROVEN METHODS FOR UTILIZING
DIVERSIFIED GENERATION TO MEET PEAK DEMANDS. PLEASE
EXPLAIN.
Another proven method for utilizing diversified generation (generation installed
throughout a utility's service territory) to meet peak demands is through contracting with
commercial and industrial facility owners to make use of their backup generation
facilities. There appears to be a wealth of untapped peaking capacity in Idaho Power
service territory.
ON WHAT DO YOU BASE THAT ASSERTION?
A report by the Northwest Power Planning Council (Feasibility of Emergency
Electrical Generation Units to Serve System Load Requirements Northwest Power
Planning Council, (August 17 2001)) found:
(E)mergency generators are available in a variety of commercial and
industrial buildings as well as hospitals, high schools, colleges, jails, and
public safety facilities. According to industry information Washington
Oregon, Idaho, and Montana have just over 26 000 generators within their
borders.
(Exhibit No. 218, Feasibility of Electrical Generation Units to Serve System Load
Requirements, p. 1). The report shows the State ofIdaho has 1 438 generators ranging
from 50 kW to over 2 MW, with 27 generators having a capacity of at least 2 MW.
(Exhibit No. 218, Feasibility of Electrical Generation Units to Serve System Load
Requirements, p. 9, Table 1). This peaking capacity could be tapped by Idaho Power to
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meet its system peak load.
HOW CAN YOU BE SO SURE THAT TIDS PEAKING RESOURCE IS
AVAILABLE TO IDAHO POWER FOR ITS USE?
Because other Northwest utilities are currently running successful programs that
do just that right now. For example Portland General Electric (PGE) has established a
Dispatchable Standby Generation (DSG) program, though which it has acquired a
significant "virtual peaking plant" at a very low cost. In exchange for the ability to
dispatch a standby generator for up to 400 hours per year, PGE offers support and
maintenance services to the customer, and installs all necessary switching to allow the
generator to instantaneously put power onto the grid. The system operates in parallel
with PGE's system so there is no service interruption. Additionally, if the building owner
requires the emergency backup generator for backup purposes, the switching
automatically makes that happen without interruption.
Under its DSG program, PGE will:
Upgrade switchgear and install control and
communications hardware at no charge to the customer;
Assume all maintenance and operation costs, including fuel
costs, costs of repairs, and overhauls
Provide additional sound attenuation, if needed, to quiet the
generator system
Provide additional fuel storage, if needed
Test the generator at least once a month under full load (a
benefit for the engine)
Provide fmancing if a customer is purchasing a new
generator or upgrading its system
(Exhibit No. 219 Dispatchable Standby Generation).
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IT SEEMS LIKE A VERY SIMPLE SOLUTION TO PEAKING
PROBLEMS AT LOAD CENTERS, CAN SUCH AN EASY SOLUTION REALLY
WORK?
Yes. For example, on July 24 2006, PGE successfully dispatched 25.5 MW
under its DSG program to meet its peak demand. (Exhibit No. 220 Standby generation
picks up extra load during heat wave). PGE will have a total of 45 MW available under
its DSG program by the end of 2007, and estimates that it may be able to develop as
much as 100 MW. (Exhibit No. 221 , Portland General Electric 2002 Integrated Resource
Plan Final Action Update, p. 7 (March 23 , 2006)).
In describing its DSG program, PGE has stated
We have found that customer enthusiasm and adoption rates for this
program have been higher than we originally anticipated. The high levels
of customer interest and participation have allowed PGE to establish one
of the most successful customer-based capacity programs of its kind. This
option, because of its distributed nature, also provides reliability benefits
for PGE and the host customers. DSG is a high quality. cost-effective
capacity resource that also serves as reserve capacity.. . . Since we have
received inquiries and further interest from customers beyond our current
implementation, we believe that the DSG program could potentially be
expanded to help meet more ofPGE's future capacity needs.
(Exhibit No. 221 , Portland General Electric 2002 Integrated Resource Plan Final Action
Update, p. 7 (March 23 , 2006) (emphasis provided)).
WHAT ABOUT AIR QUALITY CONCERNS?
Addressing questions about air quality concerns, PGE has found that the limited
number of hours that each plant can be operated "does not impair the effectiveness of
DSG as a capacity option " since it is used only during peak events. (Exhibit No. 221
Portland General Electric 2002 Integrated Resource Plan Final Action Update, p. 7
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(March 23 2006)).
