20040803Vol VI Part II.pdf

Please state your name and business address
f or the record.
My name is Rick Sterling.My business
address is 472 West Washington Street , Boise, Idaho.
By whom are you employed and in what
capaci ty?
I am employed by the Idaho Public Utilities
Commission as a Staff engineer.
What is your educational and professional
background?
I received a Bachelor of Science degree in
Civil Engineering from the University of Idaho in 1981 and
a Master of Science degree in Civil Engineering from the
University of Idaho in 1983.I worked for the Idaho
Department of Water Resources from 1983 to 1994.In 1988,
I became licensed in Idaho as a registered professional
Civil Engineer.I began working at the Idaho Public
Utilities Commission in 1994.My duties at the Commission
include analysis of utility applications and customer
pet it ions.
What is the purpose of your testimony in this
proceeding?
The first purpose of my testimony is to
discuss the Company s weather normalization.Another
purpose is to detail the test year power supply
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adj ustments proposed by Avista and describe my
investigation of those adj ustments.I will also discuss
Avista s investments in the Coyote Springs 2, Kettle Falls
CT and Boulder Park proj ects
Are you sponsorlng any exhibits?
I am sponsoring Staff Exhibit Nos. 128Yes.
through 131.
Please summarlze your testimony.
My review of the Company s weather
normalization consisted of replicating the results
obtained by the Company, in addition to evaluating the
effects of varying the weather data and period of record
used in the Company s analysis.I conclude that the
weather normalization performed by Avista is accurate and
reasonable, and recommend that it be accepted.
The test year power supply adj ustments
proposed by the Company in this case consist of
contractual changes due to new or expirlng contracts, and
changes due to specific contract rates or terms; and power
supply cost adjustments for normalized loads and water
condi tions.As a resul t of these adj ustments, the Company
has proposed a net, system-wide decrease in ~est year
expenses of $30.5 million.
My investigation of test year power supply
adjustments included evaluation of known and measurable
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changes through August 2005 and replication of the
Company s dispatch simulation model and evaluation of its
inputs and assumptions.I specifically focused on short-
term sales and purchases and long-term whdlesale sales and
purchase contracts.
I found that the power supply pro forma
adj ustments proposed by the Company adequately reflect
known and measurable changes that will occur through
August 2005.I also found that the dispatch simulation
model adequately reflects anticipated dispatch of Company
resources, the availability and price of regional surplus
energy, the normalization of hydro resources, and the
normal cost of fuel for Company-owned thermal resources.
Therefore, as a resul t of my investigation, I recommend
that the Commission accept the power supply adj ustments
proposed by the Company.
Based on my reVlew of the Company s decision
to pursue the Coyote Springs 2 proj ect (CS2), I concluded
that the Company s need for power justified the decision.
My review of the Request for Proposal (RFP) process also
led me to conclude that the process was fair and that the
CS2 proj ect was the best al ternati ve.Because the proj ect
was transferred from Avista Power to Avista Utilities
cost, I believe that it was appropriate to consider the
proj ect as an al ternati ve in the Company s RFP eval uation.
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Despi te the problems caused by the bankruptcy of the
construction contractor , and the numerous problems
experienced wi th the generator step-up transformer, I
believe Avista did all it reasonably could to minimize the
construction delays and the cost overruns.
The Kettle Falls CT and Boulder Park proj ects
were pursued to obtain some relief from the extremely poor
water conditions and high market prices in 2000 and 2001.
I reviewed the Company s analysis justifying the Kettle
Falls proj ect and conclude that it was reasonable given
the circumstances at the time.In reviewing the Boulder
Park proj ect, however , I found that there were exceptional
cost overruns and delays.While some of the cost overruns
and delays were unavoidable, others could have been
avoided if Avista had better planned and managed the
proj ect Because the cost overruns and delays were so
excessive, I contend that ratepayers should not be stuck
with all of the excess costs and recommend that ten
percent of the proj ect investment not be allowed in rate
base.
WEATHER NORMALIZATION
What is the purpose of weather normalization?
Customer energy usage in the test year
typically higher or lower than normal due to unusually
warm , cold, wet or dry weather.The purpose of weather
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normalization is to adjust test year customer energy usage
to reflect a level of usage that would reasonably be
expected in a year with normal weather conditions.
Normalized customer energy usage is then used to establish
retail sales revenue that can be expected in a normal
year.It is also used to determine the demand that must
be met by the Company s generation or purchased resources,
thus it affects the normalized net power supply expenses.
Have you reviewed the weather normalization
performed by the Company in this case?
Yes, I reviewed it in detail.I replicated
the method used by the Company in order to verify the
accuracy of the Company's resul ts.I also varied the
analysis by using weather and customer usage data for
different periods of record than used by the Company.
also examined different weather variables.In addition, I
performed weather normalization analysis for each of the
Company s customer classes to determine which classes are
sensitive to weather conditions.
Avista made separate weather normalization
adjustments for usage by its electric and its gas
customers.Did you review the Company s weather
normalization for its gas customers?
Yes, I conducted a similar reVlew of the
Company s gas weather normalization as I did for the
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electric weather normalization.The techniques and
weather variables used by the Company were nearly
identical for both the electric and gas weather
normalization.
What is your oplnlon of the Company I s weather
normalization?
I believe the Company's weather normalization
fairly and accurately adjusts test year energy consumption
and that no further adj ustment to the weather
normalization proposed by the Company lS necessary.
POWER SUPPLY EXPENSE AND REVENUE ADJUSTMENTS
Why is it necessary to make adjustments to
the test year power supply costs?
The Company s adjustments to the 2002 test
period power supply revenues and expenses are designed to
reflect the normalized level of revenues and expenses, and
to include known and measurable changes to the revenue and
expense items.The purpose of the adjustments is to come
up wi th revenues and expenses that can be reasonably
expected going forward with the rates that are established
by the Commission.
What are the primary differences in net power
supply costs since Avista ' s last general rate case in
1997?
Net power supply costs in this case are
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approximately $11 million (Idaho share) higher than in the
last general rate case in 1997.The two primary changes
include a reduction in wholesale sales revenue (PGE
capacity sale) of $6 million , and an increase in net fuel
expense for thermal generation (primarily Coyote Springs
2) of $4.5 million.
Have you reviewed the testimony of Company
wi tness Johnson and the power supply adj ustments shown in
Exhibi t No.1 0 , Schedule
I have reviewed Mr. JohnsonYes.
testimony, Exhibit No. 10, Schedule 1, Company workpapers
that support the exhibi t and Company responses to Staff
production requests.
What are the primary reasons for the proposed
power supply adjustments?
There are two prlmary reasons for the
proposed adjustments to the 2002 test year power supply
revenue and expenses.The maj ori ty of the adj ustments are
associated wi th contracts.These can be due to the
expiration of an existing contract or the ini tiation of a
new contract, or due to specific, proj ected or estimated
changes in contract rates or charges.The remaining
changes result from the dispatch simulation model, and
mostly incl ude proj ected fuel expenses.
Staff Exhibit No. 128, entitled 2002 Test
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Year Power Supply Adj ustments, provides a categorical
breakdown of total Company power supply expense and
revenue adj ustments.Expenses have been reduced by $85.
million and revenues have been reduced by $55.4 million
for a net decrease In revenue requirement of $30.5 million
from the 2002 test year.
Please generally describe the types of power
supply adjustments summarized in Staff Exhibit No. 128.
Avista has made 67 pro forma power supply
adjustments to 2002 test year actuals to reflect power
costs for the twelve-month period beginning September
2004 and ending August 31 , 2005.Fifty-two of these
adj ustments are to test year expenses, while
adj ustments are to test year revenues.Many 0 f the
adj ustments are associated with changes in wholesale power
contracts from 2002 through August 2005.Some of these
adj ustments reflect new or explrlng contracts, while
others reflect contractual rate and cost changes for
services purchased, services rendered and acquisition of
fuel supplies over the same period.In some cases,
adjustments are based on specific contractual rates
applied to historical averages or estimates for such
things as generation or transmission quanti ties.The
remalnlng adjustments have been categorized as power
supply, and are the resul t of output from the Company
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dispatch simulation model under normal load and water
condi tions.
What prlmary criterion did you use to decide
whether a proposed adjustment is reasonable?
The primary cri terion is whether the
adjustment is known and measurable.
Are the power supply adjustments proposed by
the Company and presented by Mr. Johnson reasonable?
I have reviewed the workpapers. provided
the Company for each of the proposed power supply
adjustments presented by Mr. Johnson and recommend that
they be approved as proposed.There is little question
that the specific changes such as new contracts, expired
contracts, and contract-specific changes in rates or
charges occur at a date certain and are therefore known
and measurable.When expense and revenue adjustments
shown on line 4 of Staff Exhibit No. 128 are combined,
this category of adjustments represents approximately a
$7.09 million increase in power supply revenue requirement
(Net adjustment in power supply costs = Net adjustment in
expenses - Net adjustment in revenues, or -$11.172 million
- (-$18.260 million) = $7.088 million)
When the expense and revenue adj ustments
shown on line 8 that represent estimated, proj ected and
miscellaneous contract changes are combined, they
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represent a decrease in power supply expenses of $34.
million.Although these changes are not all specifically
stated within a contract, I believe 'they represent
reasonable estimates based on historic averages, proj ected
third party budgets or historic service costs or revenues
under existing contracts.
Power Supply adjustments , the final category
of expense and revenue adjustments, are from the dispatch
simulation model and are shown on lines 10 and 11 of Staff
Exhibi t No. 128.After analysis of the simulation model
examination of Company workpapers and review of production
request responses , I believe that the adjustments for
short -term sales and purchases, and fuel price changes for
thermal resources are reasonable.When added together,
this category of adjustments represents a decrease of
$3.53 million.I will discuss the dispatch simulation
model and the associated adj ustments in more detail later
In my testimony.
How did you evaluate the Company s proposed
adjustments for contracts?
I reviewed the workpapers provided by the
Company, which in some cases consisted of the contracts
themselves and in other cases consisted of excerpts from
the contracts showing the rates and terms that would
affect power supply costs.The workpapers showed
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beginning and termination dates of the contracts, the
quantities and delivery schedules, and the rates for
purchase or sale.
Are there some contracts for which
adjustments have been made where a precise rate is not
specified?
Yes, there are some.For those contracts the
adjustments were based on estimates made by the
contracting parties.
There appear to be very large power supply
adj ustments in both expenses and revenues in the
miscellaneous " category (line 7) of your Staff Exhibit
No. 128.Please explain why these adj ustments are so
arge
Nearly all of the adjustments in this
category, both on the expense and the revenue side, are
attributable to gas that was purchased, but not consumed,
for generation during the 2002 test year.The pro forma
expense for this gas is zero since it is assumed that all
gas purchased will be used for generation.Similarly, the
pro forma revenue for this gas is also zero since there
would normally be no gas to sell.
The second most noticeable adj ustments are In
the "short-term purchases/sales " category (line 10) of
your Staff Exhibit No. 128.Please explain why these
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adj ustments are so large.
The short-term market purchases and sales
adj ustments are based on output from the dispatch
simulation model (AURORA)The adj ustments are the
combined effect of differences from the 2002 test year in
both the quantities of purchases and sales, and the prices
of those purchases and sales.In general, there would be
fewer short-term purchases and more sales in a normal
year.This reflects the fact that the CS2 plant would be
available in a normal year , and the fact that 2002 was
below normal for hydro generation.
The final category of large adjustments is in
fuel expenses (line 11 of Staff Exhibit No. 128)Please
explain this adjustment.
Fuel expense adjustments are based on the
results of the Company s system dispatch model.The
maj ori ty of the fuel expense increase is associated wi
operation of the CS2 plant.The Boulder Park and Kettle
Falls CT proj ects also contribute to this adj ustment.
Note on Staff Exhibit No. 128 that the increase in fuel
expense is more than offset by a net decrease in the cost
of short - term purchases and sales.
Do you believe it is appropriate to pro form
the normalized 2002 test year power supply expenses to the
period of September 1, 2004 through August 31 , 2005?
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Yes, I believe that it is appropriate to
allow adjustments that reflect power supply cost during
the period proposed for several reasons.First, as
previously discussed, all of the adjustments must be
reasonably known and measurable to be considered
reasonabl e Second, the adjustments must be based
strictly on test year loads and be independent of future
retail load condi tions.Finally, by the time the rates go
into effect in this proceeding, we will be at the
beginning of the pro forma period and the test year will
be more than two years old.
Is it unusual in a general rate case to pro
form test year power supply expenses to a period more than
two years later than the test year, in this case from
2002 test year to a pro forma period of September 1, 2004
through August 31 , 2005?
In Avista s last general rate case, CaseNo.
No. WWP-98-11, the Company used a 1997 test year and a
pro forma power supply period of July 1 , 1999 through June
30, 2000.Thus, the pro forma period followed the test
year by about two and a half years.
By using a pro forma power supply period
September 1, 2004 through August 31, 2005, do you believe
there is any potential for a mismatch between revenues and
expenses?
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There is always a potential for a mismatch of
revenues and expenses.That is why we typically use a
historical test year and try to limit adjustments as much
as possible.In using a historic test year and making
prospective adjustments, it is very important to make only
those adjustments that are known and measurable.I have
carefully reviewed each of the power supply adjustments
proposed by the Company and believe all of them are
reasonably known and measurable.
But isn t it possible that the Company
power supply adjustments include known expense increases
and known revenue decreases due to ei ther new or expired
contracts , but not include potential revenue increases due
to unknown future events and prices?
If Avista has contracts that explre and are
not replaced during the pro forma period, the dispatch
simulation model will either buy or sell generation to
replace the effect of the contract.Thus, for example, if
a power sales contract expires before the end of the pro
forma period leaving Avista with surplus generation for
some period of time, the system dispatch model will simply
sell the surplus into the market at whatever prices the
model computes.Thus , the revenue lost when the contract
expires is replaced by revenue determined by the system
dispatch model.Similarly, if a purchase contract by
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Avista explres , the model will purchase replacement
resources from the market at computed prices.Al t houg h
the purchase and sales prices computed by the model are
not precisely known and measurable, they are as accurate
as can be determined, short of having a contract in-hand.
Moreover, they are no less accurate than the normalized
fuel expenses.
According to Mr. Storro s testimony at page
, lines 6 - 9, Avista ' s annual net resource energy position
does not become deficient until 2008 and beyond, and the
Company s capacity position is either surplus or nearly
balanced through 2007.Is it possible that the Company
surplus is too large, resul ting in increased costs but not
proportionately increased revenues?
It is important to realize that the Company
surplus condition is on an annual basis, and that there
are times during the year when the surplus is ei ther
greater or less than the annual average.Avista operates
its own resources to make economy sales in the market
whenever its resources are not needed to meet its own
load.However , if those resources cannot be economically
operated to make off-system sales, they sit idle.
Nevertheless Avista still may need all of its resources
times, and must always maintain a required reserve margin.
(Avista currently maintains a reserve margin of about 15%
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based on forecasted peak loads.In addition, Avista is
required by the Western Electricity Coordinating Council
to maintain an operating reserve equal to 5% of its hydro
generation and 7% of its thermal generation capacity)
Having too great of a surplus can indeed cost the Company
and its ratepayers more.However, I do not believe that
Avista has an unacceptably large surplus.Further, I
believe the planning cri teria used by the Company for
deciding whether and when to acquire new resources
appropriate.
Is it unusual to have 67 power supply expense
and revenue adjustments in a general rate case?
No.In Avista s last general rate case there
were 97 power supply adj ustments.As I stated earlier,
the maj ori ty of the adj ustments in this case are
contract~ally related, and the remaining adjustments are
pro forma fuel cost adjustments.
DISPATCH SIMULATION MODEL
Has Avista done anything differently from its
1997 general rate case in terms of analysis using a
dispatch simulation model?
The primary difference is that theYes.
Company is now using the AURORA model.AURORA dispatches
resources on an hourly basis, unlike the previous model
that used a monthly time step.An hourly dispatch more
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accurately reflects the true system dispatch of Avista ' s
resources and of other generation resources throughout the
reglon.The use of hourly data also more accurately
recognizes hourly load variations and properly evaluates
the costs and benefi ts of peaking resources.In my
opinion, the adoption of an hourly dispatch model is a
substantial improvement over prior system dispatch models,
and I am more comfortable wi th the resul ts it produces.
You stated that the power supply adjustments
proposed by Mr. Johnson were reasonable.How did you
evaluate the adjustments that result from running the
dispatch simulation model?
