HomeMy WebLinkAbout20010809Sterling Direct.pdf1
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
Q.Please state your name and business address
for the record.
A.My name is Rick Sterling. My business
address is 472 West Washington Street, Boise, Idaho.
Q.By whom are you employed and in what
capacity?
A.I am employed by the Idaho Public Utilities
Commission as a Staff engineer.
Q.What is your educational and professional
background?
A.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 received my Idaho license as a registered
professional Civil Engineer. I began working at the
Idaho Public Utilities Commission in 1994. During my
employment at the IPUC, I have attended the 1995 annual
regulatory studies program sponsored by the National
Association of Regulatory Commissioners (NARUC) at
Michigan State University, the 1995 Lawrence Berkeley
Laboratory Advanced Integrated Resource Plan (IRP)
Seminar, an advanced IRP course sponsored by EPRI
entitled Resource Planning in a Competitive
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
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7/20/01
Environment, and a 1998 workshop on Pricing and
Restructuring Alternatives in a Changing Electric
Industry sponsored by the New Mexico State University
Center for Public Utilities. My duties at the
Commission include analysis of utility rate
applications, rate design, tariff analysis and customer
petitions.
Q.What is the purpose of your testimony in this
proceeding?
A.The purpose of my testimony is to discuss the
adequacy of Idaho Power’s long-term and short-term
planning process, changes that I believe need to be
made to the planning process, the role of IdaCorp’s
Risk Management Committee in the planning process, and
recommendations on how the role of the Risk Management
Committee should be changed.
Q.What are the Commission’s current electric
utility planning requirements?
A.Regulated electric utilities in Idaho are
required by Order No. 22299 to prepare IRPs and file
them biennially with the Commission. Integrated
Resource Plans include the following three basic
elements:
1. A summary of existing hydroelectric, thermal
and Public Utility Regulatory Policy Act
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
(PURPA) generating resources, and a summary
of contract purchases and exchanges.
2. A summary of the utility’s present load
situation and forecasts of possible future
load requirements.
3. A discussion of the utility’s plan for
meeting all potential jurisdictional load
over the planning horizon. The discussion
should include references to expected costs,
reliability, and risks inherent in the range
of credible future scenarios.
Q.What is the purpose of an IRP?
A.The primary purpose of an IRP is to insure
that the utility considers all alternatives, both
demand side and supply side, for meeting expected loads
in the future at the lowest cost. The process of
preparing an IRP also insures that the full costs and
risks associated with all alternatives are considered.
The process requires that the utility seek input from
its customers, interested parties and from the
Commission Staff. The process itself and the
submission of the written plan as an end product,
document the utility’s planning and provide the
Commission and the public a window into the utility’s
planning process as well as a forum for providing
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
input.
Q.Can a utility deviate from its IRP?
A.Yes, in fact, a utility is expected to
deviate from its IRP when circumstances warrant. The
Commission, in Order No. 25260, adopted a policy
regarding integrated resource planning in which it
stated the following:
The requirement for implementation of a plandoes not mean that the plan must be followedwithout deviation. The requirement ofimplementation of a plan means that anelectric utility, having made an integratedresource plan to provide adequate and reliableservice to its electric customers at thelowest system cost, may and should deviatefrom that plan when presented withresponsible, reliable opportunities to furtherlower its planned system cost not anticipatedor identified in new existing or earlier plans
and not undermining the utility=s reliability.
. . . the filing of the plan does not
constitute approval or disapproval of the plan
having the force and effect of law, and
deviation from the plan would not constitute
violation of the Commission=s orders or rules.
The prudence of a utility=s plan and the
utility=s prudence in following or notfollowing a plan are matters that may beconsidered in a general rate proceeding orother proceeding in which those issues havebeen noticed.
The IRP represents a utility’s long-term plan
for meeting load. Currently, utilities are required to
use a 10-year planning horizon.
Q.In Idaho Power’s most recent IRP, how did the
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
Company indicate it would meet short-term deficits?
A.In Idaho Power’s most recent IRP, the 2000
IRP filed in June 2000, the Company indicated that it
intended to meet short-term deficits by purchasing from
the market. The Company planned to have sufficient
resources in place to meet load under median water
conditions, but intended to meet deficits under low
water conditions with wholesale market purchases.
Under median water conditions and expected
loads, the 2000 IRP showed deficits beginning in the
year 2000 of approximately 142 average MegaWatts (aMW)
in July, 86 aMW in August, and 88 aMW in December.
