20040220Hessing Direct.pdf

RECEIVED
2004 February 20 PM 4:59
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS INTERIM
AND BASE RATES AND CHARGES FOR
ELECTRIC SERVICE.
) CASE NO. IPC-O3-
DIRECT TESTIMONY OF KEITH HESSING
IDAHO PUBLIC UTILITIES COMMISSION
FEBRUARY 20, 2004
Please state your name and business address for
the record.
My name is Keith D. Hess and my business
address is 472 West Washington street, Boise, Idaho.
By whom are you emplo and in what capacity?
I am employed the Idaho Public utili ties
Commission as a Public utili ties Engineer.
What 1S your educational and experience
background?
I am a Registered Professional er in the
state of Idaho.I received a Bachelor of Science Degree
in Civil ring from the Uni versi ty of Idaho in
1974.Since then, I have worked six years with the Idaho
Department of Water Resources, and two years with
Morrison-Knudsen.I have been cont ly emplo
the Commission since August 1983.
As a member of the Commission Staff, my primary
areas of responsibility have been electric utility power
supply, revenue allocation and rate design.
What is the purpose of your test in thi
proceeding?
My test addresses Jur isdict
Separations, Class Cost of Service, some Power Cost
Adjustment components and cloud seeding.
Please summar1ze your test
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
I recommend that the Commission the 12
coincident peak (12CP) Jurisdictional Separation
Methodology proposed the Company to allocate costs to
the Idaho jurisdiction.This method applied to Staff'
total Company Revenue Requirement results in an Idaho
Jurisdictional Revenue Requirement of $498,758,249, which
requires an average 3.06 percent rate 1ncrease to recover
an additional $14,796,880 revenue requirement.
Staff accepts the weighted 12 coincident peak
(W 2CP) methodology proposed by the Company for the
purpose of allocat costs to the Company s Idaho
customer classes.Staff witness David Schunke proposes
some non-cost based modifications to these cost of
service results that become Staff's revenue allocation
proposal.
I review the Company s Power Cost Adj us tment
ca culations that change as a result of a general
rate case.Staff recommends that the Commission accept
the Company s proposed changes for the changes to
the Expense Adjustment Rate for Growth.The Company
proposes that the rate used to adj ust actual power supply
costs to remove the costs of load be the embedded
cost of power supply which is 7.30 $/MWh.I propose that
these changes from normal power supply costs occur at the
cost of power supply and, therefore, the
CASE NO. IPC-03-02/20/04 (Di)HESSING , K.Staff
marginal cost rate of 29.41 $/MWh should be used in the
calculation.
Finally, my testimony scusses the Company
cloud se program 1nc its effects on the PCA.
I propose that there are questions regarding the program
tha t remain unanswered and that need to be answered
before the Commission can decide whether or not to accept
the costs include in this case.My testimony includes
some of those questions.
JURISDICTIONAL SEPARATIONS
What are Jurisdictional S ions?
I t is the process used to divide Idaho Power
Company s annual costs among the j ur isdictions it serves.
In general the process identifies the Company s costs as
related to the supply of energy, peak demand, or the
number of customers.The costs are then divided to the
Idaho, Oregon or Federal Energy Regulatory Commission
(FERC) Jurisdictions based on each jurisdiction
proportional amount of each of these items.The FERC
Jurisdiction consists of wholesale sales to other
utilities.The Jurisdictional Separation process results
in the Idaho Revenue Requirement, which is the amount of
the Company s total normal annual Revenue Requirement
that is caused by Idaho ratepayers and that must be
recovered from Idaho ratepayers.
CASE NO. IPC-03-02/20/04 (Di)HESSING , K.Staff
Wha t has changed since the , s last
general rate case that affects Jurisdictional
Separations?
Big s have occurred in the allocation
factors.For example, the number of customers in Idaho
and on the total System grew substantially since the last
rate case, but the Idaho customer allocator only grew
about 1 percent.The story is very different for the
demand and energy allocators.Idaho s share of total
Company peak demand grew approximately 8 percent and
Idaho s share of total energy use grew approximately 9
percent.In all three cases Idaho s share of the total
has increased.Because these are the characteristics
used to divide or allocate costs among the jurisdictions,
the Idaho Juris has become a larger share of the
Company s total costs of providing service.