The first step in evaluating the power supply
expense and revenue adjustments was to replicate the
Company s results using the AURORA model.Through its
software licensing agreement, Avista has provided Staff
wi th a copy of the model.Avista has also provided Staff
wi th a complete copy of all input data that it used in its
analysis.By replicating the Company s results, I was
able to better understand the relationships between energy
demand, supply energy and market conditions throughout the
reglon.I then evaluated the hydro generation and
regional resource input data provided mostly by third
parties , the long-term contract demand obligations
adj usted in the pro forma test year, the monthly energy
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calculated by the model for short-term purchases and
sales, and the generation and cost for each Company-owned
thermal resource.The final step was to evaluate the
effect of different natural gas prices on the annual fuel
cost for the Company s thermal resources.
How do you know that the hydro condi tions
assumed by the model represent normal water conditions?
In the model , hydroelectric generation for
the Northwest was based on the Northwest Power Pool'
2000-2001 Headwater Benefits Study.The study provides
generation estimates for northwest hydroelectric plants
including Avista s plants, utilizing current regulation
and sixty water years (1929-1988) of historical stream
flows.Because AURORA dispatches resources throughout the
WECC, data sets for plants outside of the Northwest (e. g.
Canada and California) were also used.These data sets
were provided by EPIS, the developer of AURORA, and are
based on information from Canadian sources and from the
U. S. Department of Energy.Because the hydro data used in
this rate case has been developed by independent sources
for a variety of uses by many different utili ties, I
believe it fairly reflects normal water conditions and
produces unbiased resul ts.
It would seem that the resul ts of the
dispatch simulation model would be highly dependent on the
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fuel prlce assumptions used in the model.Did you reVlew
Avista s fuel price assumptions and do you believe they
are reasonabl
It is true that the resul ts of the dispatch
simulation modeling are highly dependent on the fuel price
assumptions used.For its analysis, Avista used actual
contract prices for its coal plants and for its wood- fired
Kettle Falls plant.For its gas-fired plants, the Company
used Henry Hub NYMEX natural gas forward prices on
December 10 , 2003 for the power supply pro forma period.
Avista then adj usted the Henry Hub prices using basis
differentials intended to capture ancillary costs such
transportation and taxes.A different set of gas prlces
was derived for Coyote Springs 2, Rathdrum, and the
combination of Boulder Park , Northeast and the Kettle
Falls CT.The source used by Avista for these prlces was
the same system the Company uses to make gas fired
resource dispatch decisions.
Because the modeling resul ts are so highly
dependent on gas prlces, I investigated gas price changes
and their effect on annual expenses.I first examined a
historical record of NYMEX forward prices for delivery in
each month of the pro forma period.I reviewed historical
daily NYMEX forward prices from April 2003 - April 2004 to
determine whether the December 10, 2003 prices used by
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Avista were unreasonably high or low.In my judgment,
Avista did not choose a particularly high or low priced
day.Generally, gas prices have steadily increased Slnce
December 10 , 2003 when Avista chose prices for its
analysis.
Nevertheless, to analyze the effect of gas
prlces on net power supply costs; I estimated gas prices
that were lower and higher than the prices used by Avista.
In the low price scenario, I selected prices on May 1
2003 because they were nearly the lowest of any day in the
past twelve months.For the pro forma period, the prices
averaged about $4.77 per MMBtu.For the high gas prlce
scenarlo, I selected futures prices on May 5, 2004 because
they were close to the highest on any day in the past
twel ve months.The average price in the pro forma period
under the high price scenario was approximately $6.09 per
MMBtu.Using these high and low gas prlce scenarios, I
determined a corresponding range of thermal fuel costs to
be $46.32 million to $63.49 million.The thermal fuel
cost computed by Avista using its December 10 , 2003 fuel
prices is $50.0 million.Based on the range I computed
for high and low gas prices, I concluded that the gas
prices Avista used in its modeling are reasonable.
How cri tical is it that Avista use accurate
gas prlces in determining its net power supply costs?
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Of course, it is desirable to use gas prlces
that are close as possible to what the Company will
actually encounter.It is impossible to know these prlces
in advance, however.Nevertheless, if gas prices are
estimated too high or too low , deviations in actual net
power supply costs will be captured in the Company
annual power cost adj ustment (PCA)Under the PCA, Avista
is entitled to recover or refund to customers up to
percent of deviations from normal.This sharing between
the Company and its customers helps to minimize the built-
in incentive for Avista to establish its base net power
supply costs too high.Again , I do not believe Avista
chose to use December 10 , 2003 gas prlces In an effort to
set its base net power supply costs high.Instead, I
believe the gas prices chosen by Avista are reasonable.
po you recommend any changes in the thermal
fuel adj ustments proposed by the Company?
I believe that the dispatch simulationNo.
model adequately estimates the amount of energy that will
be generated at each resource under normal water
condi t ions.I also believe that the fuel price changes
proposed by the Company are reasonable based on my reVlew
of Company workpapers.
Does the dispatch simulation model include
speculative sales or purchases?
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No.The dispatch simulation model includes
only Avista s hourly native loads, so resources are
dispatched to meet only those loads.However, whenever
Avista has resources of its own that can be operated
economically to meet other loads in the region, they will
be operated and the revenues will accrue to Avista and its
customers.Similarly, Avista regularly makes off -system
purchases whenever its own resources are insufficient to
meet load.These off-system purchases and sales are not
speculative and therefore are appropriately included in
power supply modeling.
COYOTE SPRINGS 2
When did Avista first identify a need for the
Coyote Springs 2 proj ect?
In July 2000, Avista submitted an update to
its 1997 Integrated Resource Plan (IRP)The updated 1997
IRP served as the basis for a Request for Proposals that
the Company intended to release in August 2000.In the
1997 IRP update, Avista s load-resource balance showed
that the Company was defici t, both for energy capaci ty,
beginning immediately and extending throughout the entire
planning horizon.Deficits in 2000 were 395 MW of peak
capaci ty and 237 aMW of energy.One of the primary
reasons for the deficits was the sale of the Company
share of the Centralia plant.Avista had a contract to
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purchase output from Centralia after the sale, but that
contract expired at the end of 2003.A second reason for
the expected deficits was a decreased reliance on long and
short -term contracts, in part due to their risk and the
recent volatility in market prices.I believed that the
Company s need for new resources was sufficiently
demonstrated in the 1997 IRP update and I supported the
Company s decision to issue a Request for Proposals.
Do you believe the RFP issued by Avista was
fair?
Yes, I believe the RFP was fair.Staf f
reviewed preliminary drafts of the RFP prior to its
release and provided comments to Avista.All of Staff'
comments, both written and verbal , were addressed by
Avista in the preparation of the final draft RFP.Avista
then submitted the draft RFP and its 1997 IRP Update to
the Commission for comment.Commission Staff commented
noting that it believed that issuing the RFP was
appropriate.The Commission issued Order No. 28542 noting
that the Company s filings of its 1997 IRP Update and the
RFP were informational and were not required by statute or
Commission Order.The Company solicited only comment;
therefore, Commission approval was not necessary.The
Commission commended Avista for soliciting public input
into its RFP process.
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" 4
Avista s RFP was an "all source " competitive
bid based on the Company s identified need for 300 MW of
new electric power starting in 2004.The 1997 IRP Update
described the Company s loads and resources, provided an
overview of technically available resource options, and
demonstrated need for resources.
In its filing with the Commission, the
Company stated that it would consider any offer of
resources including but not limited to, energy and
capaci ty, energy eff iciency, turnkey plans, construction-
for Avista-of a generating plant on a si te provided by the
bidder, and construction by a bidder on a site furnished
by Avista.
I believe that the RFP was fair in all
respects, and not intended to favor specific proposals,
locations, technologies or bidders.
Briefly describe the response Avista received
In response to the RFP.
Thirty-two proposals were received from
bidders for a total of 2,700 MW of resources in response
to the all-resource RFP.The proposals included 24 offers
for new generation, six of which were for renewables, one
customer-owned emergency generation proposal, and seven
energy efficiency proj ects.
Do you believe that the evaluation criteria
CASE NOS. AVU-04-1/AVU-04-
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STAFF
(Di) 24
1212
developed and used by Avista were fair to all proposals?
Avista went to great lengths to insureYes.
that the evaluation criteria it developed were fair and
impartial.Besides seeking input from the Idaho and
Washington Commission Staffs, it retained R.W. Beck , an
engineering consul t ing company, to al so review the
evaluation criteria.R. W. Beck made recommendations on
the evaluation criteria and on the assumptions to be used
in analyzing proposals, and on the dispatch modeling and
economic analysis used by Avista.
Do you believe it was appropriate to consider
the Coyote Springs 2 proj ect as an al ternati ve, Slnce
rights to develop the proj ect were owned at the time by
Avista Power , an unregulated Avista Corp. subsidiary?
Yes, I do believe it was appropriate.
participated in meetings with Avista and with a
representative from the Washington Commission Staff in
which this issue was specifically discussed.My opinion
and the opinion of the Washington staff member was that
CS2 should be considered as an alternative as long as the
proj ect assets at the time (permi ts , si te, turbine
contract, rights to develop, etc.) would be transferred at
cost to Avista Utilities.Early on in the proposal
evaluation phase, it was apparent that the CS2 project
could be a very competitive proposal.It was fel t that
CASE NOS. AVU-04-1/AVU-04-
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(Di) 25
1213
excluding it might eliminate what could ultimately be
Avista s best and least cost option.
Do you believe there was any impropriety in
the transfer of rights to the CS2 proj ect from Avista
power to Avista Utilities?
No, because the transfer was made at cost.
Staff auditors have reviewed the transaction and have
assured me that the transfer was indeed at cost.Neither
Avista Power nor the shareholders of Avista Corp. made any
prof i t from the transfer.
What was Staff's involvement in the RFP
process?
I participated on behalf of the Idaho
Commission Staff.I reviewed and helped develop
evaluation criteria, and reviewed the results of Avista
analysis of proposals.I participated in several meetings
with Avista and a representative of the Washington
Cornmission staff to review Avista s evaluation and ranking
of the proposal s .We reviewed the Company s first round
screening results and provided input into the decision
about which proj ects should move on to the second round
screenlng.We also identified things we believed needed
further investigation before further evaluation and
ranking could take place.During the final screening
process, we reviewed in detail Avista ' s economic analysis
CASE NOS. AVU-04-1/AVU-04-
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STAFF
(Di) 26
1214
as well as all the other factors that were used in
assesslng the proposal s
just days before Avista
the Board Directors.
I also attended a final meeting
staff made their recommendation to
Are you convinced that Avista chose the best
least cost proposal?
The Company ' s selec~ion of CS2 asYes, I am
a resource from its 2000 all-resource Request for
Proposals process was reasonable.
Do you believe it was reasonable to sell half
of CS2 to Mirant?
Yes , I do believe it was reasonable, gl ven
the financial challenges facing the Company at the time.
I reviewed the analysis done by the Company of the options
available at the time.Although it would have been
desirable to have more interested bidders in the plant, I
believe that the Company s analysis supports the decision
to sell half of the plant to Mirant.
Avista witness Lafferty s testimony includes
extensive discussion of the litany of problems experienced
during the construction and start-up of CS2 , along with
the costs associated wi th those problems.Do you believe
that the cost overruns that resul ted from these problems
should be allowed in rate base?
The problems and associated cost overruns
CASE NOS. AVU-04-1/AVU-04-06/21/04 STERLING, R.
STAFF
(Di) 27
1215
seemed to be associated primarily with two factors, the
bankruptcy of Enron and ul timately of NEPCO, its
construction subsidiary, and failures of the generator
step-up (GSU) transformer.
I do not believe the bankruptcy of Enron and
NEPCO could have ever been envisioned at the time
construction on the proj ect began.There was virtually
nothing Avista could do other than try to. mi tigate the
effects on the CS2 construction costs and schedule.
believe Avista made a good effort keep costs under
control and to mlnlml ze construction delays following the
bankruptcies; therefore , I do not believe Avista or its
shareholders should be held accountable for any cost
overruns and delays caused by the bankruptcies.
Wi th regard to the repeated GSU transformer
failures, I believe that these too were beyond the control
of Avista.Decisions about the transformer design and
which manufacturer to select were not unreasonable.
Whenever problems were encountered , it appears Avista did
everything it could to make repairs or acqulre a
replacement.The Company also appears to have diligently
exercised warranties and pursued insurance claims.
The cost overruns associated with these
problems have been estimated by Avista to be approximately
$15 million.This amount represents 16 percent of the
CASE NOS. AVU-E- 04 -l/AVU-G- 04-
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STERLING, R.
STAFF
(Di) 28
total original proj ect cost estimate of $93.9 million.
Staff does not oppose inclusion of. these costs in rate
base for the CS2 plant.
KETTLE FALLS CT
Why did Avista build the Kettle Falls gas-
fired combustion turbine (CT) project?
The Kettle Falls CT proj ect was one of at
least five potential generation projects identified as
possible solutions to help mitigate the effect of very low
water conditions and extremely high and volatile electric
prices that occurred during the June 2000 through December
2001 period.Eventually the Company decided to pursue the
Kettle Falls CT proj ect and the Boulder Park proj ect, but
not pursue three small proj ects involving installation of
natural gas or diesel- fueled generators at other
locations.Two gas-fired engine generators like those
installed at Boulder Park were purchased by Avista for
installation at the Spokane Industrial Park , but were
never installed after power prices receded in late 2001.
Recovery of the cost of these generators is not being
requested in this case.
Have you reviewed the final cost of the
Kettle Falls CT proj ect?
The final cost of the Kettle Falls CTYes.
project as verified by Staff auditors is $9.2 million, or
CASE NOS. AVU-04-1/AVU-04-06/21/04 STERLING, R.
STAFF
(Di) 29
1217
approximately 8.2 percent above the estimated proj ect
cost of $8.5 million.
It appears the proj ect exceeded its cost
estimate by nearly $700,000.What does Avista attribute
the cost overruns to?
There are two primary reasons identified by
Avista.First, $543,000 in addi tional costs were incurred
because of additional work that had to be completed by the
proj ect contractor.Most of this work was associated wi
the construction cost of the turbine building.Second, an
additional $153,000 was incurred directly by Avista for
work outside of the scope of the contractor
responsibility.Of this amount, $133,000 was paid to the
contractor in accordance wi th contract requirements for
exceeding the performance requirements of the turbine.
Do you recommend that the full final cost of
the Kettle Falls CT proj ect be allowed in rate base?
Yes, I do.Despite the fact that the final
proj ect costs exceeded its original estimate and took a
little longer to complete than expected, I believe the
cost overruns were wi thin a reasonable range and not
unusual for a proj ect of this type.
BOULDER PARK
Was Boulder Park or an equivalent plant
included in Avista s 1997 or 2000 IRPs before the Company
CASE NOS. AVU-04-1/AVU-04-06/21/04
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STAFF
(Di) 30
1218
made its decision to pursue the proj ect?
The need for such a plant was notNo.
identified in any of the Company s previous IRPs.Avista
decided to pursue the proj ect primarily In response to the
extreme low water conditions and market prices in
2000-2001.
Do you believe it was reasonable for Avista
to develop the Boulder Park proj ect?
Yes, I do.Market prices at the time were
extremely high and no one knew if or when such high prices
might subside.Most utilities in the Northwest were
pursuing a variety of options for relief from the high
prices including diesel generation, gas-fired generation
customer buy-backs and demand management programs.Avista
also considered many of these options, and the Boulder
Park proj ect appeared to be one of the Company s most cost
effective al ternati ves.I thoroughly reviewed the
Company s analysis that it completed at the time a
decision was made to pursue the proj ect.At that time, I
believe a decision to proceed was reasonable.
What was the Company s estimated cost for
Boulder Park?When did the Company expect to complete
construction?
When the proj ect was first proposed , Avista
estimated the construction cost to be $21.0 million.
CASE NOS. AVU-04-1/AVU-O4-06/21/04 STERLING, R.
STAFF
(Di) 31
1219
12
June 17 , 2001, Avista revised its estimate upward to
$23.65 million.The original estimated completion date
was September 1 , 2001.
It appears that there were considerable cost
overruns and delays on the proj ect.Have you reviewed the
information provided by the Company in response to Staff'
production requests concerning cost overruns and delays?
Yes, I have.The final cost of Boulder Park
was approximately $32.1 million.This is $11 million more
than initially projected, and represents a greater than
50% cost overrun.Completion of construction was delayed
by eight months until May 2002.
What reasons does Avista gl ve for the cost
overruns and delay in completion?
In response to production requests,
Avista states that:
The excess costs for the Boulder Parkproj ect generally stemmed from the fast
track design-build approach that the
Company chose in order to bring small
generation on line as quickly as
practical in order to mi tigate the high
prices and volatility in the electric
power market during the energy crisis.Al though not new technology for the
power industry, the natural gas fired
reciprocating engine generators were the
first project of its kind for Avista,
which contributed in part to actual
construction costs being higher than the
original estimates.
Avista provided a summary by cost category of the amounts
CASE NOS. AVU-04-1/AVU-04-
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STAFF
(Di) 32
1220
of the cost overruns, along with a brief description of
the reasons for the cost variations in each category.
have included this summary as Staff Exhibit No. 129.