Without the addition of any new generation resources,
deficits in these months were expected to grow, and
deficits in other months were expected to appear as
loads grew. Exhibit No. 101 shows graphically the
monthly energy surplus/deficiency through 2010. To
fully satisfy expected deficits under median water
conditions, Idaho Power planned to purchase up to 250
aMW of energy in July and August, and 200 aMW of energy
in November and December.
Q.If Idaho Power planned to rely on the market
even under median water conditions, what were its plans
under low water conditions?
A.Under low water conditions, the Company
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
planned to rely on the market to an even greater
extent. Under the low water scenario, the IRP
projected substantial deficits to begin immediately in
the summer and winter months. Exhibit No. 102 shows
the monthly energy surplus/deficiency under low water
conditions. A deficit of as much as 334 aMW appears as
early as July 2000.
The monthly peak hour surplus/deficiency
graph also reveals how dependent Idaho Power was
expected to be under low water conditions as shown in
Exhibit No. 103. For the monthly peak hour, Idaho
Power expected to be deficit almost all of the months
of the year.
Under low water, even with the purchase of
250 aMW in the summer (July and August) and 200 aMW in
the winter (November and December), the Company still
projected deficits as high as 264 aMW in May of 2000.
Exhibit No. 104 shows the Company’s expected monthly
deficits, including planned seasonal purchases and new
resource additions.
Q. How did the low water scenario in Idaho
Power’s IRP compare to what actually happened during
the past year?
A.Exhibit No. 105 compares actual surpluses and
deficits from June 2000 through May 2001 to the low
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
water scenario in the IRP. As the exhibit shows,
deficits in five of the twelve months were even greater
than expected under the low water scenario.
Q. It seems that Idaho Power’s own IRP indicated
the degree to which the Company might have to rely on
the market this past year. Why then did Idaho Power
incur such high purchased power costs?
A. The level of reliance on the market during
the past year was, for the most part, expected given
the water conditions. Some months showed deficits even
greater than predicted under a low water scenario,
while in some months, water conditions were above the
low water condition and thus showed smaller deficits.
What was not expected, however, were the extremely high
market prices. The substantial planned reliance on the
market combined with the extremely high prices led to
higher than anticipated purchased power costs.
Q. How did Idaho Power respond to the high
market prices of the past year?
A. The Company responded in several different
ways. First, Idaho Power implemented buy-back programs
for their irrigation customers and for Astaris, their
largest industrial customer. In addition, the Company
made a decision to construct 90 MW of new gas-fired
generation at Mountain Home. Finally, the Company
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
leased 25 MW of diesel-fired mobile generators and
considered plans to lease two additional 25 MW
increments of mobile generation.
Q. How did Idaho Power evaluate these resources
and programs?
A. For the most part, Idaho Power compared the
estimated costs of these resources and programs to the
prices they otherwise expected to pay to acquire power
from the market.
Q. Do you think Idaho Power’s evaluations were
appropriate?
A. In most cases they were, but in some cases I
think more complete evaluations should have been done.
For example, the irrigation buy-back program is only
intended to last for the current season, so a
comparison to expected market prices was reasonable.
Similarly, the mobile generators have short-term leases
that expire at the end of the summer. The Astaris buy-
back is a two-year agreement, so a comparison with
market alternatives is possible but more difficult.
The Mountain Home project, on the other hand, is a
project with an expected life of 30 years. A
comparison to current market prices is not sufficient
to determine the long-term cost effectiveness of the
project. As a long-term resource, it should be
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
compared to other long-term resource alternatives.
Q. How well do the alternatives selected by
Idaho Power — i.e., irrigation buy-back, Astaris buy-
back, Mountain Home generation project, and mobile
generators — reduce the Company’s exposure to the
wholesale market through the end of this year?
A. Under currently anticipated water conditions,
the combination of these alternatives should enable
Idaho Power to meet loads through March 2002 with no
additional market purchases necessary, except for a
small 37 aMW deficit during heavy load hours in
December.
Under a worst case water scenario, deficits
of 151 aMW in December, 80 aMW in January and 24 aMW in
March would be possible without the purchase of
additional energy or the addition of new resources.
Q.Do you think the experience of the past year
indicates a weakness in the IRP planning process?
A.Yes, in some ways. The IRP process is
perhaps more important than ever now that utilities are
again faced with acquiring new resources and the risks
of simply relying on the market have become evident.