Please explain in more detail the changes that
have occurred in these allocators Slnce the Company
last general rate case.
The addition of 100,000 new customers in Idaho
did not substantially change the Idaho customer allocator
because ional , soccurred in the
other jurisdictions.The growth in the rela ti ve
percentages of the energy and coincident peak demand
allocators res more explanation.Total Company
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
energy ion has decl ined and total peak
demand has not increased as fast as peak demand in Idaho.
There are a number of factors at ay here.The large
increase in customers increased Idaho Peak demand and
energy requirements and Idaho Power lost its single
largest customer, FMC/Astaris.Since Idaho Power s last
general rate case, nearly all of its FERC Jurisdictional
contract sales expired as ori lly designed so that the
Company s resources could be fully utilized to supply its
load growth.These expired contracts practically
eliminated FERC Jurisdictional energy and peak demand.
When Idaho s share of peak demand is calculated, the
Idaho Jurisdiction becomes responsible for an additional
8 percent share of total Company demand-related costs.
When Idaho s share of total energy is calculated, Idaho
becomes responsible for an additional 9 percent of total
Company energy-related costs, not only because Idaho
energy requirements increased but because total Company
energy requirements decreased.
Have you prepared an exhibit that shows how
these allocation factors have changed since the Company
last general rate case?
Staff Exhibit No. 118 shows theseYes.
changes.There are several di fferent Energy, Demand and
Customer Allocators used in the Jurisdictional
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
ions S The exhibit includes one of each for
illustrative purposes.
has the Company not entered into firm
contracts to sell the unused energy made available by the
expiration of the FERC jurisdictional contracts?
Doing so would reduce Idaho s peak demand and
energy allocators.However , the Company has also changed
the load and water planning criteria in its Integrated
Resource Plan.In response to high costs experienced by
the Company and its customers in 2000 and 2001 when
streamflows were low and market ces were extremely
high, the Company now plans to meet its load during low
water conditions with reduced reliance on market
purchases.This change in planning criteria, coupled
wi th new customer load , has all but el
excess energy available for new firm wholesale contracts.
Wha t happens to the uncommi t ted capaci t y that
is be held in reserve to meet above normal load and/or
below normal streamflow conditions?
In low water or high load conditions, the
reserve capac1 1S available to the Company and its
customers to meet 1 ad at a price that will usually
be below the cost of purchasing market power.In normal
or above normal water conditions when the costs of
wi th these resources is below market pr1ce,
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
Idaho Power will sell the power and credit the revenues
against expenses, which reduces customer rates.In this
case, these benefits are captured in the power supply
model process that establishes normal power supply
costs included in base rates.On a year-by-year basis,
deviations from base power supply costs are captured in
the PCA.
Does Staff agree with the Jurisdictional
Separations process used by Idaho Power Company?
The Company used the same 12CPYes.
methodology that it has used for more than 20 years.
is appropriate for changes in Company costs and changes
1n jurisdictional use characteristics to change customer
ra tes.However , without compelling reason , it is not
appropriate to cause tional rate s due simply
to change in allocation methodology.In its analysis,
Staff used the Company s methodology and jurisdictional
allocators with Staff's proposed account adjustments
to determine the Idaho Jurisdictional revenue
requirement.
What are the results of Staff's Jurisdictional
process?
Staff's cost of service results, revenue
al ocation to classes and rate designs are based on a
total Idaho Jurisdiction revenue requirement initially
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
determined to be $499 161,903 which is an increase of
$15,200,534, and results in a 3.14 percent average
increase in rates.After that initial determination,
staff auditors continued to examine fic items in the
Company s revenue requirement, which ultimately reduced
Staff's recommended Idaho Jurisdictional revenue
requirement to $498 758 249 , an increase of $14 796 880
or a 3.06 percent average rate increase.Because lass
cost of service studies, revenue allocations and rate
designs involve complicated issues and analysis, it was
necessary for the Staff members wor on those 1ssues
to prepare their recommendations before the Staff
audi tors had concluded their analysis.Accordingly,
staff testimony on revenue allocation , cost of serV1ce
and rate design are based on the initial Staff
determination of the Company s Idaho Jurisdictional
Revenue Requirement.it No.Staff 19 summarizes
the results of Staff's jurisdictional separations study.