Do you believe the explanations cited by
Avista for the cost overruns are reasonable?
I believe that some of the explanations are
reasonable.Avista clearly did not anticipate many of the
problems encountered in the proj ect' s construction or many
of the requirements imposed on the proj ect by other
agencles.For example, the Company ci tes incomplete
construction plans being provided by the engine generator
manufacturer , handicapped building access requirements
road width requirements, paved instead of graveled si te
grounds , building soundproofing requirements and
construction plan approval delays as among the many
unexpected factors.I agree that many of these delays and
requirements could not have been anticipated.
Nevertheless, it is simply impossible to
19nore that the final proj ect cost exceeded the ini tial
estimate by nearly 53 percent.While many of the causes
of cost overruns could not be anticipated, I believe some
of them could have been if Avista had better planned and
managed the proj ect Blaming a fast track construction
process for cost overruns might make sense if the proj ect
had actually been completed on a fast track schedule, but
CASE NOS. AVU-04-1/AVU-04-06/21/04 STERLING, R.
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(Di) 33
1221
the fact is that construction took eight months longer
than expected.The higher costs due to the fast track
schedule apparently cost the Company quite a lot but
gained nothing.
It is common to include a contingency amount
in the cost estimate for large construction proj ects to
lnsure that funds are available in the event of unplanned
problems, circumstances or conditions.The amount of the
contingency can vary considerably for construction
proj ects depending on many things such as material and
equipment costs, installation complications and unknown
si te condi tions.Contingency amounts for proj ects similar
to this one are typically in the range of 5 -15 percent.
In fact , CS2 and Kettle Falls contingencies totaled 16 and
8 percent, respectively.Avista may not have any
experlence in building this particular type of plant, but
it should have some experience with building practices and
requirements in Spokane County, a place where it has buil
many things.
The explanations put forth by Avista may be
understandable , but the excessive cost overruns should
primarily be the responsibility of Avista.I believe
ratepayers should be able to expect the utility to have
the ability to construct proj ects at least cost.
Construction of new proj ects cannot simply be a blank
CASE NOS. AVU-- 04 -l/AVU-G- 04-06/21/04 STERLING, R.
STAFF
(Di) 34
1222
check signed by ratepayers.It is reasonable to expect
the utility to have the expertise and experience to
construct and manage any proj ect it undertakes at a
reasonable cost.
Do you recommend that all of the cost of the
Boulder Park plant be allowed in rate base?
No, I do not.I recommend that ten percent
of the final proj ect cost be disallowed.
What is the basis for recommendipg ten
percent disallowance?
In reviewing Staff Exhibi t No. 129, three
particular cost categories stand out.First, the final
construction management cost of $2,159,000 was 2.25 times
the revised proj ect estimate.This addi tional cost was
primarily due to the contractor being required to spend
twice the amount of time working on the proj ect.The
second cost category that stands out is $1,110\000 for
Avista s proj ect management, engineering and proj ect
commlsslonlng.There was no amount included for these
costs in the revised estimate.Finally, an addi tional
$912 714 was incurred because of the additional time
required to complete the proj ect The total" cost overrun
in just these three cost categories comes to $3,221 714
approximately ten percent of the total final proj ect cost
Undoubtedly, some of the cost overruns in these categories
CASE NOS. AVU-04-1/AVU-04-06/21/04 STERLIN~, R.
STAFF
(Di) 35
1223
would have occurred due to reasonable construction delays
and problems.However, it is also likely that there are
some unreasonable cost overruns spread throughout nearly
every cost category.Consequently, I believe a ten
percent disallowance from rate base is a fair amount.The
effect of a ten percent disallowance from rate base is a
reduction in annual revenue requirement of approximately
$205 000 on an Idaho jurisdictional basis.Staff wi tness
Patricia Harms further discusses this adj ustment in her
testimony.
I might also add that using the ini tial
construction cost estimate as the basis for judging the
reasonableness of the final construction cost is not
necessarily always fair.The initial estimate could be
low or inaccurate.
Have you examined any other evidence to
determine a reasonable cost for gas fired reciprocating
engines similar to Boulder Park?
Yes, al though cost information for these
types of englnes is somewhat difficul t to obtain because
there are few utilities or public entities that have
recently installed these types of units.Normally, uni ts
like these are installed by non-public entities such as
hospitals , institutions and industries for cogeneration or
backup purposes.Nevertheless, I was able to obtain some
CASE NOS. AVU-E- 04 -l/AVU-G- 04-06/21/04 STERLING, R.
STAFF
(Di) 36
1224
information for comparlson purposes.Six different recent
reports all reference the same source for cost figures.
Thus, I have included excerpts from only one report as
Staff Exhibi t No. 130.As second source ci ting a cost
range of $350 to $600 per kW is included as Staff Exhibit
No. 131.As shown by Staff Exhibit No. 130, total plant
costs range from $695 per kW for the largest units to
$1030 per kW for the smallest units.Boulder Park
consists of six units similar in size to the largest unit
shown in the exhibi t .Boulder Park's total plant cost
came to $1303 per kW.The ini tial estimate of the plant
cost was approximately $850 per kW.It is absolutely true
that actual costs for a specific plant could vary quite
significantly from the estimates shown in the exhibit;
however , Boulder Park's cost seems exceptionally high by
comparlson.Even wi th the ten percent disallowance
recommended by Staff, Boulder Park's cost would still far
exceed the estimates from other sources.
Does this conclude your direct testimony in
thi s proceeding?
Yes, it does.
CASE NOS. AVU-04-1/AVU-04-06/21/04 STERLING , R.
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(Di) 37
1225
(The following proceedings were had
open hearing.
(Staff Exhibit Nos. 128 through 131
having been premarked for identification, were admitted into
evidence.
MR. WOODBURY:And Staff has no further questions
and would present Mr. Sterling for cross-examination.
COMMISSIONER KJELLANDER:Okay.Let's move first
to Mr. Ward.
MR . WARD:Thank you, Mr. Cha i rman .
CROSS - EXAMINATION
BY MR. WARD:
Mr. Sterling, if I could quickly summarize your
testimony on Coyote Springs 2 , would it be fair to say that you
conclude that the RFP process was reasonable and that the
ul timate decision to purchase Coyote Springs 2 was
reasonable?
Yes, that's a fair characterization.
Would your views have been al tered if you had
known about the LJM two payment of three and a half million
dollars that was paid to Enron?
, I don't think it would have changed my
oplnlon.
1226
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
STERLING (X)Staff
Would your opinion have been altered if you knew
that Avista was paying Portland General approximately
$14 million for less than $4 million in assets?
No, I don't think that would have changed my
opinion ei ther.
And would it have been altered if you knew that
the -- collectively the Portland General and Enron profit was
close to $20 million on something less than $40 million (sic)
in assets?
, I don't think any of those things would have
changed , in my opinion, and the reason is that Avista had a
proj ect wi th a price to consider that proved to be less
expensive and a better alternative than the other things that
they had to consider.So even wi th those things, I think
was still a better deal for Avista than any other alternative.
Let me ask you a hypothetical:Assume for me
that the seller of the Coyote Springs 2 plant was a utility
wi th a single asset , Coyote Springs Can you make that
assumption?
Okay.
If that utility was then sold to Avista for
$20 million in excess of its net book value or its rate base,
what would - - what value would the Commission place on that
sale for rate base purposes?
Probably the net book value.
1227
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
STERLING (X)Staff
Why should it be any different in this case?
Well , in this particular case, Avista Utilities,
the regulated Company, actually, as far as I know , had no
involvement in the ini tial acquisi tion of Coyote Springs 2 by
Avista Power , so I don t think that was an al ternati ve that
Avista Utilities had.There was one price and one offer , and
that was all they had before them, as far as Coyote Springs
si te was concerned.
But in my hypothetical , how does that distinguish
this case from my hypothetical?In the hypothetical and, in
fact , in the real world , when this Commission reviews purchases
by a utility, it doesn't necessarily look to causation or
anything else when it evaluates what the rate base component of
the purchased utility will be, does it?
No, but I guess the reason that I'm having some
difficulty with your hypothetical is that assume that for a
moment that Avista Power was not even a part of the picture and
that the project was offered by some other utility at 59 and a
half to Avista Utilities , the same price that they ultimately
paid.In a case like that, I think the Commission would value
the proj ect at 59 and a half million.
When you evaluated
- -
when the evaluation was
conducted of the Coyote Springs 2 al ternati ve, how did the
evaluation account for the risk of construction; that is, the
risk that construction costs will be exceeded when compared to
1228
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
STERLING (X)
Staff
al ternati ves that offered fixed price?
I don t believe in any of the evaluations that
saw or that I was a part of discussed for any of the
alternatives that there was any risk analysis associated with
you know , what I s the risk that the proj ect might cost more than
what we estimate.Now , whether Avista did that, I don t know
but it was not something that I saw as a part of any analysis.
But doesn t anybody who I s even built a back-yard
fence know that there I s a risk of overrunning your proj ected
costs of the proj ect?
Yes, I would think so.
At the time, I think our concern
- - "
our" being
Staff
- -
we were more concerned that Avista Power not make a
profit as a result of transfer to Avista Utilities, and that '
why we insisted that it be at cost.But there was really not a
lot of thought given , at least on my part, to what will happen
if the proj ect costs more to build than what has been
estimated.
Okay, I want to follow that up a bit.I f you I d
turn to page 26 of your testimony, at the top of the page
there, you re asked a question beginning:Do you bel ieve there
was any impropriety in the transfer of rights to the CS2
project from Avista Power to Avista Utilities.
Do you see that question?
Yes, I do.
1229
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
STERLING (X)
Staf f
And would you read the first two sentences of
your answer?
, because the transfer was made at cost.Staff
audi tors have reviewed the transaction and have assured me that
the transfer was, indeed, at cost.
Now , when you were making that evaluation , did
anyone on the Staff conduct an examination or analyze the law
related to the permissible price for transactions between a
utility and its affiliates?
Not to my knowledge.
And so I assume there was no
- -
there was no
discussion of whether a utility has to transfer such assets at
the lesser of fair market value or cost?
There was no discussions that I was a part of.
One final thing, and it's more a philosophical
consideration than anything else, and I'm going to ask you a
very open-ended question:
Clearly, Mr. Sterling, it's probably a good idea
for Commission Staffs to sit in on major RFP evaluations.
don't think anybody would really quarrel with that.Bu t do you
think there I s some risk in having the same Staff member who
does that, who sits in on those evaluations, also be the
evaluator for rate base consideration?
And the reason I ask that, and I'm not suggesting
anything in this particular case, but in the long run, doesn'
1230
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
STERLING (X)Staff
the person who sits in on the evaluation tend to get invested
in the decision the Utility makes?
I think there's defini tely a risk of that, yes
and I think it's a legi timate concern.But I think it'
difficult with a Staff the size of ours to have more than one
person be brought up to speed on those sorts of issues, and so
I think out of necessity sometimes the same person has to be
involved in mul tiple aspects of an issue , and this was an
example of that.But I think it's a legitimate concern.
I understand.
MR . WARD:Thank you.That's all I have.
COMMISSIONER KJELLANDER:Thank you, Mr. Ward.
Mr. Cox.
MR . COX:I have no questions for this witness.
COMMISSIONER KJELLANDER:Mr. Purdy.
MR . PURDY:No questions.
COMMISSIONER KJELLANDER:And Mr. Meye r .
MR. MEYER:Just a couple follow-ons.
CROSS - EXAMINATION
BY MR. MEYER:
Mr. Sterling, you also examined the delays and
cost overruns associated with this proj ect, didn't you?
Yes, I did.
1231
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
STERLING (X)Staff
And I believe it was your testimony at page 4
lines 3 through 5 , that Avista, quote , did all it reasonably
could to minimize the construction delays and the cost
overruns.
Is that your testimony?
Yes, it is.
And I think you
- -
don't you build on that point
later on at page 21 and conclude that Avista made a good effort
to keep costs under control and to minimize construction delays
following the bankruptcies?
Yes.
MR. MEYER:That's all I have.Thank you.
COMMISSIONER KJELLANDER:Thank you, Mr. Meyer.
Are there questions from members of the
Commission?None.
We'll move now to redirect.Mr. Woodbury.
MR . WOODBURY:May I take a minute?
COMMISSIONER KJELLANDER:Yes.We'll go off the
record for just a moment.
(Discussion off the record.
COMMISSIONER KJELLANDER:We'll go back on the
record.Mr. Woodbury.
1232
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P. O. BOX 578, BOISE , ID 83701
STERLING (X)Staff
REDIRECT EXAMINATION
BY MR. WOODBURY:
Mr. Sterling, just a couple of follow-
questions to Mr. Ward's cross-examination:
In your knowledge of the RFP process for Coyote
Springs 2 and the way that that was structured, did Avista
Power have to reply to the RFP?
didn'
Well, I can'-- I'm not aware of how
, they didn't have to, and, in fact , they
And if
- -
excuse me?
Avista Power did not reply to the RFP.
How did the CS2 proj ect come to be the choice?
initially came about or the
- -
how it initially was conveyed to
Avista Utili ties that that proj ect would be available.But at
the time of my involvement, it was some time I believe after
the proposals were submitted, and it was some point in the
review process where Avista Utilities brought up the idea that
maybe Coyote Springs 2 should be considered as an al ternati ve.
I f Coyote Springs 2 were not the choice for a
selected resource , would the next available resource have been
higher?
Yes, I believe it would have been.
MR. WOODBURY:Thank you.Mr. Chairman , Staff
1233
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STERLING (Di)
Staff
has no further redirect.
COMMISSIONER KJELLANDER:Thank you.
And , Mr. Sterling, we appreciate your testimony
and presence here today.
(The wi tness left the stand.
HEARING OFFICER:Mr. Woodbury, we're ready for
your next wi tness
MR . WOODBURY:Staff would call Michael Fuss to
the stand.
MICHAEL FUSS,
produced as a witness at the instance of Staff , being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MR. WOODBURY:
Good morning, Mr. Fuss.Will you please state
your full name, spell your last name for the record?
Michael Fuss, F-
And, Mr. Fuss , for whom do you work and in what
capacity?
I work for the Idaho Public Utilities Commission
as a Staff engineer.
And in that capacity, did you have occasion to
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FUSS (Di)
Staf f
prepare prefiled testimony in this case consisting of 17 pages,
and two exhibits, Exhibits 136 and 137?
Yes, I did.
And have you had the opportunity to review that
testimony and those exhibi ts prior to this morning's hearing?
Yes.
And is it necessary to make any changes or
correct ions
No.
- -
to that testimony?
If I were to ask you the questions set forth in
your testimony, would your answers be the same?
Yes.
MR. WOODBURY:Mr. Chairman , I'd ask that the
testimony be spread on the record as if read, and that
Exhibits 136 and 137 be admitted.
COMMISSIONER KJELLANDER:wi thout obj ect ion , then
we would spread the testimony across the record as if read , and
admi t Exhibi ts 136 and 137.
(The following prefiled direct testimony
of Mr. Fuss is spread upon the record.
1235
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FUSS (Di)Staff
10 '
Please state your name and business address for
the record.
My name is Michael Fuss.My business address
lS 472 West Washington Street, Boise, Idaho.
By whom are you employed and in what capaci ty?
I am employed by the Idaho Public Utilities
Commission as a Staff engineer.
What lS your educational and professional
background?
I have a Bachelor of Science Degree in Civil
Engineering from Washington State Uni versi ty and a Master
of Business Administration Degree from Boise State
Uni vers i ty I am a licensed Civil Engineer in the states
of Idaho, Oregon , and Washington.I am a past president
of the Southern Idaho Section of the American Society
Civil Engineers and have been a member of various
professional affiliations and service organizations.
I have over 15 years of Civil Engineering
Experience in the areas of Municipal, Utili ty,
Regulatory, and Development Civil Engineering and
consul t ing
While at the Idaho Public Utility Commission
have attended the National Association of Regulatory
Utility Commissioners (NARUC) Basic Training Program,
Risk Management Techniques for the Natural Gas Industry
CASE NO. AVU-E- 04 -l/AVU-G- 04-
6/21/04
(Di)FUSS, M
STAFF
1236
at New Mexico State Uni versi ty and the Northwest Public
Power Association s course on Unbundled Cost of Service
Rate Design.
What is the purpose of your testimony?
My testimony pertains only to Avista ' s Natural
Gas (Gas) rate case.In my testimony I review the
Company s Natural Gas Jurisdictional Separation Study
(Separation Study) This separation study is used by
Avista to develop the Idaho gas unadj usted resul ts
operation.
I review the Company s Gas Cost of Service
(COS) Study, its method of incorporating the results of
operation adj ustments, and the development of the Class
Revenue Requirement.