However, the IRP process was never intended to be a
short-term planning tool. While utilities are expected
to deviate from the IRP when necessary, there still
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
must be a short-term planning process to guide decision
making for such deviations. Without a short-term plan
or a well defined process, the utility is put in a
position of having to take quick actions and make
emergency decisions. It can subsequently be difficult
for both the utility and the Commission to assure
ratepayers that prudent decision making occurred. Time
constraints associated with planning and implementing
new programs or in acquiring new resources can narrow
the field of possible options. In addition, sometimes
there is no assurance that the resources or programs
chosen are necessarily the best when the primary basis
for comparison is whether they are less costly than
relying on the market. Customers and the Commission
deserve some assurance that a full menu of options is
considered, and that even short-term decisions are in
the long-term interests of ratepayers.
One example of this was the Company’s
decision to pursue the Mountain Home generation
project. Idaho Power did not identify the need for the
project until early this year, and quickly decided to
go ahead with it in a matter of weeks. Construction
began on the project in June. While the project may be
the best alternative for the Company, which may deserve
to be commended for getting the project underway
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
quickly, the Commission expressed concern about the
lack of a comparison to other alternatives.
Consequently, the Commission approved rate-basing the
project but declined to approve a specific amount to be
recovered in rates. Reference Order No. 28773.
Q.Do you believe any changes need to be made in
the IRP planning process?
A.Yes. When the rules for IRPs were
implemented, I do not believe anyone expected changes
in market or natural gas prices to take place at the
speed and to the degree they have recently. A two-year
planning cycle is too long if a utility uses the full
two years to completely overhaul the previous IRP.
Integrated resource planning should be an ongoing
process, not an effort to produce a final document.
Integrated resource planning should not stop after
completion of one plan and start up again prior to
preparation of another. The plan, once submitted,
should simply be a reflection of that continuing
process. A two-year interval may still be reasonable
for reporting the utility’s planning activities to the
Commission, however.
In addition, Idaho Power must incorporate
market uncertainty into its IRP analysis. It is no
longer reasonable to assume that market resources are
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
unlimited and readily available at prices no higher
than the marginal cost of new generation. Reliance on
the market carries substantial risk. As more and more
utilities have developed a dependence on the market in
recent years, this risk has increased. What may have
seemed like a reasonable level of planned reliance on
the market just two years ago may no longer be
reasonable. It has become more important to
acknowledge that market prices are uncertain and
perhaps less attractive than building new generators or
acquiring long-term contracts for output from specific
plants.
Finally, a fresh look at demand side
alternatives is warranted. As market prices have
increased, more and more demand side programs have
become cost effective. Idaho Power should continue to
support regional conservation efforts through the
Northwest Energy Efficiency Alliance and proceed in
developing a comprehensive Demand Side Management
Program as directed by the Commission’s Order No.
28722. As the past year has shown, quick
implementation of various short-term demand reduction
programs can be one of the most effective ways to
respond to supply shortfalls and extremely high market
prices. It is important to develop some experience
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
with these types of demand side programs so that they
can be rapidly deployed whenever needed. The Company
should have an arsenal of programs “on the shelf” so
that it does not need to devise new programs and
strategies each time the need arises.
Q.What other changes do you recommend?
A.I recommend that Idaho Power consider
abandoning median water planning and either move closer
to critical water planning or re-establish a planning
reserve.
Q.Please explain the difference between median
water planning and critical water planning.
A.Median water planning means that the Company
plans to have enough resources available under median
water conditions to meet its expected native load on a
monthly basis. A median water condition is that which
represents the average condition over many years (a 50-
year average in Idaho Power’s case). By definition
then, above median conditions can be expected to occur
in half of the years, and below median conditions can
be expected in the remaining half. Consequently, Idaho
Power currently plans to meet its load with its own
resources or long-term contracts every month in half of
the years, but must rely, at least to some extent, on
spot or short-term market purchases to meet load during
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
the other half of the years.
Critical water planning means that the
Company would plan to have enough resources available
under critical water conditions to meet its expected
native load. Critical water conditions reflect the
lowest consecutive 18-month period on record. A
utility that planned to meet load under critical water
conditions could meet load with its own resources for
an extended period of time, but would not necessarily
be able to meet load all of the time in every month.
Q.On what basis does Idaho Power plan?
A.Idaho Power has always planned using median
water assumptions. Many other utilities in the region
plan based on a critical water planning criterion.
Q.Do you believe Idaho Power should continue to
plan based on median water?
A.No, not unless the Company reestablishes a
planning reserve. Median water planning may have been
acceptable when the availability and price of market
resources were reasonably predictable. However, as we
have seen in the past year, the price and availability
of market resources can be extremely volatile. In the
past, it was assumed that reliance on the market
carried little risk, and that prices would not rise
above the marginal cost of new generation. The
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
experience of the past year has demonstrated that
reliance on the market can expose ratepayers to
considerable risk.