IS TIDS AN EXPENSIVE ALTERNATIVE?
No. It is cheaper than Evandar Andrews, the other CHP discussed ealier in my
testimony or even the generic CHP identified in Idaho Power s IRP. Significantly,
documents presented to the Oregon Public Utility Commission by PGE regarding the
program list an estimated cost of the capacity acquired under the program at about
$23/KW-yr. (Exhibit No. 222, PowerPoint Presentation Stakeholder Dialogue No.
PGE's 2006 Integrated Resource Plan p. 46 (July 25 2006)). This is approximately half
of the costs PGE estimates Single-Cycle Combustion Turbine capacity would cost.
(Exhibit No. 222, PowerPoint Presentation Stakeholder Dialogue No., PGE's 2006
Integrated Resource Plan p. 46 (July 25 2006)).
HAS IDAHO POWER EXPLORED TIDS OPTION?
, it has not.
DID YOU ASK THE COMPANY SPECIFICALLY ABOUT THE USE OF
EMERGENCY BACKUP GENERATORS TO MEET ITS PEAK?
Yes, we did. The ICIP asked specifically whether Idaho Power made any efforts
to look into the use of emergency generators to meet or reduce peak load. (See Exhibit
No. 223, Response to Request for Production No. 46 ofICIP). Idaho Power s response
simply describes its buy back program that was implemented in response to the
2000/2001 energy crisis. Idaho Power called the program their "Energy Exchange
program under which customers were paid one half of the wholesale market price in
exchange for their reducing their load by a minimum of 1 000 kw. Idaho Power
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discontinued the program shortly after it started because wholesale prices were too low to
motivate customer participation. The Energy Exchange program is very different from
the "virtual peaking" program implemented by PGE. Given the high cost of peaking
power the Company is asking for in this Docket, a program similar to PGE's DSG
program makes more sense than constructing the Evander Andrews plant. It is also
compelling evidence that Evander Andrews may not be in the public convenience and
necessity. An investigation into the size of the potential peaking resources will have to be
conducted prior to committing the ratepayers to paying for the Evander Andrews plant.
IS IT REASONABLE TO PUT TIDS CASE ON HOLD PENDING THE
RESULTS OF SUCH AN INVESTIGATION?
Yes.
WHAT IF IDAHO POWER INCURRS ADDITIONAL COSTS CAUSED
BY SUCH A DELAY?
The shareholders should absorb any such additional costs.
WHY SHOULD THE SHAREHOLDERS ABSORB SUCH COSTS?
Because the idea of using diversified backup generation is not new to Idaho
Power. I was a witness for ICIP in the Company s general rate case in Oregon. (U-167).
I presented testimony recommending the use of emergency generators to obviate the
need for new gas-fIred peaking plants in that proceeding. In that case Idaho Power
expressed a willingness to investigate the potential of this approach to help in meeting its
peak load concerns. In its Order in that case the Oregon Commission stated
Idaho Power voluntarily committed to exploring distributed generation
opportunities with Holy Rosary Medical Center and any other Oregon
Reading (Di) - ICIP
IPC- E-06-
customer with such potential, without direction by the Commission. See
IP/600, Galel3. Staff agrees with OICIP that dispatchable standby
generation could be an important asset to meet peak load demands. See
Staff brief, 19 (June 13 2005).
(Oregon Public Commission Order 05-871 , July 28 2005 , p. 15).
The Oregon Commission did not direct Idaho Power to conduct such an
investigation because Idaho Power "voluntarily" agreed to explore the possibility of the
use of distributed generation opportunities. The evidence gathered in this case shows that
Idaho Power has taken no steps to pursue this resource since that time. (See Exhibit No.
223, Response to Request for Production No. 46 ofICIP). Idaho Power s failure to
investigate the availability of this resource, coupled with the success other utilities are
experience in mining this resource for meeting peak is additional evidence of the
imprudence of constructing the Evander facility at this time.
YOU STATED EARLIER THAT IDAHO POWER HAS FAILED TO
EFFECTIVELY UTILIZE DEMAND-SIDE MANAGEMENT (DSM)
RESOURCES AND HAS FAILED TO ACCOUNT FOR FUTURE DSM
SAVINGS. IS THERE ANY REASON TO BELIEVE THAT IDAHO POWER
COULD IMPLEMENT, OR COULD HAVE IMPLEMENTED MORE DSM OR
CONSERVATION THAN IT HAS?