Staff witness Schunke s testimony provides revenue
allocation and rate design guidelines for the
Commission s consideration that accommodate the reduced
Staff revenue requirement proposal.
COST OF SERVICE
What is a cost of service study?
A cost of serV1ce study divides the Idaho
CASE NO. IPC-03-02/20/04 (Di)HESSING , K.Staff
Jurisdictional Revenue Requirement among the Company
various customer classes based on the cost-causing
characteristics of the classes.The process is similar
to the Jurisdictional Separations process.Alloca tors
are developed for each customer class as pe s of
the Idaho total for energy use, contributions to monthly
coincident peak demand and numbers of customers.These
allocators are then used to distribute the total Idaho
Revenue Requirement to the various customer classes.
What class cost of service methodology did the
Company use?
The Company used substantially the same
methodology that it has used in its last two general rate
cases.The method is called the weighted 12 coincident
peak (W12CP) method.For the allocation of
related costs, this method weights monthly coincident
peak demands by the marginal cost of providing for those
demands and averages the results with unweighted 12CP
resul ts .In months when the Company is not ing a
peak demand deficit, a zero wei ing is applied.When
seven of the months are weighted at zero, the allocators
become the average f, what amounts to, a wei 5CP
methodology (the remaining five months of coincident peak
demands) and an unweigh ted 2CP methodology.
The same method is used for the allocation of
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
transmission related costs except on the transmission
system there are nine months when the Company does not
expect peak demand deficits.Therefore, only three
weighted months are averaged with the 12CP numbers to
obtain the proposed allocation factors.The maj or energy
allocator is calculated based on monthly energy use
weighted by the monthly marginal cost of energy.It is
not averaged with other unweighted allocators.
Steam and Hydro production investment are
classified as related to demand or related to energy
based on an Idaho Jurisdictional Load Factor (the ratio
of average use to peak use) of 55.This means
that 55.26 percent of these investments are allocated to
customer classes based on energy use and the rema1n1ng
amount is allocated based on peak demand.
What has changed since the Company s last
general rate case ten years ago that affects cost of
service?
There have been many changes.A few of the
changes are: the addition of 100,000 new customers, the
loss of the FMC/Astaris load, the change in the Company
load and water pI ter ia a more conservat
posi tion, the deregulation of the wholesale electric
market, and the change in the Company oad/ resource
characteristics from be energy constrained to capaci
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
constrained.
How might these changes affect cost of service
resul ts?
These s affect the Company s underlying
costs, the energy and capaci allocators applied to each
customer class, and the marginal costs used to wei the
alloca tors.Virtually everything that affects cost of
serV1ce, except the basic methodology, has changed.
Please describe the cost of service analysis
performed by Staff.
staff used the Company s W12CP methodology that
has been by the Commission in past proce
staff also used the wei factors and associated
methodology proposed the Company in recognition that
and energy are more costly to In some
months of the year.Staff recognizes that weighted
months, some of which were weighted at zero, averaged
with unweighted months, creates demand allocators that
are more complex than those used in the past.staff can
accept the use of some zero we1 ed months because they
are averaged with unweighted months and because they
de with the months where no capacity constra
expected.Staff Exhibit No. 120 shows the results of
Staff's Cost of Service Study.In his testimony, Staff
wi tness Schunke proposes a modified allocation of revenue
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
requirement to customer classes that is not entirely
based on cost of service results.
Are unweighted and zero weighted months the
same thing?
If the peak demand for a month is zeroNo.
wel ed, it is mul zero and no value islied
included in the calculation of the weighted allocator for
that month.I f the peak demand for a month is
unweighted, the actual coincident peak demand is used in
the calculation of the allocator.
How many cost of service studies did Staff
perform?
staff performed three cost of serV1ce studies.
I have already described the first one which is the study
recommended Staff.
What was the second study performed by Staff?
The second study is a weighted 12CP study with
the weighted portion of the June allocator weighted at
zero.The resulting ratio was averaged with the
unwel ed ratio to obtain the final allocators.The
resul ts of this study are shown on Staff Exhibit No. 121.