I also review the Cost of Gas in base rates,
Gas Special Contracts, and recommend an addi tional
natural gas tariff sheet.
How is your testimony structured?
My testimony is structured as follows:
Summary
Gas Jurisdictional Separation
Methodology
Adj ustments
Cost of Service
Methodology
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04 (Di)FUSS, M
STAFF
1237
Other Studies
Adj ustments
Adj ustment Summary
Cost of Gas in Base Rates
Special Contracts
Tariff Summary Sheet Recommendation
Would you please summarize your testimony?
I have reviewed and recommend acceptance of the
Company s Gas Jurisdictional Separation Study using the
Four- Factor methodology wi th one minor adj ustment
I have also reviewed and recommend acceptance
of the Company s Gas Cost of Service Study known as the
Washington Accepted Methodology wi th exception of two
adj ustments.I recommend an adj ustment in usage wi thin
the pro forma revenue calculation that resul ts in an
increase of $23, 000 to current revenues.I also
recommend allocating storage expenses and credi ts based
on winter therm usage as opposed to the annual usage
proposed by the Company.
I recommend that the Company s request to move
the cost of gas in base rates to $0. 44989/therm
considered reasonable.I believe increasing the cost of
gas In base rates will reduce the overall magnitude of
future PGA adj ustments If actual gas costs increase,
the PGA adj ustment will be lower; and if actual gas costs
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04
(Di)FUSS, M
STAFF
1238
decrease, a PGA credi t is more likely.
I recommend acceptance of the Company
treatment of Idaho gas special contracts within the Gas
COS Study.I believe the Gas COS Study appropriately
allocates gas special contract revenues and expenses.
I recommend that the Company be directed to add
a tariff summary sheet to its gas tariff schedules.
believe the additional tariff sheet will not be
administratively burdensome for the Company and it will
provide clari ty for Customers.
GAS JURISDICTIONAL SEPARATION STUDY
Have you reviewed the Company s Gas
Jurisdictional Separation Study and do you have any
recommendations regarding the study?
Yes, I have reviewed the Company s Gas
Jurisdictional Separation Study and recommend that the
Commission accept the Separation Study with a mlnor
adj ustment The Separation Study uses the Four-Factor
methodology, a methodology first reviewed by Staff when
ini tiated by the Company in 1993.The Separation Study
is also consistent with the methodology used in Case No.
WWP-E- 98 -11, the last Avista Idaho Electric General Rate
Case.Furthermore, the general methodology of the
Separation Study has been approved for the Company in all
of its other operating jurisdictions.
CAS E NO. A VU - E - 04 - 1/ A VU - G - 04 - 1
6/21/04 1239
(Di)FUSS, M
STAFF
, 21
Me thodo logy
Please gl ve a brief description of the
Company s Gas Jurisdictional Separation Study
methodology.
Jurisdictional separation is performed in the
following steps.
Direct Assignment
All expenses , revenues, and rate base
investments that can be directly assigned are allotted to
the Idaho gas jurisdiction.
Utili tv Codes
For items not directly assigned , six utility
codes are used to assign expenses, revenues and rate base
to common cost categories.The categories are Avista
Electric, Avista Gas, WPNG (Avista Gas OR/CA) , Common to
Avista Electric and Avista Gas, Common to Avista Gas and
WPNG, and Common to Avista Electric, Avista Gas and WPNG.
Four-Factor
For common items the Company uses an allocator
composed of four factors to allocate these items to the
Idaho natural gas utili ty.The four factors are:Direct
O&M Expense excluding labor and resource costs, Direct
Labor , Number of Customers, and Net Direct Plant.
Other Allocators
The Company uses a number of other allocators
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04 (Di)FUSS, M
STAFF
1240
such as five-day firm peak demand, distribution operating
expens~ and number of customers to allocate the
appropriate Avista Gas costs to the Idaho gas
jurisdiction.
Adjustments
Do you recommend that the methodology from the
Company s Gas Jurisdictional Separation Study be accepted
wi thout change?
I believe that one mlnor adj ustment No.
necessary.
Would you please explain your mlnor adjustment?
I believe the Separation Study is inconsistent
in the allocation of plant investment, expenses, and
revenues in the following tax adj usting (Schedule "
accounts in report G- SCM-12A:1999.
Hardware/Software/Furniture Lease Payments, 1999.
Airplane Lease Payments, and 1999.14 Sale Leaseback of
General Office Building.In the Separation Study as
filed , the Company uses allocator 5 -Actual Therms
Purchased for these accounts.I believe this
incorrect.
In all other areas wi thin the Separation Study
where I reviewed the natural gas accounts 1999.09,
1999.13, and 1999., the revenue and expenses were
allocated using the four-factor allocator.The same
CASE NO. A VU - E - 04 -1/ A VU - G - 04-
6/21/04
(Di)FUSS, M
STAFF1241
Schedule "" accounts are also allocated using the four-
factor methodology in the Electric Jurisdictional
Separation Study.Therefore, I recommend that the
appropriate four-factor allocator be used to distribute
costs in the stated gas accounts.
What is the net affect of this adjustment?
Using the four-factor allocator on the listed
accounts reduces Idaho s share of taxes and the Idaho gas
net operating income by $1 , 888 .The Company in answer to
Staff Production Request No.1 79 confirmed the amount of
the adj ustment
GAS COST OF SERVICE STUDY
Methodology
Would you please describe the Company s Gas
Cost of Service (COS) Study?
Certainly, the Company s Gas cas Study is a
complex operation using three main Excel spreadsheets to
incorporate the results of operation, make adjustments,
functionalize, classify, and allocate expenses to develop
the revenue requirement for the various customer classes.
Output from the Gas COS Study is then used to help design
rates.The Company uses the spreadsheet " Proform " to
incorporate the resul ts of operation and make
adj ustments It uses the spreadsheet "Assign " to
functionalize, classify, and assign costs.As sign
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04
(Di)FUSS, M
STAFF
1242
contains varlOUS parameters used to develop allocation
factors and facilitate cost assignment.The final
spreadsheet "Sumcost" organizes the results and provides
a revenue requirement estimate for each customer class.
The Company s Gas Cost of Service Study also
incorporates a number of "other studies " used to
normalize the resul ts and create allocation factors.
Some of the other studies worth mentioning are the
weather normalization study, the Pro Forma Gas Revenue
Calculation , the Labor Dollars study, and the Weighted
Meter and Service Cost Analysis.
Other Studies
Would you please explain the significance of
these other studies and why these particular studies are
most important?
Certainly.The weather normalization study
important because natural gas usage is highly weather
dependant for most customer classes.The weather
normalization study uses regression analysis to determine
the amount of gas consumption that is weather dependant
for each customer class.It also relates the test year
weather pattern to a 30-year normal weather pattern and
adjusts the test year usage to reflect normal weather
condi tions.Staff wi tness Sterling s direct testimony
includes additional discussion on weather normalization.
CAS E NO. A VU - E - 04 - 1/ A VU - G - 04 - 16/21/04 (Di)FUSS, M
STAFF1243
The Pro Forma Revenue Calculation develops
normalized billing determinants (therms and customers)
adjusting the test year to reflect expected conditions on
average.This includes but is not limited to known
customer changes, weather normalization , and period
adj ustments The Pro Forma Calculation uses rates in
place during the test year to reflect the appropriate
normalized revenue generation by the various customer
classes.
The Labor Dollars Study is a study that is
embedded wi thin the Gas COS Study that determines labor
cost allocation.This study is important because it is
used to develop labor allocators used in the four- factor
allocator wi thin the Jurisdictional Separation Study.
The labor allocators are also used to allocate costs for
some labor related accounts.
The Weighted Meter and Service Cost Analysis
an engineering/economic study that calculates metering
and service costs for the various customer classes.This
study is important because it creates weighting factors
and cost relationships used to allocate a number of meter
and customer cost categories.
What is the purpose of the Gas Cost of Service
Study?
The Gas Cost of Service Study is an engineering
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04 (Di)FUSS, M
STAFF1244
economlc analysis that allocates expenses to establish
the revenue requirement based on cost causation.The
account-by-account study apportions each expense to the
various customer classes or rate schedules.The Gas Cost
of Service Study is the starting point in ultimately
establishing rates for each customer class.The resul ts
of the study provide an indication of the amount of
revenue that should be generated from rates for each
customer class or rate schedule.
Do you agree wi th the Company s Gas Cost of
Service Study?
Not entirely; there are any number of ways to
perform a cost of service study and any number of items
that can be used to allocate costs among customer
classes.Any individual or interest group could
reasonably argue for changes that would cause costs to
shift from one customer class to another.After a
detailed review of the Company s Gas COS Study, I believe
several small adj ustments are required.
Adjustments
What changes to the Company s Gas Cost of
Service Study do you recommend?
I recommend changes to the Company s Pro Forma
Gas Revenue calculation.The Company adj usts for known
and measurable changes in usage by adding or subtracting
CAS E NO. A VU - E - 04 - 1/ A VU - G - 04 - 16/21/04
(Di)FUSS, M
STAFF
1245
revenue in the Pro Forma Revenue Calculation.In Brian
Hirschkorn s workpapers GA1-GA5 adj ustments are made in
gas consumption to reflect actual condi tions, weather
normalization , and unbilled usage.The consumpt ion
reduction in Mr. Hirschkorn s calculation of revenue
associated with Schedules 111 and 112 double counts gas
revenue included in the monthly minimum charge.Double
counting the reduction causes an understatement of
approximately $23 000 in the Idaho Gas Pro Forma Revenue
Calculation.I recommend that addi tional revenue be
included in the Company s Gas cas Study to properly
reflect normalized revenues.
I further recommend adding consumption to the
normalized billing determinants used to determine
proposed rates.
What is the net affect of your recommended
adj ustments?
The net affect of my adjustments is a decrease
in Idaho Gas Revenue Requirement of $23 414 when tax
effects are included.
Does Staff agree wi th the methodology the
Company uses to allocate storage costs and storage
capaci ty release credi ts to the various Idaho customer
classes?
Staff has reviewed the CompanyNo.
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04 (Di)FUSS, M
STAFF
1246
~ 1 7
methodology and believes that adjustment is necessary.
The Company allocates storage costs and credi ts among the
Idaho classes based on annual consumption.While this
methodology will allocate costs and credi ts, it does not
reflect the true value each class receives when using the
Company s storage facili ties.
The primary purpose of the Company s storage
facilities is for winter peak supply.The use of the
storage facili ties is very limi ted throughout the rest of
the year.In fact stored gas is currently distributed to
Idaho on a systematic schedule.Storage is used in the
months of November, December , January, February, and
March.Staff believes that allocating storage costs
based on individual customer class usage over these
months is more appropriate because it better reflects
val ues received by each class.Consequently, I have
included this allocation methodology in the Company s Gas
Cost of Service Study.
Furthermore, Staff believes that the storage
capacity release credits should also be allocated based
on the monthly storage wi thdrawal cycle.Staff has made
two adj ustments to the Company s Gas Cost of Service
Study to reflect this change.Staff first allocates the
credi t over the Company s fixed storage wi thdrawal
schedule on the basis of volume to determine the amount
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04 1247
(Di)FUSS, M
STAFF
of credit attributable to each month.Staff then
allocates the monthly storage credi t to each customer
class based on the class s contribution to the monthly
throughput.I have included this allocation methodology
in Staff's adjustment to the Gas Cost of Service Study.
The storage allocator calculation is attached as Exhibit
No. 136.All natural gas rates and Gas Cost of Service
results presented in my testimony include these
allocations.While the changes to the storage
allocations do not change the Gas Jurisdictional Revenue
Requirement, Staff believes it provides a more
appropriate revenue requirement by customer class.Staff
recommends that the Commission approve allocation of
storage costs and credi ts based on the Company s actual
use of storage.
Adjustment Summary
What is the net affect on the Gas
Jurisdictional Revenue Requirement from the recommended
adjustments included in your testimony?
The net affect to the Idaho Gas Revenue
Requirement is a decrease of $26,367.The decrease is
shown as adjustment G13 & G14 on Staff Exhibit No. 107.
Have you provided a summary of the Staff
adjusted Gas Cost of Seyvice results?
Yes, attached as Exhibit No. 137 are the
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04
(Di)FUSS, M
STAFF
1248
resul ts of the Staff adj usted Gas Cost of Service Study.
COST OF GAS IN BASE RATES
Has the Company requested a change in the cost
of gas included in base rates?
Yes , the Company has requested to increase gas
costs in base rates to $0. 44989/therm.
Do you believe an adjustment of gas cost in
base rates is necessary?
Yes, over the past several years the Company
has requested and received several fairly large Purchase
Gas Cost Adj ustments (PGA)These rate adj ustments were
intended to reflect the Company s actual cost of gas
purchased for customers above the price of gas included
in base rates.The Company is proposing to add the
current PGA WACOG adjustment of $0. 27186/therm to base
rates to produce a total base rate gas cost of
$0.44989/therm.
I believe this change in gas cost
appropriate.Base rates should reflect the best estimate
of what gas costs would be in the future.The mo
accurately base rates reflect gas costs, the less extreme
PGA adj ustments will be.
Is a gas cost of $0. 44989/therm the appropriate
price level to be included in base rates today?
While Staff cannot predict the magni tude of
CASE NO. AVU-04-1/AVU-04-6/21/04 (Di)FUSS, M
STAFF
1249
future natural gas prlces with certainty, we believe that
the $0. 44989/therm proposed by the Company is a
reasonable price level for natural gas in base rates
going forward.Natural gas prices are considerably
higher today than in 1988 when the current base rate gas
prlce of $0 .17803/therm was established.However , Staff
notes that increasing gas costs included in base rates
will not eliminate the need for a PGA in the future.
the extent actual gas costs lncrease , the PGA will simply
be lower than it otherwise would have been.If actual
gas costs decrease, then larger PGA credi ts will resul
That being said, natural gas is in a period of
extreme volatility.Staff believes that natural gas
prices will likely vary between $0.300 and $0.600 over
the next five to seven years.The Company s proposed
cost of gas in base rates falls at approximately the mid-
point of Staff's estimated range of future gas prlces.
Therefore, Staff recommends that the Company s proposal
be accepted.
SPECIAL CONTRACTS (NATURAL GAS)
How are Idaho Gas Special Contract customers
like Potlatch , IMCO, and Lignetics treated in the rate
case?
The Company has included all expenses
associated wi th serving Idaho s Gas Special Contract
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04 1250
(Di)FUSS, M
STAFF
customers in the general rate filing.These expenses are
allocated among all customer classes using the same
methodology used for allocating other service costs.
order to offset the rate effect of allocating special
contract expenses to other customer classes, special
contract revenue is also credi ted to the classes.The
result is the inclusion of costs and benefits to all
other customer classes.
Staff believes that the revenue credit
continues to provide an adequate offset to Company
expenses as approved by the Commission during the
contract approval process.Based on Staff's review of
the Company s Gas Cost of Service Study, the credits are
appropriately applied.
Are Idaho Gas Special Contract Customers rates
changed as a resul t of this case?
All Gas Special Contract Customers inNo.
Idaho are served under existing long-term contracts at
fixed rates.All current Idaho contracts were in place
before the test year used by the Company in this case.
While Special Contract rates are not changed as a resul t
of this case, the Commission has previously reviewed the
contract conditions and revenue contribution from these
customers and found them prudent.However, when the
current contracts expire , the terms and contribution of
CASE NO. AVU-E- 04 -l/AVU-G- 04-
6/21/04
(Di)FUSS, M
STAFF
1251
each contract should be reevaluated and updated to
reflect the appropriate cost of service or appropriate
level of contribution to margin.Staff does not believe
that any change is necessary at this time.
TARIFF ISSUE
Do you have any natural gas general tariff
recommenda t ions?
Yes , Staff recommends that the Company add a
tariff summary sheet,denoted as sheet whi ch
summari zes all natural gas rate schedules and all natural
gas adj ustment clauses wi th the except ion local
franchise fees.Currently the Company uses a number of
tariff sheets such as Schedules 150, 155, and 191 to
identify various periodic rate adjustments such
Purchase Gas Adjustments (PGAs) and Demand Side
Management (DSM) tariff riders.While the use of the
various tariff schedules minimizes the number of sheets
that must be updated, the practice increases the
likelihood for rate calculation errors and is somewhat
confusing to customers.Staff believes adding a tariff
sheet will benefit customers and will not be overly
burdensome on the Company.
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NO. AVU-E- 04 -l/AVU-G- 04-6/21/04 1252
(Di)FUSS, M
STAFF
(The following proceedings were had in
open hearing.
(Staff Exhibit Nos. 136 and 137 , having
been premarked for identification , were admitted into
evidence.
MR. WOODBURY:And Staff would present Mr. Fuss
for cross-examination.
COMMISSIONER KJELLANDER:Thank you.Let's begin
wi th Mr. Meyer.