Yes. Idaho Power could have implemented more conservation and other DSM
than it has in recent years, and it is very likely that Idaho Power could do more in the
future to use DSM and conservation to meet its peak demand, and at least partially
obviate any need for the Evander Andrews power plant.
Reading (Di) - ICIP
IPC-06-
WHY DO YOU ST ATE THAT IDAHO POWER COULD HAVE
IMPLEMENTED CONSIDERABLY MORE DSM AND CONSERVATION THAN
IT HAS IN RECENT YEARS?
Between 1995 and 2001 , Idaho Power slashed its spending on DSM programs.
Even though its normalized system loads between 1995 and 2000 grew from 14.7 million
MWh to 15.8 million MWh, Idaho Power s total spending on DSM programs dropped
from $6.2 million to $1.6 million. (See Exhibit No. 224, Idaho Power s Response to
Request for Production Nos. 1 and 4 of Northwest Energy Coalition in Case No. IPC-
06-08). This means that over those five years, Idaho Power cut its spending on
conservation and DSM by almost 75 %, while its loads grew by over 8 %. Only recently
has Idaho Power s spending on DSM efforts come back within the range of its pre-1995
spending levels. And, it has taken Idaho Power the last several years to get up to those
levels, with 2004 spending still being only $3.7 million.
IS SPENDING THE BEST INDICATOR OF DSM AND CONSERVATION
THAT THE COMPANY IS ACIDEVING?
It may not be the best indicator, but it certainly shows the Company made a
deliberate and dramatic decrease in its conservation and DSM efforts for many of the past
several years. Other indicators also show that Idaho Power s DSM and conservation
achievements have been relatively poor.
WHAT ARE SOME OF THE OTHER INDICATORS THAT IDAHO
POWER'S DSM AND CONSERVATION EFFORTS HAVE BEEN RELA TIVEL Y
POOR?
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IPC-06-
Idaho Power s annual energy savings as a result of its DSM programs are quite
modest. Idaho Power s savings in 2004 and 2005 were only 3.26 MWa and 4.71 MWa
respectively. From available information, Idaho Power s annual energy savings from
DSM programs between 2000 and 2004 have been less than 1 MWa, and essentially zero
for a couple of those years. (See Exhibit No. 225 , Idaho Power s Response to Request
for Production No.8 of Northwest Energy Coalition in Case No. IPC-06-08).
Additionally, a comparison ofIdaho Power s historical conservation
achievements to the achievements of other regional investor-owned and publicly-owned
utilities shows that, of the surveyed utilities, Idaho Power has the lowest conservation
savings as a percentage of its load. Idaho Power s achievements are half ofPacifiCorp
and less than one third of Avista's. (See Exhibit No. 226 Generation Options for Idaho
Energy Plan presented to Idaho Legislature s Subcommittee on Generation Resources
August 10 2006, p. 33).
Historical Conservation Achievements as a Share of 2003 Load
25%
----_...--.-._---_.--.~--
20%
.. --.--. ------- ----. --.-- -
15%
.. ---------.-----
10%
4P o 'i-
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Reading (Di) - ICIP
IPC-06-
Finally, out of the three Idaho jurisdictional utilities, Idaho Power is the only one
that has planned conservation investments considerably below the Northwest Power and
Conservation Council's targets for 2015. Idaho Power s planned conservation
investment is approximately one-third of the Council's goal. (See Exhibit No. 226
Generation Options for Idaho s Energy Plan Presented to Idaho Legislature
Subcommittee on Generation Resources, August 10 2006, p. 34).
Planned Conservation Investments vs.
Power Council Target, 2015
140
120
100
3':
C!:I
Idaho Power PacifiCorp
Planned Conservation Investment
- Power Council Target
;:t*:v.o;~;;'
Avista
ON A GOING-FORWARD BASIS, DO YOU BELIEVE IDAHO POWER
COULD DO MORE CONSERVATION, SUCH THAT SOME OF THE NEED
FOR A PEAKER PLANT COULD BE REDUCED?