The results showed a decrease in thes s
required increase for the irrigation class.The increase
dropped from 47.2 percent to 44.5 percent.
Please discuss Staff's third cost of serVlce
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
study.
The third study is a traditional unweighted
12CP study.The analysis removed all 1 cost
demand and energy weight used to calculate
alloca tors.Weightings were removed in the calculation
of production and transmission demand allocators and for
the calculation of the energy allocator.staff Exhibit
No. 122 shows the results of the study.When all
weightings were removed, which is the same as setting
them at , the required increase in irrigation rates
dropped aga1n, this time to a 29.percent increase.
course, any time the allocation drops for one class the
other customer classes pick up the difference to produce
the revenue required to cover the Idaho jurisdictional
revenue requirement.
Why did Staff perform the second and third
studies?
The results of the Company s W12CP methodology
require a substantial increase to bring the irri ion
class to full cost of serV1ce, as m1 be expected with
capaci ty and energy allocators more heavily weighted in
summer months.staff wanted to know how sensi class
allocations, especially irr iga tion class allocations, are
to al oca tion factor changes.All three studies show the
irrigation class requi an increase far above any
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
other class.Using the Company s methodology, as Staff
did in its first study, the irrigation class would
require an increase five times the next highest class
lncrease.
Please compare the effects of the unweighted
12CP methodology and the Company s W12CP methodology on
the Residential customer class.
The results of the weighted 12CP study showed a
08 percent decrease for residential customers.
Unweighted study results showed residential rates
a 1.71 percent lncrease.Gi ven the residential
customer s summer air conditioning load these results may
seem inconsistent.However, a more detailed review of
residential load data provides an explanation.The
winter heat load is er than the summer air
condi tioning load and January and February are zero
weighted in the weighted 12CP production al ocator.
Also, all winter months are zero weighted in the weighted
12CP transmission allocator.The result is a relatively
small effect on residential cost of service regardless of
the allocator weightings used in the cost of service
study.
Why did Staff choose the Company s proposed
cost of service methodology including its allocator
weight
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
staff believes that demand-related plant
investments are driven by low hydro conditions and high
oads in the critical peak months.It is the demand in
these critical months when the system is capacity
constrained that is most relevant in this analysis.
Therefore, any analysis that does not weight the critical
months more heavily than shoulder months does not
correctly reflect forward-looking demand related costs.
The Company s study gives heavier weighting to the five
cri tical months of June, July, August, November and
December.Therefore, Staff believes that the monthly
weightings are justified and that the Company s cost of
service methodology is reasonable.
THE POWER COST ADJUSTMENT (PCA) MECHANISM
What is the PCA?
In general, the PCA is a rate adjustment
mechanism that annually adjusts customer rates to recover
or re fund 90 of above or below normal load
usted power supply costs.Each year the PCA is
composed of a forecast or predicted component and a true
up component.
What PCA items does your test scuss?
Base power supply costs are established in a
general rate case and those are discussed in Staff
wi tness Rick Sterl , s testimony.From the process that
CASE NO. IPC-03-02/20/04 (Di)HESSING , K.Staff
establishes base power supply comes the PCA
forecast, which I will discuss.I will also discuss the
oad adjustment and some other components of the PCA
calculation.
How will the results of this rate case change
the PCA?
The normalized power supply costs established
in thi will be included in the base rates of
each customer class.The annual proj ection or forecast
of power supply costs based on water conditions will also
in base power supply costs will cause a
recalculation of the predictive formula that relates
April through July Brownlee inflow to Net Power Supply
Costs.Each April this formula along with the National
Wea ther ce runoff forecast is used to proj ect net
power supply costs for the coming year.Company "vi tness
Greg Said discusses this calculation in his direct
test 19 of his testat page 16.
shows the Company-proposed forecast formula.Company
Exhibi t No. 35 shows the data and regression
resul ts .
Does Staff agree with the Company s calculat
of the forecast formula?
Staff has not adjusted the CompanyYes.
power supply model results in this case and proposes no
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
changes in the forecast methodology other than exclusion
of the FMC/Astaris adjustment proposed Company witness
Said (Direct Testimony, page 19, 1 17-24).