MR . MEYER:No questions , thank you.
COMMISSIONER KJELLANDER:Mr. Purdy.
MR . PURDY:I have none, thank you.
COMMISSIONER KJELLANDER:Mr. Cox.
MR . COX:I have none.Thank you.
COMMISSIONER KJELLANDER:Mr. Ward.
MR . WARD:No questions.Thank you.
COMMISSIONER KJELLANDER:Any questions from
members of the Commission?
If not, then there is no opportunity for redirect
of this witness, and we thank you for your testimony and your
presence.
(The witness left the stand.
COMMISSIONER KJELLANDER:And if you'd like to
call your next witness?
MR. WOODBURY:Staff would call Keith Hessing.
1253
HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE, ID 83701
FUSS (Di)Staff
KEITH HESSING,
produced as a witness at the instance of Staff , being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MR. WOODBURY:
Mr. Hessing, will you please state your full
name , spell your last name for the record?
My name is Kei th Hessing.My last name
spelled H-S- I -
And , Mr. Hessing, for whom do you work and in
what capaci ty?
I work for the Idaho Public Utilities Commission
and I'm a Staff engineer.
And in that capacity, did you have occasion to
prefile testimony in this case consisting of 24 pages, and five
exhibits , Exhibits 138 through 142?
That's correct.
And have you had the opportuni ty to review that
testimony and those exhibi ts prior to this morning's hearing?
Yes.
And if I were to ask you the questions set forth
in your testimony, would your answers be the same?
Yes.And I might point out that the cost of
1254
HEDRI CK COURT REPORTING
O. BOX 578 , BOISE , ID 83701
HESSING (Di)
Staff
serVlce exhibits haven't been revised with some of the
revisions that were made after Staff's initial filing that
wi tness Stockton made.
MR. WOODBURY:Mr. Chairman , I'd ask that the
testimony be spread on the record as if read, and that
Exhibits 138 through 142 be identified.
COMMISSIONER KJELLANDER:Wi thou t obj ect ion
spread the testimony across the record as if read, and admi
Exhibits 138 and (sic) 142.
(The following prefiled direct testimony
of Mr. Hessing is spread upon the record.
1255
HEDRICK COURT REPORTING
O. BOX 578 , BOISE , ID 83701
HESSING (Di)Staff
Please state you~ name and business address
for the record.
My name is Keith D. Hessing and my business
address is 472 West Washington Street, Boise, Idaho.
By whom are you employed and in what
capaci ty?
I am employed by the Idaho Public Utilities
Commission as a Public Utilities Engineer.
What is your educational and experience
background?
I am a Registered Professional Engineer in
the State of Idaho.I received a Bachelor of Science
Degree in Civil Engineering from the Uni versi ty of Idaho
in 1974.Since then, I worked six years for the Idaho
Department of Water Resources, and two years for
Morrison-Knudsen.I have been continuously ~mployed
the Commission since August 1983.
As a member of the Commission Staff, my
prlmary areas of responsibility have been electric
utility power supply, revenue allocation and rate design.
What is the purpose of your testimony in
this proceeding?
My testimony discusses electric issues
including Jurisdictional Separations, Class Cost of
Service and PCA issues including Deal "A" and Deal "
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESS ING, (Di)
STAFF
1256
gas purchase issues carried into this case from Case No.
AVU-03-6 by Commission Order No. 29377.I al so propose
a change in PCA methodology.My testimony concludes with
a brief discussion of average rate changes for each
customer class and an exhibit showing the overall effects
of Staff's rate proposal.
Please summarize your testimony.
I recommend that the Commission accept the
Jurisdictional Separation study proposed by the Company.
I also recommend that the Class Cost of Service
methodology proposed by Avista be accepted by the
Commission.I provide Cost of Service resul ts, that
include Staff's accounting adjustments, to Staff witness
Schunke which he uses as the starting point in allocating
revenue requirement to the various customer classes.
I recommend that the Commission accept the
Company s calculation of base power supply costs for use
in future PCA calculations.I recommend that losses on
the purchase and subsequent sale of Deal "B" gas in the
amount of $6,496,669 not be charged to customers.I also
propose a reduct ion in PCA rates.
I propose that the PCA rate design
methodology be changed once the current deferral balance
is eliminated.Currently increases and decreases are
spread to customer classes based on each class
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1257
percentage of total revenue and recovered in the energy
charge for each class.I propose that PCA increases and
decreases be surcharged or rebated to customers on the
basis of energy consumption.My proposal would apply an
equal cents per kWh rate to all customer classes except
lighting classes which would receive the average
percentage lncrease or decrease.
My testimony concl udes wi th an exhibi t
showing the combined average revenue changes for each
customer class caused by Staff's base rate proposal, DSM
Rider rate proposal and PCA rate change proposal.The
overall net electric increase proposed by Staff is 2.4%.
JURISDICTIONAL SEPARATIONS AND CLASS COST OF SERVICE
What Jurisdictional Separation and Class
Cost of Service methodology is used by the Company?
The Company applied the same Jurisdictional
Separation methodology accepted by the Commission in its
last general rate case, Case No. WWP-98-11.The
methodology directly assigns revenues, costs and
investment to jurisdictions where appropriate and
allocates the remaining amounts.The methodology uses
2002 test year booked amounts without adjustment.All
adjustments are included on an Idaho System basis at the
beginning of the Cost of Service process.
The Company used the same Peak Credi t Cost
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1258
of Service methodology that it used in its last general
rate case with minor modifications.The Commission
accepted that methodology as the starting point for
revenue allocation in that case.Staff proposes only an
incremental move toward full cost serVlce
recognition the fact that cost serVlce resul ts are
not preClse and unacceptably arge lncreases some
classes would occur.Staff witness Schunke discusses
revenue allocation to the various customer classes in his
testimony.
Is there value in applying consistent
Jurisdictional Separation and Class Cost of Service
methodology from case to case?
Yes, there is.It allows the usage and
customer characteristics that form the allocators and the
accounting data to drive the resul ts.There are
substantial changes caused by these factors without
changing the methodology.
Does the Staff accept the methodology and
allocation factors used by the Company in its filing?
Yes.
Have you prepared an exhibi t that shows the
Class Cost of Service resul ts that have been used as the
starting point for revenue allocation in Staff's case?
Yes, I have.Staff Exhibi t No. 138 shows
CASE NOS. AVU-04-1/AVU-04-
06/21/04
HESSING, K (Di)
STAFF
1259
Class Cost of Service resul ts based on a total revenue
requirement of $169,326,876 which is a $23,078,876,
15.78% increase above existing base rates.This
information was provided to Staff wi tness Schunke for
revenue allocation purposes.
PCA ISSUES
Deal "A" and Deal "
Please summarize the Deal "A" and Deal "
lssue carried into this case by Commission Order No.
29377 from Case No. AVU-03-6, which was the Company
last PCA case.
In March 2001, Avista Utilities purchased
gas at index to operate its gas-fired resources for the
purpose of producing electrici ty.Deal "A" deliveries
were for 27,658 dth/day for a 36-month period beginning
November 1, 2001.Deal "B" deliveries were 20,000
dth/day for a 17-month period beginning June 1 2002.
Total Deal "A" and Deal "B" purchases were exactly the
quanti ty of gas required to run the Coyote Springs 2 CCCT
at its full generating capacity of 280 MW.
In April and May of 2001, using 4 separate
transactions, the Company fixed the price, using hedges
for 40, 000 dth/ day, which is 84 percent of the gas.The
hedged price averaged approximately $6.00 per decatherm.
The other 16 percent of the gas remained at index.The
CASE NOS. AVU-04-1/AVU-04-
06/21/04
HESSING, K (Di)
STAFF
1260
Company s Confidential Exhibit 7 , Schedule 16, summarlzes
the Deal "A" and "B" transactions.
When the various gas price hedges were
established , electric forward market prices were high and
if the electric prices would have persisted in real time
a number of good things could have happened to the
Company and its customers using the fixed price gas.
discuss those later in this testimony.However, between
the time that the price was fixed and the time the gas
supplies were to be delivered, electric and gas market
prices dropped precipitously.After this happened, the
best plan for the Company and its customers was to sell
the gas at a loss and purchase the Company s electric
needs from the wholesale electric market each month.The
Company had losses on Deal "A" and Deal "B" which
proposed to include in the PCA.The PCA would have
passed 90% of the losses for the Idaho jurisdiction on to
customers while the Company s shareholders would have
been responsible for the other 10%.In its comments in
the referenced case, Staff proposed that only Deal "
losses be excluded from PCA treatment and recovery from
ra tepayers In its final order in that case, the
Commission did not rule on the issue but required that
both Deal "A" and Deal "B" losses be examined In more
detai I in thi s proceeding.Staff Exhibi t No. 139 is a
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1261
copy of the Staff Comments filed in Case No. AVU-03-
The detailed discussion of Deal "A" and "B" begins on
page 6.An understanding of the referenced comments and
testimony is essential to full understanding of the Deal
A" and "B" issues in this case.
Please summarize Staff's conclusions in that
case.
Wi th regard to the Company s Energy
Resources Risk Policy, the Staff concluded that Deal "
purchases violated risk policy provisions.Al so , Deal
B" price hedges were entered into with Avista Energy
(AE) , an unregulated affiliate of the regulated utility.
Staff concluded that appropriate safeguards were not in
place or followed to protect customers when the regulated
utility does business with its affiliate.Saf eguards
could include a proper Code of Conduct or a requirement
for lower-of -cost or market prlclng.The Staff also
concluded that the Company took unusual risks when
hedging the price for the length of these gas purchase
deals for its electric customers.Similar risks were not
taken for its natural gas customers.
What has changed with regard to Deal "A" and
B" purchases since the Staff filed its comments in the
last PCA case?
Several months have passed and the time
CASE NOS. AVU-04-1/AVU-04-06/21/04
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STAFF
1262
frame for gas delivery under Deal "B" is over.It ended
at the end of October 2003.In the last few months of
the deal, Avista sold some of the gas at a loss but
burned some of the Deal "8" gas profitably.
Has Staff's position changed since its PCA
filing?
No, but Staff does recognlze that some Deal
B" gas has since been burned profitably.It is only
fair that the savings on the price of the gas when the
market is above $6.00 be netted against losses when the
market is below $6.00.Staff's position in this case
that the net of Deal "B" profits and losses, net losses,
should not be included in the PCA.
Does the Company s filing in this case
address the concerns that Staff raised in its filed
comments in Case No. AVU-03-
Only partially.In his testimony, Company
witness Lafferty presents and discusses Deal "A" and Deal
B" purchases from a longer-term , resource planning,
point of view instead of the near term , risk policy,
point of view presented by Staff in its previously
referenced PCA comments.
Please discuss some of the differences in
the two approaches.
The risk policy perspective Vlews resource
CASE NOS. AVU-04-1/AVU-04-
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1263
decisions for the coming 18 -month period.This process
initially assumes normal load and resource conditions and
updates both based on forecasts as they become available.
Forecasts become more accurate as they near real time.
The policy includes written rules and maximum long and
short position limits that vary based on the period of
time remaining before energy lS needed, real time.
general the Company s "position " is the difference
between expected loads and expected resources.
The long-term planning view presumably
guides resource decisions that are made for periods
further than 18 months out.It assumes cri tical water
conditions resulting in approximately 150 average MW'
less available generation than under normal water
condi tions.Eighteen months out from real time, where
the planning criteria time period and operating criteria
time period meet, loads and resources that are perfectly
balanced based on the long-term cri tical water planning
criteria resul t approximate 150 long position
under the risk policy reVlew cri teria because the risk
policy is based on normal water condi tion assumptions.
Eighteen months out, the long limit allowed in the risk
management plan is 150 MW above normal water conditions.
Therefore, the Company would move into the risk policy
analysis period with the largest amount of extra
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1264
resources that the plan allows.Of course, if the
Company is just a little long based on long-term critical
water planning cri teria, it transi tions into the risk
policy period above the established limits and would
immediately have to sell energy to get below the long
limit contained in the Company s Risk Policy.
Does Company wi tness Lafferty suggest that
there are concerns, other than critical water, that the
Company should be allowed to consider when it purchases
fuel for its gas fired resources?
In addition to water conditions Mr.Yes.
Lafferty suggests that loads and outages should also be
considered.He states that actual loads could be higher
than expected by 87 MW and that a unit outage at Colstrip
could reduce generating capability by 100 MW.Pg. 43)
Does it make sense to purchase energy or
fixed prlce fuel to produce energy for 300+ MW of unusual
deficiencies?
No, not before the deficiencies become
known.The chances of all three events occurrlng
together are extremely improbable.
Is it reasonable to have some energy reserve
to address these types of deficiency causing events if
they do occur?
Yes, it is.The Company s risk policy very
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1265
specifically provides for this by establishing a long
limi t of 150 MW.The Company s Risk Policy says,
Reasons to maintain long positions may include
strategies to mi tigate potential negative impacts of
unplanned loss of resources, adverse changes in hydro
condi tions, or adverse impacts of load variations as
compared to the forecast"(Exhibit 139, Energy Resources
Risk Policy, Attachment J, Pgs. 3 and 4 of 15)
Do the differing perspectives concerning
appropriate reVlew criteria cause the Company and Staff
to reach different conclusions?
I think so.The long-term perspective used
by the Company to justify these transactions is very
different than the Company s near term risk policy
perspecti ve used by the Staff.
How are the Deal "A" and "B" purchases
initially positioned relative to the 18-month transition
point between the long-term and short-term analytical
approaches?
As indicated in Staff comments in the last
PCA case, both purchases were ongoing at the 18 -month
transition point which was about October 2002.
Why does Staff utilize the Company
shorter-term risk policy method of analysis to evaluate
the merits of the gas transactions?
CASE NOS. AVU-04-1/AVU-04-
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HESSING, K (Di)
STAFF
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The Energy Resources Risk Policy is written
and well defined.It is designed to address the very
situations that the Company says could occur.The
Resource planning process that Staff is familiar with,
the Integrated Resource Planning (IRP) process, does not
include criteria for acquiring energy or gas to produce
energy which is the issue being addressed here.
Was the Company using a long-term planning
process like the one discussed in its testimony and used
to justify its long out-of-limit position before the Deal
A" and "B" gas purchases?
If the Company was uslng it's long termNo.
resource acquisition plan, its resource positions would
have been long, probably even long out of limi ts in its
Posi tion Reports.As shown on the Company s Posi tion
Limit Chart for March 7, 2001 (Exhibit No. 139,
Confidential Attachment K, pg. 1), the load resource
balance is short coming into the 18 month planning period
and remains short or minimally long, 35 MW maximum , for
the entire perio~.This report reflects the Company
position just prior to Deal "A" and "B" transactions.
This is not consistent with the long-term acquisition
process the Company says it uses.
In Staff's previously mentioned PCA
comments, Staff pointed out that Avista ' s gas operations
CASE NOS. AVU-04-1/AVU-04-06/21/04
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STAFF
1267
did not make the same kind of long-term purchases for its
gas customers in early 2001.What information do you
have that supports this position?
Staff Exhibi t No. 140 was provided by the
Company in response to Staff Production Request No. 27.
The Exhibit shows that in early 2001 the Company did not
purchase gas two and three years into the future for its
gas customers.The fact that the Company failed to
purchase gas with the same kind of long-term deals for
its gas customers that it did for its electric customers
demonstrates the Company s inconsistency.If long-term
gas purchases were expected to be beneficial to the
electric utility, why would they have not been expected
to be beneficial to the gas utility?Staf f Exhibi t No.
140 shows that in the same time frame, the Company rarely
purchased gas for its gas customers at Deal "A" or "
prices and never made fixed price purchases for use more
than two years in the future.
In its PCA comments the Staff discussed the
hedge transactions between Avista Utilities and Avista
Energy (AE) that fixed the gas cost for Deal "B" in April
and May o f 2 0 0 1 .Do you have anything further to add
that discussion?
Yes.When the gas cost was fixed wi
Avista Energy, both AE and the utility along with its
CASE NOS. AVU-04-1/AVU-04-06/21/04
HESSING, K (Di)
STAFF1268
customers were exposed to risk.AE's risk was that gas
prices would go up and that when it needed gas for
delivery it would be more costly.
The utility was exposed to several types of
risk.It had the risk that gas prices would go down and
gas would cost less when it was needed.The utili ty also
had the risk that electric and gas prices would go down
such that the gas could not be economically. used to
produce electricity and the gas would have to be sold
a loss.Of course, through the PCA 90% of any loss would
be recovered from customers.This created a situation
where one affiliate essentially bet against the other
affiliate.One was going to profit and one was going to
pay and because of the PCA , Avista shareholders were
substantially protected from paying.Because the deal
with AE was not provided to Avista Utilities at cost, AE
had the opportunity to profit by keeping the difference
between the actual cost and fixed price of gas sold
the regulated utili ty.In fact a counter party such .