I understand that Idaho Power is planning to significantly increase its spending on
conservation and other DSM programs. In the 2006 IRP, for example, Idaho Power
states that it plans to add "several new programs as well as expanding existing
programs." (Exhibit No. 204, Idaho Power 2006 IRP at p. 97). Overall, it plans to add a
set ofDSM programs that are expected to reduce loads by approximately 90 aMW and
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IPC- E-06-
reduce the system peak-hour load by approximately 187 MW during the summertime.
(Exhibit No. 204, Idaho Power 2006 IRP at p. 2).
This focus on reducing Idaho Power s peak demand, therefore, should alleviate to
some extent the need for the Evander Andrews power plant. Because the 2006 Draft IRP
simply assumes that the Evander Andrews plant will be built, however, Idaho Power
analysis in the 2006 IRP is unhelpful in determining whether this increase in DSM efforts
obviates the need for the Evander Andrews plant at this time. However, given the
surprisingly few number of hours the Evander Plant will operate under the assumptions
contained in the 2006 IRP, the need for the plant may be obviated, possibly due to a
variety of factors, including increased DSM savings.
According to Idaho Power s own study, Idaho Power may be underestimating
the amount of peak demand savings through DSM that are available to it. In late 2004
Quantum Consulting completed a study for Idaho Power in which it set out the resources
available to Idaho Power through DSM efforts. That study concluded that there was a
potential for 384 MW of economic peak demand reduction by 2013 to Idaho Power
through DSM programs. (Exhibit No. 227, Idaho Power Demand-Side Management
Potential Study, p. 4-1).
DO YOU REALLY TIDNK THAT DSM MAY OBVIATE THE NEED TO
CONSTRUCT THE EV ANDER ANDREWS POWER PLANT?
Yes, but not just DSM. I would like to make three points about Idaho Power
DSM programs and the need for the Evander Andrews plant: 1) for the reasons stated
above, I believe it is likely that future DSM efforts could substantially lessen any need for
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IPC-06-
a peaking plant such as the Evander Andrews plant, 2) Idaho Power s failing to
implement reasonable amounts of DSM and conservation in the past several years has
exacerbated any need Idaho Power may have for a peaking resource such as Evander
Andrews at this time, and 3) it would be fundamentally unfair to require customers to pay
for the total costs of a plant such as Evander Andrews when a lack of commitment to
DSM on Idaho Power s part in recent years may be a substantial reason for its
construction.
Also, I would point out that utilities, in general, seem to be finding increasingly
innovative ways to meet or reduce their peak demand. For example, on July 24th of this
year when record peaks were set, not only on Idaho Power s system, but all throughout
the region, several utilities took creative measures to reduce and meet their peak demand.
A vista, for example, reached out to its customers through personal contact and the media
and requested voluntary conservation, resulting in an approximately 30 MW reduction in
its peak demand. (See Exhibit No. 228, Avista Quarterly Review, August 2006). Also on
July 24 , Snohomish Public Utility District, set a record peak load of 845 MW, but
through placing calls to select large customers it achieved a 10 MW reduction in peak
demand (approximately 1.2 percent of its peak load) from reduced loads and self-
generation by customers. (See Exhibit No. 242
, "
Peak Load Condition, Monday, July 24
2006, Commission meeting August 1 2006 " p. 7). As discussed above, Portland
General Electric, also on July 24 , dispatched 25.5 MW through its Dispatchable Standby
Generation program in order to meet its peak demand.
Especially under the circumstances I describe in this testimony, allowing Idaho
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IPC-06-
Power to construct a 170 MW gas-fired peaking unit will discourage Idaho Power from
making these, and similar, types of efforts, and could result in customers needlessly
paying for Idaho Power s reluctance to do so.
PLEASE EXPLAIN YOUR EARLIER STATEMENT THAT IDAHO
POWER HAS FAILED TO ACCOUNT FOR THE POWER THAT WILL BE
AVAILABLE TO IT THROUGH CSPP AND PURP A PURCHASES.
In its generation resource forecasts, Idaho Power only includes the estimated
output from projects with signed and IPUC-approved agreements. Idaho Power does this
because it claims it has no control over the development or operation of these projects
and that the online times vary from estimated online dates. (See Exhibit No. 229
Response to ICIP Request No. 38).
This is problematic, however, because for purposes of its claim that the Evander
Andrews peaking plant is necessary, Idaho Power is assuming essentially no increase in
power available from CSPP and PURPA projects, even though it is almost certain that
significant increases will in fact be realized. Idaho Power s current internal CSPP
forecast shows a potential increase of approximately 60 MW of CSPP power on an
annual average basis in 2008, but it is unclear whether this potential increase was
considered by Idaho Power in determining that it needed the Evander Andrews plant.