Therefore, Staff calculates the same forecast formula as
the Company.
Does the Company propose to update other PCA
computations?
Company Exhibit No.3 6 shows four PCAYes.
computations that Company witness Said proposes to
update.He updates "Normalized PCA Expenses " which is
normalized power supply expense from the Aurora model
plus normalized CSPP costs.The new number is
$94,101,100 per year.
The Company updates the "Normalized Base PCA
Rate " which is normalized PCA expenses divided
normalized system firm sales.The new rate is .7315
C::/kWh.
Idaho Power also updates the "Idaho
Jurisdictional Percentage " which is used to allocate
abnormal power supply costs to Idaho.It is calculated
by dividing normalized system firm load Idaho
Jur1 ctional firm load.The number is 94.
Finally, the Company updates the "Expense
Adj ustment Rate for Growth" which is used to remove power
supply cost increases associated with growth.Mr. Said
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
calculates 13.98 $/MWh in the exhibit but uses a
different rational to propose 7.30 $/MWh in his
testimony.
Is it appropriate to update these calculations
in this general rate case?
These calculations are intended to beYes.
updated in a general rate case.
Does Staff accept the results of the updated
calculations for use in the PCA?
Staff accepts the Company s updated
calculations as shown on Company Exhibit No. 36, except
for the calculation of the e Adjustment Rate for
Growth.Staff disagrees with the Company s rational for
and calculation of this adjustment.
Please discuss the Expense Adjustment Rate for
Growth.
Such a discussion requires some basic PCA
background.The PCA captures actual booked monthly power
supply costs that are above or below the normal values
established the Commission and included in base rates.
These differences from normal power supply costs result
from abnormal streamflows, abnormal market prlces,
abnormal fuel prices, abnormal loads that may be caused
by weather, buy-back programs, conservation, or load
growth or loss.e Adjustment Rate for GrowthThe
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
(EARG) is aimed very specifically at the variable cost of
power supply caused by changes in load.When load grows,
the EARG is part of the me sm that removes the above
normal costs of power supply captured in PCA accounts
that are associated with load growth.In essence this
ustment removes the power supply effects of load
growth and leaves the effects of abnormal water
conditions and market pr1ces, which the PCA is desi
to capture.
When loads are below normal, the EARG
mult lier is part of the mechanism that s the
Company from losing both the retail revenue and power
supply cost sav1ngs that are credited back to customers
through the PCA.Again , this adjustment removes from the
PCA the power cost effects of the loss in load and leaves
the effects of abnormal water and market prices in the
PCA.When these adj ustments are appropriately made using
the correct multiplier, the Company neither over-collects
nor under-collects power supply costs through the PCA
when consumption is higher or lower than normal.The
difference between power supply costs incurred to serve
new customers and embedded power y costs collected
in rates must still be recovered in a general rate case
just as it has been in the past.The PCA is left to
capture predominantly power supply cost s that
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
resul t from abnormal water and market prlce conditions
tha t would not be captured under the normal conditions
assumed in a genera rate case.
You mentioned that the load adjustment
mechanism works if the correct value is used as the
Expense Adjustment Rate for Growth.What is the correct
EARG value?
Power supply costs associated with load
are captured in the PCA at the marginal cost level.
Therefore, they must be removed at the marginal cost
level.In Response No. 30 to the Second Production
Request of the Idaho Irri ion rs Association,
Idaho Power identified the average annual marginal cost
of energy as 27.01 $/MWh.This is Staff Exhibit No. 123.
At the customer level, which ude s 8. 9 sslon
and distribution losses, this becomes 29.41 $/MWh.
propose this as the appropriate EARG.
What is the current EARG and where did it come
from?
The current EARG is 16.84 $/MWh and it was
established in Case No. IPC-E-92-, the case that first
established Idaho Power s PCA me sm.Staff proposed
16.84 $/MWh in that case as a surrogate for the average
marginal cost of power supply.It was calculated as the
average of Boardman and Valmy fuel costs which at that
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
time the range of normal market prlces.
surrogate for Idaho Power s marginal cost of power supply
was proposed in that case because Staff did not have an
opera t power supply model that would allow it to
incrementally adj ust the load and calculate the marginal
cost.In the Company s last general rate case, Case No.