AE would not have made the deal if it did not expect to
profit.In the end , AE profited and the regulated
utili ty is proposlng that its customers pay 90% of the
costs.If AE chose not to hedge its risks on the
transactions, it profited by the difference between
actual and fixed price.In the end regulated utility
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1269
shareholders paid 10% of the AE profit and utility
ratepayers paid the other 90% of AE's profit.It is
Staff's position that whether AE profited or not, Deal
B" was not at the lower-of-cost or market and,
therefore, constituted an inappropriate affiliate
transaction.Staff's Deal "B" proposal in this case,
that net losses on the gas sales should not be allowed in
the PCA , amounts to giving the customer the better deal,
cost or market.
Why does Staff propose to disallow Deal "
loss recovery and accept Deal "A" loss recovery?
Deal "A" hedges were not done with an Avista
affiliate, but Deal "B" hedges were.Also, the Deal "
gas purchase did not put the Company over the long limit
contained in it's Risk Policy, the Deal "B" purchase
which was executed at a later point in time caused the
utility to exceed the long limit.Not only did the
transaction place Avista above the long limit, but
Avista s position continued to stay above the limit.
Has the information provided by the Company
changed Staff's position regarding disallowance of Deal
B" net loss~s from PCA treatment?
No. ,It remains Staff's position that net
losses on the sale of Deal "B" gas should not be included
in the PCA.
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1270
What is the basis for this conclusion?
It is Staff's position that the Company
violated both the intent and the written requirements of
its own Energy Resources Risk Policy.The Company
purchased gas for electric generation that exceeded the
limits allowed by the policy, then fixed the price which
created a speculative posi tion that led to the losses.
Also in executing the Deal "B" price hedges with its
unregulated affiliate, Avista Energy, the Company created
a potential conflict of interest.In order to avoid
potential abuse or even the appearance of abuse, the
Company needs to provide its customers wi th the best deal
by recording the transaction at the lower-of -cost or
market absent other specific rules established to protect
cus tomers Staff believes that it was extremely risky to
lock the price of gas at a tradi tionally high price in
gas market with prices falling even though forward
electric prices were high.
What' other reasons. could have caused the
Company to take the risks that it took in the Deal "
and "B" purchases?
Avista needed the Coyote Springs 2 plant to
reduce its dependence on what had become a highly
volatile energy market.Coyote Springs 2 was to be one
of the most efficient combined cycle gas-fired combustion
CASE NOS. AVU-04-1/AVU-04-
06/21/04
HESSING, K (Di)
STAFF
1271
turbines in the reglon with a 7 000 BTU/kWh heat rate.
Avista was finan~ially stressed and needed to obtain a
gas supply in order to secure financing for the proj ect
Deal "A" provided the necessary gas transportation along
wi th gas supply.If electric prices held at or near the
forward level at the time of the Deal "A" and "B" hedges,
the operation of CS '2 would have been profitable.Power
needed by customers could be generated at a cost below
the market price.I f the Company was long on supply, it
could generate power and sell the power for profit.Ten
percent of the profit would go to shareholders, while
percent of the profi t would go to the PCA to buy down PCA
balances and reduce customer rates.
This philosophy could have worked if the
electric sale of the long energy had also been made at
the same time to lock in the gain and reduce the long
position.Absent such an electric power sale, the
transaction was purely speculation.
Al so, if all had gone according to the
Company s plan , Coyote Springs 2 would have been
demonstrated to be used and useful and therefore, easily
rate based.
The Company fixed the gas prlces for 84% of
the Deal "A" and "B" gas.Could Avista have fixed
electric forward prlces as well?
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1272
Yes, but the cost may have been substantial
and may have reduced or eliminated the expected profits.
If the cost of fixing the electric forward
prlces was high or prohibi ti ve, what would this tell
Avista about the risk of the transaction?
If the parties who sell this type of
financial instrument wanted a high premium to fix the
forward price of electricity they obviously believed that
there was a great deal of risk in selling forward at a
fixed prlce.If there is a great deal of risk that
forward electric prices would be lower than forecast, the
Company should have chosen shorter term less risky deals
that would have captured the benefits of layering or
dollar cost averaging.Again as previously stated,
absent electric sale transactions this act i vi ty was based
on speculation.Customers should not pay for Avista to
speculate.
In two different places in his testimony,
Company witness Lafferty characterizes Staff's proposal
that electric forward prices could have been hedged along
with gas prices as "retrospective
(pg.
47) or "after the
fact"
(pg.
51) views.Would you please comment.
It is a common practice in the energy
business to capture the benefits of a deal by locking in
all prices.It requires no hindsight to see the
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING , K (Di)
STAFF
1273
advantages of so doing in the Deal "A" and "
transactions.By not locking the electric forward prlces
in these transactions the Company gambled that electric
prices would not decline substantially.The Company lost
on that gamble.As stated previously, customers should
not pay for speculation or a gamble.
What amount does Staff recommend be removed
from the PCA deferral account to reflect Deal "B" losses?
Deal "B" losses are calculated on Staff
Confidential Exhibit No. 141.The bot tom I ine shows that
90% of Idaho jurisdictional losses on Deal "B" that have
been deferred for recovery are $6,496,669.This is the
amount that Staff recommends be removed from the PCA
deferral account.
Does Staff Exhibi t No. 141 also show the
Deal "A" losses that Staff is not proposing to remove
from PCA treatment?
Ninety percent of the IdahoYes.
jurisdictional share of Deal "A" losses are shown to be
$8,677 766.
Upda ted PCA Components
Are base PCA net power supply costs to be
updated as a resul t of this general rate case?
Staff proposes that base power supplyYes.
costs be updated as a resul t of this case.The Company
CASE NOS. AVU-E- 04 -l/AVU-G- 04-06/21/04 HESSING, K (Di)
STAFF
1274
proposed the same.Company witness Johnson shows the new
base amounts on Exhibi t 10 , Schedule
What are base power supply costs used for
the PCA?
The PCA calculates the difference between
actual and authorized base Idaho jurisdictional power
supply costs and, after appropriate sharing and a load
change revenue adjustment, defers the difference for
later recovery or rebate.
Does Staff support the base amounts proposed
by the Company as shown in Company witness Johnson
Exhibi t 10 , Schedule 4?
Yes.
Is there another PCA component that the
Company proposes to update in this case?
In his testimony, Company wi tnessYes.
Johnson proposes to update the load change revenue
adjustment multiplier.
What change is proposed in the mul tiplier?
The Company proposes that the multiplier be
changed from 21.23 $/MWh to 36.38 $/MWh.
How is the multiplier used?
The multiplier is the average annual
variable power supply cost of meeting new load as
determined from the Company s power supply model.It '
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF1275
mul tiplied times the difference between base and actual
loads to determine the cost of load changes that occur
and accrue in the PCA.The resul t ing cost is used to
adj ust the power supply cost deferral for changes in
power supply costs associated wi th load growth or
decline.By removing this resul ting amount from the PCA
calculation, power supply costs associated with load
change are reserved for consideration in general rate
cases.
Does Staff agree wi th the Company
calculation of the load change revenue adj ustment
multiplier.
Yes.
PCA Rate Reduction
Does the Company recommend a reduct ion in
current PCA rates?
In its filing the Company estimated aYes.
deferral balance of approximately $23 million at the end
of September 2004.The Company proposes to implement
reduced PCA rates in this case designed to recover $11.
million of the estimated balance each year for two years.
What is Staff's PCA rate proposal?
Staff proposes to reduce the Company
actual end of May 2004 balance of $26,261 334 by
496,669 in Deal "B" losses and calculate rates to
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1276
recover the remaining balance over 2 years.Thi s reduces
the PCA revenue requirement by $17 963 835 per year.
Staff believes it is more appropriate to use actual
amounts than estimates even though the PCA trues the
amounts up to actual.
Other PCA Matters
Does Staff propose a change in the PCA
mechanism?
Staff proposes to change the way ratesYes.
are calculated in the PCA mechanism once the current PCA
deferral balance is el iminated.The current PCA
mechanism assigns class revenue responsibility based Dn a
uniform percentage of revenue spread to each class and
then assigns recovery to the energy portion of the rate
wi thin each class.Staff proposes that PCA costs be
recovered from Avista ratepayers on a uniform cents per
kWh basis. The PCA rate would be the same for all
schedules except lighting schedules.Lighting schedules
would pay/receive the Idaho average increase/decrease.
Why should this change be made?
The allocation of PCA costs to individual
rate classes based on a percentage of total revenue
assumes and relies on a mix of fixed and variable costs
like those allocated to each customer class through the
Cost of Service process.Above or below normal power
CASE NOS. AVU-E- 04 -l/AVU-G- 04-06/21/04 HESSING, K (Di)
STAFF
1277
supply costs that are captured in the PCA mechanism are
directly related to the variable costs of providing
energy.The fixed costs of power supply are not captured
in the PCA.Therefore, it is more appropriate to recover
variable power supply costs wi th an equal cents per kWh
charge that applies to all energy use.
When does Staff propose this change be made?
Staff proposes that this change be made when
the current deferral balance is eliminated.
Why not make the change wi th the new rates
that will resul t from this case?
As pointed out by the Company in this case
there is a very substantial PCA deferral balance that has
accumulated and that will be recovered from customers in
the next few years.Staff believes that because the
balance was accumulated under the current methodology
is fair to recover this balance under the current
methodology.However , when the balance is eliminated,
the methodology should be changed.The proposed
methodology causes high load factor customers, such
Potlatch and others , to pay /recei ve a larger percentage
of surcharges/rebates.To impose such a change when
there is a large balance to surcharge would initially
penalize high load factor customers.It is only fair
make the change when the current balance is at or near
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING , K (Di)
STAFF
1278
zero and, golng forward, there is an equal probability of
credi t or surcharge.
FINAL REVENUE ALLOCATION
What rates does Staff propose to change as
the resul t of this case?
Staff proposes that base rates change based
on the revenue requirement spread included in Staff
wi tness Schunke ' s testimony.His testimony also provides
Staff's proposed base rates.In addition, Staff witness
Anderson proposes a change in DSM Rider rates.Finally,
my testimony recommends changes to PCA rates. I propose
that these PCA rate changes stay in place until October
2005 when an annual review of the deferral balance could
cause them to change.Staff Exhibi t No. 142 shows all of
the revenue requirement changes by customer class and the
resul ting net percentage lncreases and decreases measured
from existing rates.As shown on the exhibi t , the
overall change is a 2.4% lncrease above existing rates.
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di)
STAFF
1279
(The following proceedings were had
open hearing.
(Staff Exhibit Nos. 138 through 142
having been premarked for identification, were admitted into
evidence.
MR. WOODBURY:And with the Commission I
indulgence in light of some testimony of Mr. Lafferty regarding
affiliate transactions and documentation , I would have three
short questions to ask of Mr. Hessing.
COMMISSIONER KJELLANDER:Please proceed.
BY MR. WOODBURY:Mr. Hessing, in yesterday I
testimony, Mr. Lafferty testified.Were you available for
that?
Yes, I was here.
Mr. Lafferty agrees that a higher level of
scrutiny is warranted with affiliates, and that I s set forth in
his rebuttal on page 28.Do you believe that additional
documentation is part of that higher level of scrutiny that
applies to affiliate transactions?
I think additional documentation would be part of
what we would expect for affiliate transactions.
And in Staff I s audit and review of the Company I s
transactions regarding Deal A and did Staff see any
addi tional documentation for those transactions than was
greater than for other transactions?
1280
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HESSING (Di)Staff
I would say initially the documentation , there
was no additional documentation.And , of course, as part of
this case, some additional information has been provided.
And does Staff believe that the documentation for
Deal B met the higher level of scrutiny?
Certainly we would have I iked to have seen more
in terms of documentation for that kind of a transaction.
Okay.And does the Company generally provide a
higher level of documentation for its natural gas transactions
under the benchmark mechanism?
It's my understanding that the Company does
generally provide that.
Thank you.
MR . WOODBURY:Thank you, Mr. Cha i rman .Staff
has no further questions and would present Mr. Hessing for
cross-examination.
COMMISSIONER KJELLANDER:Thank you.Let's begin
wi th Mr. Purdy.
MR . PURDY:None.Thanks.
COMMISSIONER KJELLANDER:Mr. Cox.
MR. COX:I have some, thank you.
COMMISSIONER KJELLANDER:Okay.
1281
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HESSING (Di)
Staff
CROSS - EXAMINATION
BY MR. COX:
Mr. Hessing, I'd like to ask you some questions
about the load research data that is utilized in this case.
How old is that data?
It's my understanding that it'quite old.
believe 1993.
Okay.Over the last years has Avista changed
f rom a winter peaking to a summer peaking utility?
I think there have been movements toward a maybe
a dual peaking situation.The load - - there is more load in
the summer than there was.
Okay.So now is it basically a
- -
is it now a
summer peaking utility?
Well think that
in the summer and the winter.
Avista has significant peaks
Okay.It's been a change from 1993?
Yes.
What was it in 1993?
I think that in 1993, even though Avista had a
small summer peak , that summer peak has gotten considerably
larger.
Okay.Since the peak day in July of 1993 is not
the same day and time as a peak day in July of last year or
1282
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
HESSING (X)Staff
this year , and since the hours of the peaks may be different as
well , how has the Company used the 1993 data to reflect 2002 or
2003?
I think the Company applied the information from
the study that it had probably in the best way that it could
for the purposes of this case.It's time to update that data.
Okay.Well , do you feel then that the
- -
that
it's good to use 1993 data for this case?
I think that it would have been bet ter to have
more recent data for some of the reasons that you'pointed
out but the fact that that data didn t exist and wasn't done
makes it not doable.
Okay.Well , given the lack of certainty wi
respect to the load research data, wouldn't it be better to
give all the rate schedules with load research data an even
spread of the rate increase?
I don't think it justifies throwing out the
resul ts of the cost of service in that analysis, even though
do believe it does need to be updated~
Well , let's move on to a slightly different topic
then.When you originally reviewed the Company I s cost of
service study, did you look into the possibility of directly
assigning any distribution costs to Schedule 25?
I didn t look beyond what the Company did with
the direct assignment of some substation costs.
1283
HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
HESSING (X)Staff
Okay.Well , have you seen data from the Company
that indicates there is just one mile of underground plant
that I S used by Schedule 25 out of 808 miles of underground
primary system in Northern Idaho?
Yes, I saw that data.
Okay.Do you generally agree that if Schedule 25
is using only one mile of underground primary circuit of the
total 808 miles , allocating 10 percent of all underground
primary costs based upon using the noncoincident allocation
method would assign too much cost to Schedule 25?And, again
m not asking you to tell what the numbers would be, just if
you I d agree with that generally?
Generally, I agree that the mileage is a lot less
than what would be allocated using the allocation principles
and that if you could direct assign it , the cost would be less
in general.
Okay.And the same problem generally exists with
Schedule 25, using 25 miles of overhead primary circuits out of
049 miles of overhead circuits in the same jurisdiction?
it the same problem?
I think it is, but I think the Company has
pointed out some offsetting
considered there as well.
Okay.Well
circumstances that should be
and are you talking about splitting
the difference?
1284
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
HESSING (X)
Staff
That's the - - they pointed out some reasons why
it isn't appropriate to go all the way there and why they chose
to split the difference, and I think that's a reasonable
solution here.
Let me ask it this way:In splitting the
difference, does that bring the Schedule 25 half way up to the
jurisdictional average?
It makes a significant move toward the
jurisdictional average if you do that.
Okay.And would you generally agree, at least
for purposes of Schedule 25, that use of a noncoincident peak
allocation method adds very little value or reliability to the
primary distribution costs in this case?
To the extent
- -
and Mr. Yankel did an estimate
of what those costs would be.To the extent that the costs are
known and can be directly assigned , that's a more appropriate
and accurate way of doing that.
Okay.Thank you.
Well , if it were to use Mr. Yankel' s direct
assignment , Schedule 25 would give the jurisdictional average
of the rate of return , would it not?
That's what his exhibi ts showed.
Okay.Well , correct me if I'm wrong,Thank you.
but I think that it's your testimony that the allocation method
is not based on current data, and that there are different
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things that
- -
factors in there
- -
that are not the same today
as they were in 1993, and as a result, that makes at least that
particular
- -
the allocation - - suspect?
It makes the allocation I guess more of an
estimate than it would be if the data was more current.
still think it's appropriate to use the allocation methodology
and not discard it entirely as a result of that older data.
But would you agree with me though that you have
somebody --
COMMI S S lONER KJELLANDER:Mr. Cox , I think I'
going to ask you to try to move your microphone to a central
location on your desk , and whatever is touching it, if you
could kind of move that away, because it's creating a --
MR. COX:I apologize.ve done that.