Q.In the direct testimony of Idaho Power
witness Gale, he states that he believes that the
Company’s 2002 IRP should address in detail the issue
of whether or not it is time to change the median water
planning assumption for planning purposes. Do you
agree?
A.I agree that the issue should be examined.
In fact, I think that such an examination should begin
immediately.
Q.Besides moving closer toward critical water
planning, are there other ways to accomplish the same
thing?
A.Yes, Idaho Power could establish a planning
reserve. A planning reserve simply means that the
Company would plan to have an increment of generating
capability above that required to meet expected loads
under median water conditions. A planning reserve
insures that extra resources are available in the event
of poor water conditions, higher than expected load
growth, or other planning inaccuracies. Prior to 1995,
Idaho Power maintained a six-percent planning reserve.
Ironically, that reserve was eliminated, in part I
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
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believe, because of the readily available market
resources that the Company believed it could call upon
when needed.
Q.What would be the effect of either moving
toward critical water planning or establishing a
planning reserve?
A.The effect would be an increase in the amount
of generation available from Idaho Power’s own system.
Thus, under low water conditions or during peak load
periods, Idaho Power would be less reliant on the
market. Having more system resources available would,
of course, increase the revenue requirement used to set
base rates, but it would reduce the Company’s exposure
to the high prices and volatility of the market. Staff
recommends that the Company complete an analysis to
determine what water conditions or planning reserve is
appropriate. Such an analysis should include a
comparison of the costs and benefits of having varying
levels of excess generation available. I am not
suggesting that Idaho Power eliminate its reliance on
the market. I am only recommending that the level of
reliance be reevaluated given recent market volatility.
Idaho Power has relied on regional diversity exchanges
for years to take advantage of seasonal differences in
loads, and should continue to do so.
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
7/20/01
Q.What process does Idaho Power follow for
short-term planning?
A.It appears that the short-term planning
process is not nearly as well defined as the long-term
process and that it depends somewhat on the
circumstances. When issues arise, those Company
personnel most closely associated with the issue
perform the analysis, complete the planning and carry
out necessary actions. Decisions about how to proceed
however, appear to be made primarily by the Risk
Management Committee. For example, when Idaho Power
was faced with extremely high market prices and poor
water conditions this past winter and spring, the
Committee made decisions about which demand and supply
side alternatives to implement. Detailed program and
project plans were made by Idaho Power staff.
Q.Who are the members of the Risk Management
Committee, and what are their positions and
responsibilities within Idaho Power and IdaCorp?
A.The Risk Management Committee is made up of
the following members:
Darrel Anderson Vice President Finance,
Treasurer, Idaho Power Company
and IdaCorp
Jan B. Packwood President and Chief Executive
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
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Officer, Idaho Power Company
and IdaCorp
Richard Riazzi Senior Vice President,
Generation and Marketing, Idaho
Power Company and IdaCorp
J. LaMont Keen Senior Vice President,
Administration and Chief
Financial Officer, Idaho Power
Company and IdaCorp
Jim Miller Senior Vice President,
Delivery,
Idaho Power Company
Robert Stahman Vice President, Secretary and
General Counsel, Idaho Power
Company and IdaCorp
John Prescott Vice President Generation,
Idaho
Power Company
Randy Hill President and Chief Executive
Officer, Ida-West Energy
An organizational chart showing the
composition of the Risk Management Committee is
attached as Exhibit No. 106.
Q.What is the purpose of the Risk Management
Committee?
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
IPC-E-01-11 STAFF
IPC-E-01-16
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A.The purpose of the Risk Management Committee
is to maintain general oversight over all of IdaCorp’s
commodity trading and financial risk management
operations. As outlined in IdaCorp’s Risk Management
Policy, the primary role of the Committee is to make
decisions regarding trading activities. The Risk
Management Policy does not outline any responsibilities
of the Committee with regard to acquisition of new
generating resources or implementation of short-term
demand side measures to meet load.
Q.Based on your investigation, does the Risk
Management Committee restrict its role to only that
outlined in the Risk Management Policy?