(See Exhibit No. 230, Response to ICIP Request No. 37, 38).
III
III
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IPC- E-06-
PLEASE EXPLAIN WHAT YOU MEANT BY YOUR STATEMENT THAT
IDAHO POWER HAS FAILED TO LOOK INTO THE COSTS OF
ALTERNATIVES THAT IT HAS ACKNOWLEDGED IT WOULD TURN TO IF
THE CERTIFICATE FOR THE EV ANDER ANDREWS PLANT WAS DENIED.
In its Request for Production No. 18, the ICIP asked the Company how it would
expect to meet loads if the Commission denied its request for a certificate for the Evander
Andrews plant. The Company responded
If the Commission denies Idaho Power s request for a certificate of public
convenience and necessity, Idaho Power would most likely consider
several alternatives to meet peak-hour loads during the summer of 2008.
These alternatives include: (1) additional firm market purchases and the
associated transmission necessary to deliver the energy to the east side of
Idaho Power s system , (2) transmission system expansions to increase
import capacity, (3) expansion of the Irrigation Peak Rewards program
(which is already being investigated), (4) developing advertising messages
that ask consumers to reduce their peak-hour consumption , and (5)
utilizing diesel or other temporary gensets.
(Exhibit No. 231 , Response to ICIP Request No. 18).
When ICIP followed up by asking what cost estimates the Company has prepared
for implementing these alternatives, Idaho Power stated that it had not performed a
detailed analysis. (Exhibit No. 232, Response to Request for Production ofICIP No. 40).
It did, however, provide preliminary estimates for the fIrst three alternatives, which seem
to show that some of those alternatives could be substantially less expensive than the
Evander Andrews plant.
For example, Idaho Power indicated that a premium of $16 to $17 per MWh for
additional east side purchases might apply if alternative 1 was used (additional firm
purchases to deliver to Idaho Power s east side). Given the number of hours the Evander
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IPC-06-
Andrews project is expected to run, however, this equates to only a little over a million
dollars, in addition to the non-premium costs to import power. Given its statements in
the 2006 IRP that import is cheaper than running natural-gas combustion turbines, this
option may in total be considerably cheaper in total.
Additionally, Idaho Power states that alternative 2 (transmission upgrades)
range in cost from $10.8 million to $282 million. (Exhibit No. 232, Response to Request
for Production ofICIP No. 40). If some of these upgrades are planned to occur anyway,
they may prove more cost effective than constructing the Evander Andrews plant in
getting the power the Company needs to serve customers. Finally, alternative 3
(expansion of the Irrigation Peak Rewards program), which is already being planned, is
estimated to yield an additional 4.5 MW ofload reduction during the summer peak, for
an estimated cost of $300 000.
IF THERE ARE OTHER LESS-COST ALTERNATIVES FOR MEETING
IDAHO POWER'S PEAK DEMAND, COMPARED TO EV ANDER ANDREWS,
WHY DIDN'T IDAHO POWER'S REQUEST FOR PROPOSALS (RFP)
PROCESS LEAD TO THOSE AL TERNA TIVES BEING IDENTIFIED AND
SELECTED?
Idaho Power s RFP process was not designed to determine the best resource for
meeting its peak load requirements. It sought, by its terms "peaking electric generating
resources on a turnkey basis." (Exhibit No. 233, Idaho Power Request for Proposals
, p.
1). Thus, DSM, diversified generation, and smaller CHP projects were not able to be bid
in response. Additionally, the RFP limited considered projects to those "where legal title
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IPC- E-06-
of the generating facilities" would be conveyed to Idaho Power. (Exhibit No. 233 , Idaho
Power Request for Proposals, p. 1). Finally, the RFP encouraged bidders to locate their
proposed plants at the existing Evander Andrews Power Complex, or the Bennett
Mountain Power Plant location. Given the narrowly-tailored RFP, it naturally lead to
only consideration of natural-gas fired combustion turbines.
PUTTING ASIDE THE APPARENT AVAILABILITY OF OTHER
RESOURCES TO MEET ITS PEAK DEMAND, IS THERE ANY REASON TO
BELIEVE THAT IDAHO POWER'S FUTURE PEAK LOAD MAY BE LESS
THAN THE LEVEL THAT IT CLAIMS JUSTIFIES THE EV ANDER ANDREWS
PLANT?