COMMI S S lONER KJELLANDER:Oh, not your problem.
These microphones take a while to get used to.
MR . COX:Well, I was moving my paper around.
COMMISSIONER KJELLANDER:Okay.Thank you.
BY MR. COX:What I'm trying to get to,
Mr. Hessing, doesn't it make more sense to use the mileage that
Mr. Yankel is proposing because we know how much that is , as
opposed to an allocation that's old, based on old data, and
subj ect to all these various quest ions?I mean , we don't have
the current data there and I think it would be
--
isn't it fair
to say that what Mr. Yankel is proposing is based upon some
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numbers we actually know?
It I S based - - well , the numbers in 1993 are known
also.The numbers that he's proposing and his method of making
that calculation were also an estimate.It's my opinion that
the compromise that the Company proposes is the best solution.
Okay.I guess I appreciate the comment.I was
just trying to get to if we were trying to actually determine
it as opposed to a comprise, it would be better to base the
determination on facts that we know are very close, if not
exactly, the mileage, as opposed to basing something on old
data that we know may or may not be accurate?
Well , I think there are some facts that are known
that the Company pointed out , such as the size of the
facilities , the primary facilities required to service a
Schedule 25 customer that aren't captured in Mr. Yankel'
analysis, and those are the reasons for the compromise.
Uh-huh.Okay.Appreciate it.Thank you.
COMMI S S lONER KJELLANDER:Thank you, Mr. Cox.
Mr. Ward.
MR. WARD:Thank you.
CROSS - EXAMINATION
BY MR. WARD:
Mr. Hessing, if you would turn to page 15 of your
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testimony?
I have that.
Okay.By way of background to this question , as
I understand it , you've recommended disallowance of Deal B , but
have not made similar recommendation for Deal A, and as
- -
I see it , there are two differences you draw between the two
deal s One is that Deal B , of course, involves self-dealing
with an affiliate, and the second was that Deal B was what put
the Company over its risk policy limits.Is that a fair
as sumpt ion?
I think generally that's true.The first, the
Deal B , was between affiliates and, yes, it didn't transact
towards zero is the language that's used in the policy when the
Company made Deal A - - or , Deal B in general.
Okay.And it took me a long time to figure out
what I think you were saying with regard to the policy limits
so let me see if I understand this correctly.In the middle of
the page there, you're asked about the
- -
why you propose a
disallowance, and you say at lines 13 through 16:
Al so the Deal A gas purchase did not put the
Company over the long limit contained in its risk policy.The
Deal B purchase which was executed at a later point in time
caused the Utility to exceed the long limit.
Now , really, these deals were pretty much a
package deal, were they not?The underlying physical
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transactions were made and then the hedges were put on?
They were done - - I mean , they were separate
transactions and they have been categorized I think initially
by Staff as Deal A and Deal B , and, I mean , the timing was a
little bit different for the two.It's my understanding from
reviewing it that the Deal B transactions basically came later
in time than Deal A transactions as it went through the
process.
But wouldn't it be equally accurate to say that
collectively these deals put the Company over its risk
limits?
I think collectively
- -
collectively, they
brought the Company from a position that was well below load
resource balance to a position that was over the risk limits.
Okay.Now , the Company's position in an attempt
to justify these two deals is essentially that the spark spread
they were looking at was sufficient to ensure that they could
generate electrici ty at a price
- -
at the price they were
paying, they could generate electrici ty at a price that was
lower than the existing future market.Do you understand that
to be roughly the argument?
That's, yes, generally that's my understanding,
that they could generate electricity at a price that was below
the forward electric market that they were seeing at the time.
But did you find any evidence, any documentary
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evidence, that the Company made any attempt to analyze the risk
of the purchase price they were then locking in for natural
gas?
The evidence that I saw was the information
that's provided as part of the risk policy normal package of
analysis, and I guess I'm unsure.I think there are things
that could have happened and did happen to them that I didn I
see any analysis of.
Was there any stress test analysis of the gas
price they were locking in?
The risk policy says that stress tests will be
done at least from time to time.I don't bel ieve I saw the
resul ts of that if the Company did those.
You're aware that
- -
are you not - - that Potlatch
asked for documentation regarding the analysis of these
sales?
Yes am.
And you reviewed
di dn 't find anything?
the Discovery Responses and you
I didn't see anything there.
Okay.Now , isn'
- -
by simply locking in a price
on the grounds that some other transaction at the then-existing
future price might be favorable, to do that wi thout any
analysis of the gas price , let me give you an analogy and see
if you think it's apt:Wouldn't that be like contemplating a
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mortgage as rates are near all-time highs - - let's pick a
ridiculous number , 15 percent
- -
and locking that mortgage in
solely on the grounds that my income is sufficient to afford
it?
I don't know whether that hits it right on the
head or not.I think there are some portions of that that are
left out; I mean , some portions of what existed in reality that
aren't captured in your analogy.
Okay, well , let's make it a little simpler.
Wouldn't a prudent and reasonable person, when contemplating a
mortgage near decade-long highs, try to analyze the likelihood
that that mortgage rate would stay as high as it is when he'
making the decision?
Yes, I believe so.
Now , the other reason that or the other
recommendation you have in your testimony of the Company'
analysis is that , as you point out, the Company's analysis only
makes sense if , when you lock in the gas price , you also lock
in the electric prlce.Right?
I thought that would have allowed them to capture
the benefits of the situation at the time.
And if you don't do that, otherwi se , you run the
risk that this situation could move against you and on either
side of the equation; i. e., the natural gas price and the
electric price.Right?
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Yes.
And, In fact , Avista got the worst of all
possible worlds:It moved against them on both sides?
Yes.
And the way you summarize that is on page 17 of
your testimony, you say:
This philosophy could have worked
- -
that is
looking to the spark spread
- -
if the electric sale of the long
energy had also been made at the same time to lock in the gain
and reduce the long position.Absent such an electric power
sale, the transaction was purely speculation.
Now , and al so you say over on the next page, on
page 18, lines 16 through 17:
Customers should not pay for Avista to speculate.
And I assume you re referring to the same
problem; that is, the failure to lock in both sides of the
transaction.
I think that I s one part of it.I mean , that
would have eliminated the speculation , and possibly not
entering the transaction to begin wi th would have eliminated
the speculation , so there I s two ways of viewing that.
And by "speculation there," you mean it in the
strictest sense of the word; that is, the Company was
implicitly taking a price position by failing to lock in both
sides?
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I believe that was true.
Now , Mr. Hessing, did you participate in the last
Avista rate case?
I did.
And - - I I m going to test your memory here
- -
you recall that Potlatch also participated in that case?
Yes.
And didn't Potlatch take the position that when
the -- when Avista Utilities was engaged in speculative
transactions, that the ratepayers should be enti tIed to some
port ion of the gain?
I believe that's true.
And, in fact, in the end, the Commission rej ected
that , did it not?
It did.
But you might appreciate why Potlatch is so
committed to this issue if I read you this excerpt from the
Commission's Order:
It is Staff's belief that the speculative trading
engaged in by the Company is a discretionary acti vi ty that is
risky and not always profitable.If ratepayers are allowed to
share in the profits, they would also be subject to the losses
if they should occur.Staff believes that the Company s retail
customers should not be subj ect to such risks.Staff
recommends that the operational expenses incurred by the
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Company for these activities be excluded.
That appears at the top of page 15 of the Order.
MR. WOODBURY:Excuse me.
BY MR. WARD:Do you understand why, from
Potlatch's point of view , this looks like a complete breach of
faith?In other words, we didn't get to share in any of the
gains when there were gains, and now that we have a speculative
loss , contrary to what the Staff suggests here, the Company
asking for the ratepayers to pay it and Staff is acquiescing.
m referring to Deal A, of course.Is that consistent?
I think that to the extent that the Commission
finds that Deal A and Deal B were both speculative, it would be
consistent to disallow the losses on both , if that's what the
finding is.
I think the Commission and it's Staff's position
that Deal A certainly wasn't as speculative and we're not
calling it speculative.
Well , here's your testimony at page 17:
Absent such an electric power sale
- -
that
observation would apply to both Deal A and Deal B
- -
the
transaction was purely speculation.Quote , unquote.
Well , my reference, I was speaking mostly of
Deal B because that's what our position is in this case.The
Company was short on the risk policy.And if you want to look
a t them both together I ike you've suggested, you know , it takes
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them from a short position to a very long, out-of-limits
posi tion , in my opinion.But I believe those transactions can
be separated and that Deal A just brought them long within
limits , and we've chosen to not suggest that that should be
exc I uded .
But both Deal A and Deal B implicitly took a
price posi tion.Wouldn't you agree on that?
Yes.
Certainly,
position obviously?
the counterparties were taking a price
Yes.
I f Deal A - - given the fact that Avista put on
Deal A wi thout analyzing the risks of the gas price they were
paying --
MR . MEYER:I obj ect to the form of the question.
It assumes that
- -
the question posed assumes that it did so
without analysis of the risks or the prices it was paying, and
I don't think you can just assume that for purposes of the
quest ion.
COMMISSIONER KJELLANDER:Mr. Ward.
MR . WARD:Let me ask it a different way.
BY MR. WARD:Given the fact that there are no
documents memorializing any analysis by Avista of the risks of
the gas price it was taking
- -
paying - - and given the fact
that it was implicitly taking a price position across from
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knowledgeable party
- -
in fact, the party it retains as an
agent to purchase its natural gas
- -
if that's - - if that
transaction can pass the prudency test , what is left of the
prudency test in rate making?
MR. MEYER:You know , I'm sorry, I'm not trying
to make too fine a point here, but he says given the fact that
there was no documentation surrounding these transactions.
I don t think that's what this witness said and
that is not a fact established in the record.In fact,
contrary testimony is there in Mr. Lafferty's testimony where
he describes at pages 55 and 56 the sort of documentation that
has been provided in connection with these deals.So we can'
just assert as a fact based on the evidence in the record that
there is no documentation.
COMMISSIONER KJELLANDER:Mr. Ward.
MR . WARD:Mr. Chairman, first of all , the
evidence that Mr. Lafferty furnishes is largely post hoc
rationale.
Second , the question I have relates to the
typical documentation and the typical studies that would be
undertaken before a Utility would take a natural gas price
position as it did here.And Mr. Hessing has replied to my
questions and Dr. Peseau testifies to the same thing, that
there's no evidence of such documentation or even that such
considerations were undertaken when this deal was made.
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So I think the question is perfectly consistent
wi th the evidence, and, in fact, it goes to the heart of the
probl em.But even if it wasn't consistent with the evidence,
Mr. Hessing can correct me if he thinks that's an incorrect
conclusion.
COMM IS S lONER KJELLANDER:I think we're going to
allow the question , and the Commission can weigh both the
question and the response.
THE WITNESS:To the extent that I remember the
question , I have already agreed that I haven't seen written
documentation of such an analysis.
I m not necessarily convinced - - well , I don'
believe that the Company makes those kinds of decisions without
a review process , whether they wri te it down or not.That
doesn't mean that they reviewed the price position and all of
the circumstances that could have and many of which eventually
did occur here.
I think that when the Company enters into such
transactions as this, that there needs to be a lot of
documentation for the review process.I haven't seen it all
here.That part of the argument I guess goes to both Deal A
and Deal
BY MR. WARD:Okay.One final thing:
If the requirement that Utility expenses must be
prudently incurred to be included in rates were read to mean
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only that or were read to mean that the other parties must
prove something equivalent to self -dealing or fraud to disallow
expenses, that prudency requirement wouldn't mean much , would
it?
It would be pretty difficult to show.It would
be really difficult to show with the information that most
parties have regarding the Utility's dealings.
MR . WARD:Thank you.That's all I have.
COMMISSIONER KJELLANDER:Thank you, Mr. Ward.
Let's see.Mr. Purdy, have we asked you yet?
MR . PURDY:I don t remember, but I don't have
any questions.
COMMISSIONER KJELLANDER:Okay.And Mr. Meyer.
MR . MEYER:Thank you.
CROSS - EXAMINATION
BY MR. MEYER:
At page 17 , beginning at line 14 - - and we don't
necessarily have to turn there , but you say the Company created
a speculative long position through the Deal B hedge
transactions.
Would you generally agree, Mr. Hessing, that
Avista evaluates its loaded resource positions and the need for
resources on both a short- and a long-term basis?
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Yes, I think that the Company does , and that'
been the Company's posi tion in this case.I think there are
some reasons or some uses for short- and long-term Vlews that
differ with regard to resource planning and the acquisition of
resources versus the acquisition of fueling those resources for
extreme events, and I think that's part of what we're talking
about here and a part of what the differences are between the
Company's Vlew and the Staff's view.
Well , I'd like to just at the outset maybe clear
up some definitional issues so we're using the same
terminology.There's a difference between, of course, cri tical
water planning and average water planning?
Certainly.
And just, very briefly, describe that.
Well, I think the Company has quantified it as
approximately 150 average megawatts.When you plan for
critical water situation , if you accept 150 megawatts as being
that difference , you may plan for 150 megawatts more in terms
of resources.And those may be generating resources that can
be fueled when you have some knowledge or begin to understand
that that situation may occur , or they can, once you know that
you're headed for that kind of situation , you can fuel those
resources and you can have the resource and the fuel and have
the abili ty to generate the energy needed.
So - - but the del ta between cri tical and average
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water planning is approximately 150 average megawatts.
Correct?
That's my understanding.
And is there another type of analysis that the
Company has talked about in this case , it's called 90 percent
conf idence interval planning?
Yes.
And is it
- -
is it your understanding that at the
time the Company entered into Deal B , that it had conducted a
statistical analysis of the variability of loads and hydro
generation at a 90 percent confidence interval?
That's the Company's testimony.
And you have no reason to dispute that?
I have no reason to dispute that.
And , of course, the purpose of this confidence
interval planning was to determine the resources that would be
required to cover this variability.Correct?
Yes.
And I'd like to add a little bit of definition to
resources. "I mean , I think there's a difference between
having the physical hardware setting on the ground to generate
power and fueling those resources to meet a critical water
situation.
Would you agree -- just, again , we're just
talking definitionally here
- -
but would you agree that based
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Staf f
on a 90 percent confidence interval plan , that that statistical
analysis showed that it would require not 150 average megawatts
but 170 average megawatts of additional resources to cover load
and resource variability?
Yes , that's what the information presented by the
Company says , and I have no reason to not believe that.
Would you now - - sorry to take you back to
Mr. Lafferty's Exhibi t 7 , please.Do you have that in front of
you?
I do.And that's his direct testimony?
Yes , it is.
Oh.
The Exhibi t 7 , Schedule 26 , and it looks
something like thi s .Exhibi t 7 , Schedule 26.I can provide
you a copy if you'd like.
I think I have it.It might take me a moment to
get it out here.
MR . MEYER:May I just approach the witness and
can speed things up?
COMMISSIONER KJELLANDER:Absolutely.
MR . MEYER:Let the record show that I handed to
Mr. Hessing a copy, another copy, of Exhibi 7, Schedule
(sic)
BY MR. MEYER:Now, would you agree that this
graph represents the Company I s resource posi tion
- -
excuse me.
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COMMI S S IONER KJELLANDER:Excuse me.Is that
Schedule 16?
MR . MEYER:I think it was Exhibi
THE WITNESS:Schedule 26.
MR . MEYER:26.m sorry, dropped the
COMMISSIONER KJELLANDER:Thank you.
MR. MEYER:Exhibi t 7 , Schedule 26.
BY MR. MEYER:Would you agree that this graph
represents the Company's resource position based on long-term
planning cri teria at the time of the Deal A and B hedge
transact ions?
Yes, I bel ieve it does.
And would you agree if you look at the box
MR. WOODBURY:Mr. Chairman , could I ask a little
direction as to whether we're talking about page 1 or page 2 of
Exhibit 26?There are two graphs.
MR . MEYER:m sorry.It's page
COMMISSIONER KJELLANDER:Thank you for that
clarification.
MR. WOODBURY:Thank you.
BY MR. MEYER:I f you look in the upper
right -hand corner of page 2 of that schedule , would you agree
that even wi th the Deal A and B hedges, that the Company'
long-term resource position reflects a deficit of 84 average
megawatts for 2002 and a deficit of ten average megawatts for
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2003, approximat ly?
And, of course, this is relative, likeYes.
you said earlier , to the Company's - - I guess this is the
90 percent confidence interval planning which assumes poor
wa ter condi t ions and high load condi t ions.So, yes, relative
to that assumption as being the balance point, that's correct.
And, again, 90 percent conf idence interval
planning would suggest, as we previously discuss, a deficit or
a figure of about 170 average megawatts compared to 150 average
megawatts for critical water planning.They re about the same.
Correct?
Yes.
On the subj ect of risk policy generally, would
you agree that as you look at the risk policy as a whole and
what it intends to accomplish , that positions that exceed
limits are not a violation of the policy if necessary waivers
are obtained?