A.No, I believe the Risk Management Committee
has taken on a greatly expanded role. I believe the
original role of the Committee was to make decisions
about market transactions in order to manage risk to
IdaCorp shareholders. In fact, the Risk Management
Committee was originally formed in 1996 in response to
the Company’s decision to enter into the non-regulated
speculative commodity trading business. However, a
review of the meeting minutes of the Committee over the
past year shows that the Committee has now evolved into
a decision making body for demand side and asset
acquisition decisions, such as how Idaho Power Company
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CASE NOS. IPC-E-01-7 STERLING, R (Di)
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should respond to meet short-term deficits and to
minimize exposure to extremely high market prices. In
addition to the traditional acquisition of energy from
the market, the Risk Management Committee considers
alternatives to market purchases, such as voluntary
load reduction programs and temporary generation
resources. For example, based on its meeting minutes,
the Committee appeared to make final decisions about
whether Idaho Power should proceed with the Astaris
buy-back, the irrigation buy-back and the installation
of mobile generators. The Committee did not appear to
be involved in the selection of the Garnet Project or
the Mountain Home Project as long-term future Company
resources.
Q.Do you believe that it is appropriate for the
Risk Management Committee to take on this expanded
role?
A.No, I do not. I believe that the Risk
Management Committee, given its apparent expanded role
and the composition of its membership, has created the
potential for serious conflicts of interest. What may
be best for the shareholders of IdaCorp may not be what
is best for ratepayers of Idaho Power Company. Because
the Committee is composed of some members who are not
officers of Idaho Power, and because the Committee
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answers to the Board of Directors of IdaCorp, its first
allegiance is to its shareholders. Consequently, I
believe it is possible that its decisions are not
always in the best interests of ratepayers.
Q.Can you give an example of a conflict of
interest?
A.Yes, I can. Idaho Power’s decision to lease
mobile generators was made by the Risk Management
Committee. While I am not judging the prudence of that
decision here, I am suggesting that the final decision
to proceed should not have been made by the Committee.
Most of the members of the Committee are officers of
both Idaho Power Company and IdaCorp, but some are
officers of only one. The president of Ida-West for
example, should not be involved in decisions about
acquisition of new generation by Idaho Power, even if
the generation is only temporary. Ida-West is an
unregulated subsidiary of IdaCorp whose business is
building and operating new generation projects. In
theory, their project proposals are supposed to compete
with Idaho Power’s own self-build options.
Other situations could exist where the Risk
Management Committee may be willing to commit
shareholders to paying ten percent of increased power
supply costs as passed through by the PCA, in exchange
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for the opportunity for shareholders to earn a much
greater unregulated return. A decision to rely on the
spot market instead of a term transaction could be one
example of such a conflict. If the decision were made
by Idaho Power, keeping the interests of ratepayers
foremost, a different decision might have been made.
Q.What steps do you believe should be taken to
eliminate this possible conflict of interest?
A.First I believe Idaho Power should consider
reestablishing a planning department within the
Company.
The planning department would then have primary
responsibility for both short-term and long-term
planning. The planning department would also have more
influence in planning decisions made on behalf of
ratepayers.
Second, I believe that the Risk Management
Committee should be restricted to making decisions only
about the non-regulated affairs of IdaCorp. Idaho
Power Company and its own officers and employees should
have sole responsibility for making decisions regarding
the Company’s regulated business. Idaho Power Company
can then make decisions that it believes are in the
best interests of its ratepayers. Idaho Power Company
may wish to form its own advisory committee, but it
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should be completely internal to Idaho Power so that
the interests of ratepayers are paramount. IdaCorp can
continue to have its own Risk Management Committee and
make decisions that it believes are in the best
interests of its shareholders.
Q. Has Idaho Power indicated any plans to
reorganize the Risk Management Committee?
A. Yes. Idaho Power has indicated that it and
IdaCorp Energy (formerly IdaCorp Energy Solutions) are
currently in the final stages of executing the
separation of IdaCorp Energy from Idaho Power described
in the Company’s application in Case No. IPC-E-00-13.
In conjunction with that separation, IdaCorp, Idaho
Power and IdaCorp Energy are moving to restructure and
separate the Risk Management Committee into more than
one committee to ensure compliance with all codes of
conduct and eliminate any duplication of functions. So
far, Idaho Power has indicated that there will be two
separate risk management committees: one for IdaCorp
Energy and one for Idaho Power Company. Only one
person — J. Lamont Keen, Idaho Power CFO and Senior
Vice President of Administration — will be a member of
both committees. John Prescott, Idaho Power Vice
President of Generation, will chair the Idaho Power
Risk Management Committee.
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Q. Will this proposed split and reorganization
of the Risk Management Committee alleviate your
concerns about possible conflicts of interest?
A.Yes, I believe that it will alleviate my
concerns with regard to conflicts of interest.
However, I still recommend that Idaho Power consider
reestablishing a planning department within the
Company.
Q.Does this conclude your direct testimony in
this proceeding?
A.Yes, it does.