Yes. In May of2006, a significant increase in Idaho s Conservation Reserve
Enhancement Program (CREP) was announced. Through this program, farmlands will be
set aside, and irrigation pumps turned off. In a recent forecast ofIdaho Power s loads
Idaho Power has incorporated an annual energy reduction over the next 15 years (2007
through 2021) of approximately 4% because ofCREP. (Exhibit No. 234, Response to
ICIP Request for Production No. 41). Because a significant part ofIdaho Power s peak
load is caused by irrigation pumpers, this is a large decrease in Idaho Power s peak
demand over prior forecasts. Idaho Power has clarified in this proceeding, however, that
(fjor planning purposes, Idaho Power has not incorporated any specific assumptions in
the 2006 IRP regarding the. . . CREP." (Exhibit No. 234, Response to ICIP Request for
Production No. 41). Additionally, it has stated that "(t)he CREP announcement had no
effect on the Company s decision regarding the 2005 RFP or the Evander Andrews
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IPC- E-06-
plant." (Exhibit No. 234, Response to ICIP Request for Production No. 41).
WHAT IS YOUR RECOMMENDATION AS TO WHETHER IDAHO
POWER SHOULD PURSUE CONSTRUCTION OF THE EV ANDER ANDREWS
PLANT AT THIS TIME?
Idaho Power should not proceed with construction of the plant at this time. There
simply seems to be too much uncertainty and too many troubling facts regarding the
proposed plant, and Idaho Power should re-assess its needs, and look to other available
options, which may well save significant costs to its ratepayers.
Terminating or postponing construction of the Evander Andrews plant entails
little risk. One advantage of single-cycle natural gas peakers is a short construction time.
Therefore, not going forward with this plant at this time would not jeopardize the long
run power supply for the Company, even without the various alternatives and
considerations I have laid out in my testimony. In addition, Idaho Power owns the site of
the proposed Evander Andrews project, and can therefore retain the site for future
constructi on.
ARE THERE OTHER REASONS FOR wmCH YOU TIDNK THE
COMMISSION SHOULD DENY THE CERTIFICATE?
I believe the Commission should also consider the potential that the Evander
Andrews plant has to reduce any incentive for Idaho Power to achieve cost-effective
DSM and conservation, and to prevent Idaho Power from utilizing other resources, which
may be superior, to meet its peak demand for the foreseeable future.
For example, the Company s incentives to achieve peak-shaving programs will
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IPC-06-
likely be significantly reduced if the Company has a new 170 MW peaker plant to rely on
to meet peak loads, even though it only claims to have needed an 88 MW plant in its
2004 IRP.
Additionally, it appears that the fact that the Evander Andrews plant is double
what was called for in Idaho Power s 2004 IRP is already leading the Company to
determine that it will forego other resource development plans which may have had other
positive attributes not associated with natural gas-fired combustion turbines. In its
Response to ICIP's Request for Production No. 31 , Idaho Power stated
The summation of changes considered in the 2006 IRP, including the 85
MW of additional peaking capacity (above the 88 MW called for in the
2004 IRP) provided by the larger Evander Andrews combustion turbine
have allowed several of the resources selected in the 2004 IRP to be
deferred. First the 100 MW geothermal resource originally planned to be
online in 2008 in the 2004 IRP has been reduced to 50 MW and the online
date deferred until 2009. Second, the 62 MW combustion
turbineldistributed generation/market purchase resource originally planned
to be online in 2010 in the 2004 IRP has been eliminated altogether
although market purchases are still anticipated in the 2006 IRP. Finally,
the 12 MW of CHP resources originally planned to be online in 2007 in
the 2004 IRP have been deferred until 2010.
(Exhibit No. 235).
In effect, Evander Andrews will defer geothermal, distributed generation, and
CHP resources.
III
III
* * * * *
CONFIDENTIAL INFORMATION FOLLOWS
* * * * *
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IPC-06-
IV.RECOMMENDATIONS AND CONCLUSION
DR. READING, BY WAY OF SUMMARY, WHAT DO YOU BELIEVE
THE COMMISSION SHOULD DO IN TIDS PROCEEDING?
The Commission should deny Idaho Power s application for a certificate of public
convenience and necessity to construct the Evander Andrews plant.