IPC-E-94-, 16.22 $/MWh was calculated from an
incremental power supply model run.No recommendation
was made to change the 16.84 $ /MWh EARG because the
difference was smal
What would be the result if the Commission
adopted the Company s proposal to use the average power
supply cost of 7.30 $/MWh for the Expense Adjustment Rate
for Growth?
The fference between the actual
power supply costs of 29.41 $/MWh incurred to serve new
customers and the 7.30 $embedded cost proposed
the Company would be collected from customers through the
PCA and flowed through to Idaho Power Company
shareholders.In other words the Company would collect
power supply costs from new customers through base rates
and collect 22.11 $/MWh (29.30) for new
through a PCA surcharge.While the Company has argued
that the revenue it receives from new customers does not
cover all the incremental costs of adding them, the EARG
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
proposed by the Company amounts to a windfall that more
than recovers power supply costs.As I have previously
sta ted, a general rate case, rather than the is the
appropriate place to recover load growth related power
supply costs.Therefore, Staff recommends that the
Commission adopt its Expense Adjustment Rate for Growth
of 29.41 $/MWh to eliminate the shareholder windfall and
maintain the integrity of the PCA.
CLOUD SEEDING
What is your understanding of the Company
cloud s program?
Several years ago, members of the Commission
Staff, including mysel f, met with Idaho Power Company to
discuss cloud seeding.At that time the Company was
considering a pilot program to seed clouds in the upper
Payette River drainage.The Company s goal was to
provide more precipi ta tion in that area in the form of
snow that would melt dur the summer and provide
addi tional water to the Company s hydro facilities,
allowing it to generate more electrici
Part of the reason for the meeting had to do
wi th the effects on the PCA f such a proposal.To the
extent more water could be provided to generate more
electrici ty, the value of that electricity would be
captured by the PCA and substantially (90 ) passed back
CASE NO. IPC-03-02/20/04 (Di)HESSING , K.Staff
to ratepayers.This would leave customers with the
benefi ts and the Company s shareholders with the costs.
The Company not be ieve stribut of costs
and benefits to be fair.One al ternati ve discussed was
to allow the Company to include the costs of cloud
seeding in the PCA so that customers would pay the costs
and receive the benefits.Of course, if the benefits did
not exceed the costs, the loss would be passed to
customers through PCA rates.
Another a ternati ve for cost recovery discussed
at the meet was that the Company the
program and incur and book the costs.The next general
rate case would then pick up a test year that included
the costs, at which time they could be discussed and the
Commiss could choose to or rej ect them.
Rather than seeking recovery through the PCA,
the Company has included cloud seeding costs for the 2003
test year in this case.Those costs include $897, 48 in
operation and maintenance expense (Account 536) and
$214,600 in capital costs (Account 101).
Does Staff have a position regarding the
recovery of these sts in the current case?
The Company did not provide enough information
in its filing for Staff to make a recommendation on the
meri ts of cloud s For example, the Company did
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
not state whether the program has created measurable
precipi ta tion and, if so, how much.Wi thout more
information it is not possib e to evaluate whether the
cloud se I f thecosts were prudently incurred.
Company does not provide additional information in this
case, Staff recommends that all cloud seeding costs be
removed.
What information does Staff believe should be
provided by the Company to allow an adequate opportunity
to evaluate the requested cost recovery?
Given the experimental and somewhat
controversial nature of cloud seeding programs and the
sizable amount of money requested to be included in rates
on an annual basis, Staff believes the Company should
address the foIl lssues:
1 )What acti vi ties constituted the cloud
seeding program in past years, including the test year,
and what are the Company s cloud se plans for
upcoming years?
2 )What criteria will the Company use to
determine the level of cloud seeding acti vi ty and
expendi tures necessary In any year?
How does the Company evaluate whether cloud
seeding works and that the benefits exceed the costs?
4 )What would be the effect on the Company
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff
cloud seeding program if the Commi Slon denied recovery
of the costs requested in this case?
Does this conclude your direct test
this
Yes, it does.
CASE NO. IPC-03-02/20/04 (Di)HESSINGStaff