IF, CONTRARY TO YOUR RECOMMENDATION, THE COMMISSION
WERE TO GRANT THE CERTIFICATE, WHAT STEPS DO YOU BELIEVE
THE COMMISSION SHOULD TAKE TO PREVENT UNNECESSARY HARM
TO RATEPAYERS?
If the Commission were to grant the certificate, it should make clear that Idaho
Power will not be allowed to collect the full costs of the Evander Andrews plant, which
include significant unnecessary and excessive construction and transmission costs.
HOW DO YOU BELIEVE THE COMMISSION SHOULD DETERMINE
THE AMOUNT OF COSTS TO EXCLUDE FROM IDAHO POWER'
RATEBASE?
* * * * *
CONFIDENTIAL INFORMATION FOLLOWS
* * * * *
Reading (Di) - ICIP
IPC- E-06-
I believe any of these actions would be justified since the costs I just described are
essentially costs that the Company has decided to incur, even though they are not
necessary or otherwise warranted. The Company s ratepayers should not be required to
pay for alternatives that do not benefit ratepayers where perfectly reasonable and
sufficient lower-cost options exist.
IS TIDS THE APPROPRIATE PROCEEDING TO RAISE ARGUMENTS
ABOUT HOW MUCH IDAHO POWER SHOULD BE ALLOWED TO RECOVER
IN RATES?
Even though this proceeding concerns only the Certificate to construct the
Evander Andrews project, Idaho Power s application makes clear that Idaho Power will
interpret approval of the Evander Andrews project as evidence that it will be included in
the rates Idaho Power s customers will pay. Idaho Power has stated that
Ultimately, it is Idaho Power s intent that the Project be included in Idaho
Power s rate base. . . Idaho Power requests that the Commission note in
its Order. . . that, in the ordinary course of events, Idaho Power can expect
to ratebase the prudent capital costs for this Project and to recover prudent
fuel costs in the Company s Power Cost Adjustment mechanism.
(Idaho Power s Application, pp. 1-2). Therefore, I think it is important that the
Commission note in its order its decisions as to whether Idaho Power can or cannot
expect to recover all of the Evander Andrews costs in its rates.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes it does.
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 10th day of October, 2006, I caused a true and
correct copy of the foregoing DIRECT TESTIMONY OF DON C. READING, PhD, ON
BEHALF OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER to be served by the
method indicated below, and addressed to the following:
Jean Jewell
Idaho Public Utilities Commission
472 West Washington Street (83702)
Post Office Box 83720
Boise, Idaho 83720-0074
( ) u.S. Mail, Postage Prepaid
(X) Hand Delivered
( )
Overnight Mail
( )
Facsimile
( ) Electronic Mail
Barton L. Kline
Monica Moen
Idaho Power Company
1221 W. Idaho St. (83702)
PO Box 70
Boise, Idaho 83707
bk1ine~idahopower.com
mmoen~idahopower. com
( ) U.S. Mail, Postage Prepaid
(X) Hand Delivered
( ) Overnight Mail
( ) Facsimile
( ) Electronic Mail
Donovan Walker
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington (83702)
PO Box 83720
Boise, ID 83720-0074
Donovan. walker~uc.idaho .gov
( ) U.S. Mail, Postage Prepaid
(X) Hand Delivered
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( ) Facsimile
( ) Electronic Mail
James C. Miller
Sr. Vice President, Generation
Idaho Power Company
1221 W. Idaho St. (83702)
PO Box 70
Boise, Idaho 83707
iimmiller~idahopower .com
(Non-Confidential Testimony Only)
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(X) Hand Delivered
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( )
Facsimile
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Ronald L Williams
Williams Bradbury PC
O. Box 2128
Boise, Idaho 83701-2128
(Non-Confidential Testimony Only)
(X) U.S. Mail, Postage Prepaid
( ) Hand Delivered
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( ) Facsimile
( ) Electronic Mail
CERTIFICATE OF SERVICE - 1
Robert D. Looper
Mountain View Power Inc.
1015 W. Hays
Boise, Idaho 83702
(Non-Confidential Testimony Only)
CERTIFICATE OF SERVICE - 2
(X) u.S. Mail, Postage Prepaid
( ) Hand Delivered
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Signed: L'\\ CuJ\-t c;
Nina M. Curtis