When - - the policy provides for the ability to
wai ve anything in there, so, you know
- -
so I guess certain
condi t ions can be waived for certain reasons, but there's a
limit to where the policy doesn't become of any value anymore
if you waive too much.
Well , but in fact, the policy itself contemplates
in its very wording that waivers of time to cure can be had.
Correct?
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They can be had.
Yes.And I assume that you would agree that one
of the purposes of the risk policy is to assure that there is a
deliberate, intentional , decision-making process around those
wal vers Correct?
Certainly.
Okay.Would you turn this time to
- -
back to
Exhibi t 7 , but a different schedule, Schedule 31?
MR . MEYER:And maybe again just for the
convenience of the wi tness, I'll provide my copy.And this
Exhibi t 7, Schedule 31 , page 11 of 30.
BY MR. MEYER:Would you agree that on this page
are shown examples of out of limit positions?
Yes.
And would you al so agree that as you look to the
right-hand column entitled Comments, that in each case, there
is an indication that the risk management committee expressly
addressed these out of limit positions and provide -- provided
a knowing waiver of the cure date?
Yes, that's what it says.
Okay.Do you have - - do you have information to
suggest that the hedging that occurred wi th Deals A and B did
not reflect forward market prices at the time they were entered
into?
I do not.
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In other words , would you agree that Deals A
and B , at the time they were entered into, reflected the cost
of the gas that the Company chose to lock in prices for; in
other words, a cost defined by those forward market prices?
I have seen information provided by the Company
that showed that forward electric prices were high enough to
justify purchasing gas at $6 if that's the only consideration
that is viewed.
Is it -- before we turn to that, you were asked a
few questions I believe by Mr. Ward about both sides of the
transaction.If Avista had sold the power , as has been
suggested to you, in order to lock in the gain, wouldn't it
simply have recreated a short position for the Company?
I think if Avista had sold the power that
purchased to meet its needs, had physically sold it, it would
have created a short position.
I think Avista had an opportunity to physically
sell, at least in one scenario, long -- power that it was long
on that it wouldn't have created a short position for, and
also think that there are some options for purely financial
transactions that might have locked the price without selling
the power.
But all else being equal , if we had sold that,
those posi tions, it would have recreated the short posi tion.
Correct?
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If you would have physically sold the power,
would have recreated whatever short position the Company had,
but that wasn't the only position the Company had.
Is it your understanding that the Company sold
some Deal B gas but at the same time purchased lower-cost
electricity based on notions of economlC dispatch?
It's my understanding that that happened quite
often during the Deal B period.
And you're not taking exception to that?
No.
And, in fact, in other words, it did so where
could, or to purchase electricity at a lower cost than it would
otherwise cost to generate it.That was the purpose of it.
Right?
I believe that's, yes, that was the purpose in
doing that.
But in any event, the Company used the purchased
electricity to serve customers' loads.Correct?
Yes.
You're suggesting in your testimony a
disallowance of approximately six and a half million relating
to Deal Correct?
That's correct.
And you understand that in the Company's rebut tal
testimony provided by Mr. Lafferty, we suggested some other
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alternatives for resolving the Deal B issue?
That I S correct.
Would you agree that another alternative to your
six and a half million dollars disallowance relating to Deal B
might be to essentially calculate or to include the loss on
Deal B gas sales only when those sales were made wi th no
corresponding electricity purchase?That's an al ternati ve?
I think that is an al ternati ve.I think that the
Commission would have to find something different than what the
Staff's position is in this case to arrive at that as a
reasonable posi tion.
But would you agree that under this al ternati ve,
counting the loss on Deal B gas that was sold without
without the purchase of replacement electricity would result in
a disallowance of approximately $4 million, as opposed to the
6 million that you suggest?
I believe those calculations are correct.
And would you agree that in excluding the loss on
gas sales where there was, in fact, a corresponding electrici
purchase, is similar to what you have talked about and proposed
in your testimony in that it does not include the loss on
energy that was ultimately used to serve retail load?
To that, with that in mind, it is similar.
So is this al ternati ve at least something that
this Commission might consider?
1307
HEDRI CK COURT REPORTING
O. BOX 578, BOISE, ID
HESSING (X)Staff83701
I think the Commission can consider that
al ternati ve, but in order to do so, I think the Commission has
to believe that it was appropriate in the first place to enter
into the Deal B transact ion.
MR. MEYER:Thank you.
COMMISSIONER KJELLANDER:Thank you, Mr. Meyer.
Let's move to any questions from members of the
Commission.Commissioner Hansen.
EXAMINATION
BY COMMISSIONER HANSEN:
Mr. Hessing, I know what you've stated in your
testimony; however, I guess I'm just a little confused by your
answers to Mr. Ward's questions and I would like you to clarify
for me again, if you would, whether you think Deal A was
speculative or not, and if it was not, would you explain agaln
why it is not?
Well , I think Deal A had some common
characteristics with Deal B and it took a price view at the
time, but it wasn't speculative, in my mind, I guess beyond
what I've already said , because it aligned the Company's loads
and resources for the future and within the limits that were
set in the Company's risk policy; and it was Deal B that went
beyond the limits of the risk policy and the one which is part
1308
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HESSING (Com)Staff
of the reason that Staff is challenging the costs of Deal
I guess just a follow-up and I'll probably have
to go back and read the transcripts, but I got the impression
under a couple of the questions of Mr. Ward's that you thought
that Deal A could be speculative.Is that
- -
am I getting the
wrong read on that?
I think there were some concerns.Deal A and
Deal B had some common concerns.I don't believe that Deal A
was, quote, speculative, for the reason that I just stated.
COMMISSIONER HANSEN:Thank you.That's a II
have.
COMMISSIONER KJELLANDER:Are there further
questions from members of the Commission?Commissioner Smi th.
EXAMINATION
BY COMMISSIONER SMITH:
Yes, Mr. Hessing, I've been pondering
Mr. Yankel' s testimony and rate structure for Schedule 25.
Could you refresh my mind on why we class customers into
different classes and schedules?What was the purpose of
that?
Well, I think there are different customer
classes because there are large differences, substantial
differences,the way those customers use energy,and I t h i nk
1309
HEDRI CK COURT REPORTING HESS ING ( Com)
BOX 578 BOISE 83701 Staff
it's a belief that for administrative reasons they have to be
put in separate classes; and that when we do a class
cost-of-service study or a rate design study, that we'
capturing similarly-situated customers to the extent that
we can In applying the common rates.
But when we group people together in a class and
we have - - assuming they have some similar characteristics, no
customers are identical, are they?
True.
So when I look at Exhibit 305 and I note that for
Schedule 25 the annual energy usage varies from something less
than nine million kilowatt hours up to something more than
46, 000, kilowatt load factors range from 91 percent down to 33
have we captured a similarly-situated group of customers?
there something wrong with who is in Schedule 25?Or is this
just a fairly typical diversity within a class that we live
with?
Well , I think
- -
I think those higher numbers
that you're referencing there are probably Potlatch , and it'
only been a fairly recent thing that Potlatch has been a
Schedule 25 customer of the Company.They were a spec ial
contract customer before that and there has been some
discussion in this case about whether they should be a special
contract customer again.
I think Staff witness Schunke has some opinions
1310
HEDRI CK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
HESSING (Com)Staff
in his testimony and might be willing to discuss that with
better information than I have.
Good.Thank you.
COMMI S S lONER KJELLANDER:Thank you.
Ready now for redirect.
MR.WOODBURY:Thank you Mr.Cha i rman .
REDIRECT EXAMINATION
BY MR. WOODBURY:
Mr. Hessing, just one area of questioning with
respect to Mr. Meyer's cross regarding Exhibi t 7 , Schedule 31
page 11 of 30 , of I believe it's Mr. Lafferty'That was a
time to cure type of schedule?
I have that.
And are you familiar with the manner in which the
risk management committee operates , and this seems to indicate
that they review things on a monthly basis?
I know they review things regularly and meet
regul ar I
y .
I don't know whether that's just monthly or not.
And do you know in Staff's review in this case
whether the risk management commi t tee on a monthly basis
presents documentation of their decisions and analyses?
The information that I reviewed did not include
minutes from the risk management committee meetings , but I do
1311
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
HESSING (Di)
Staff
believe that the Staff auditors involved in some of these cases
have reviewed those kind of minutes.
And have - - did you
- -
so then you didn'
personally review any supporting documentation with respect to
the comments section of this particular schedule?
, I did not.
MR . WOODBURY:Thank you , Mr. Cha i rman .Staff
has no further questions.
COMMISSIONER KJELLANDER:Thank you,
Mr. Woodbury.
And thank you , Mr. Hessing.Appreciate your
presence and your testimony today.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:I bel ieve we're ready
now for Staff's next wi tness.
MR . WOODBURY:Staff I S next wi tness is
David Schunke.
1312
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HESSING (Di)Staff
DAVID SCHUNKE
produced as a witness at the instance of Staff, being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MR. WOODBURY:
Mr. Schunke, will you please state your name,
spell your last name for the record?
Yes.My name is David Schunke.Last name is
spelled S-
And , Mr. Schunke, for whom do you work and in
what capacity?
I work for the Idaho State Public Utilities
Commission as the engineering supervisor.
And in that capacity, did you have occasion to
prepare and prefile testimony in this case consisting of 21
pages, and six exhibits , Exhibits 143 through 148?
Yes, I did.
And have you reviewed that testimony and those
exhibi ts prior to this hearing?
Yes, I have.
And it I S my understanding you have a few
correct ions to make?
Yes, I do.
1313
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
SCHUNKE (Di)Staff
Could you lead us through those?
On page 16 of my testimony, line 10, the essence
of this change is to add Schedule 25 to this sentence.So the
sentence should read:The Company should be prepared to
demonstrate that the Schedules 21 , 22 , and 25 tail blocked
rates exceed the Company's variable costs and provide a small
contribution to the Company's fixed costs.
So --
COMMISSIONER SMITH:m sorry, I'm lost.Where
are we?
THE WITNESS:We're on page 16 at line 10.
BY MR. WOODBURY:So then the change that you'
making is you're taking out the "and" on line 10 between "21"
and " 2 2" and insert ing a comma, and after " 2 2" insert ing "and
25"?
Yes.
Are there any other changes that you need to
make?
Yes.On page 17 , line 6 , the " 13 .5 percent"
should be changed to "1 7 . 2 percent.
Q .And what is the reason for that change?
Just a typo.It's - - I didn't change the - - it'
just a typo.
And any additional changes?
On my Exhibit 143, the column headings are
1314
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
SCHUNKE (Di)Staff
incorrect, and they should simply be one through 12, and if you
notice there , there's mislabeling of the column headings , so
I see you have one, two, three , four , six, five,
six, seven , and so
Right.
- -
you re changing those?
Are there any other changes to your testimony or
exhibits?
No.
And if I were to ask you the questions set forth
in your testimony, would your answers then be the same?
Yes.
MR. WOODBURY:Mr. Chairman , I'd ask that
Mr. Schunke' s testimony be spread on the record as if read, and
that Exhibits 143 through 148, as corrected, be admitted.
COMMISSIONER KJELLANDER:Wi thout obj ection,
we'll spread the testimony of Mr. Schunke across the record as
if read , and admit Exhibits 143 through 148.
(The following prefiled direct testimony
of Mr. Schunke is spread upon the record.
1315
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
SCHUNKE (Di)
Staf f
Please state your name and business address
for the record.
My name is David Schunke and my business
address is 472 West Washington Street, Boise, Idaho.
By whom are you employed and in what
capaci ty?
I am employed by the Idaho Public Utilities
Commission as a Public Utilities Engineer.
What is your educational and experience
background?
I received my Bachelor of Science Degree in
Civil Engineering at Montana State Uni versi ty in 1972.
have been licensed as a Registered Professional Engineer
in Idaho since 1977.I have worked in various capacities,
including a Cost and Materials Engineer with Morrison
Knudsen Co., Inc. and a consul ting engineer wi th Stevens,
Thompson & Runyan (STRAAM Engineers) As a consul tant, I
worked as Project Engineer on numerous civil engineering
proj ects in Idaho and Oregon for more than ,six years.
Since joining the Commission Staff as a
Utilities Engineer in 1979, I have been continuously
involved in rate design and regulatory matters with
virtually all the water , gas and electric utilities
regulated by the Commission.I served as the Engineering
Section Supervisor from 1983 to 1991, Utili ties Division
CASE NOS. AVU-04-1/AVU-04-06/21/04 1316
(Di)SCHUNKE, D.Staff
Deputy Administrator from 1991 through 2000 and Engineer
Manager from 2001 to present.
INTRODUCTION AND SUMMARY
What is the purpose of your testimony?
The purpose of my testimony is to describe
Staff's rate design proposal for electric and natural gas
tariff customers.
How is your testimony organized?
My testimony consists of a summary of my
recommendations for both electric and natural gas service
followed by:
(a)A general discussion of my rate design
obj ecti ves for electric service.
(b)An explanation of how Staff proposes to
distribute the revenue requirement to the electric
customer classes, and
(c)Based on the resul ting revenue
requirement for the various customer classes, I then
provide specific rate design proposals for each electric
customer class.
( d)A general discussion of my rate design
obj ecti ves for natural gas service.
(e)An explanation of how Staff proposes to
distribute the revenue requirement to the customer
classes, and
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)SCHUNKE, D.Staff
1317
(f)Based on the resul ting revenue
requirement for the various customer classes, I then
provide specific rate design proposals for each natural
gas customer class.
Please summarlze your testimony.
I am making recommendations for the electric
and natural gas tariff rates.These rate proposals are
based on the staff proposed. overall revenue increase in
Base Rates for electric serVlce of $23 million or 15. 8%,
and an overall lncrease of $3.1 million (6.0%) for natural
gas serVlce.These rate proposals are also based on the
cost of service resul ts discussed by Mr. Hessing
(electric) and Mr. Fuss (natural gas) The recommended
increases would move all customer classes closer to cost
of service.Recommended percentage increases for each of
the electric service schedules are shown in Staff Exhibit
No. 143.They are as follows:
Residential Service Schedule 1 -18.
General Service Schedules 11 and 12 -11.
Large General Service Schedules 21 and 22 -12.
Extra Large General Service Schedule 25 -20.
Potlatch (Lewiston) Schedule 25 -14.
Pumping Service Schedules 31 and 32 -13.
Street and Area Lighting Schedules 41-49 -17.
I am recommending no increase in the basic
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)SCHUNKE , D.Staff
1318
charge or the minimum charge for Residential Schedule 1.
While I am opposed to the Company s proposal for declining
blocks for Schedules 11 , 21 and 25, I am recommending that
the Company s proposal be accepted for this case wi th the
requirement that additional information be gathered by the
next general rate case so the Company can provide a
proposal to:
( 1 )divide Schedule 11 into two separate
schedules, one demand metered and the other not demand
metered;
(2 )eliminate the declining block rates in
Schedule 11;
(3 )provide a proposal to eliminate the
declining block rates in Schedules 21 and 25, and
(4 )implement time-of -use (TOU) rates
wherever they are practical.
Changes in revenue for the natural gas
servlce schedules are shown in Staff Exhibit No. 146.The
percentage increases for each schedule are as follows:
Residential Schedule 101 -97%
Large General Service Schedule 111 -78%
Large General Service High Load Factor Schedule
121 -86%
Interruptible Service Schedule 131 -45%
Transportation Service Schedule 146 -6 . 94
CASE NOS. AVU-E- 04 -l/AVU-G- 04-06/21/04 (Di)S CHUNKE , Staff
1319
Special Contracts -0 . 0%
The proposed increase for Transportation Service Schedule
146 excludes gas costs.If gas costs were included the
resul ting increase would be approximately 1.5%.
RATE DESIGN OBJECTIVES
What are Staff's rate design objectives?
The utility industry and this Commission have
had a long history of pricing power differently to
customers with different load and usage characteristics.
Residential customer rates differ from those of commercial
and industrial customer rates because the cost of
providing service differs depending on the characteristics
of the end use.Large loads wi th high-load factors
(constant use) tend to be less costly per kWh to serve
than pmaller loads with large fluctuations.Time-of -use
is also a maj or factor in determining the cost of service.
These differences are generally addressed by grouping
customers wi th similar end-use characteristics together.
They form a rate class such as residential , commercial,
pumping, industrial or lighting.The cost of providing
service to the various customer classes has been addressed
in the cost of serVlce (COS) studies discussed by Staff
wi tnesses Hessing and Fuss.The first obj ecti ve in rate
design is to set rates that are more closely aligned to
the cost of providing service.
CASE NOS. AVU-04-1/AVU-04-06/21/04
(Di)SCHUNKE , D.Staff
1320
It is also an obj ecti ve to keep rates
reasonable by balancing the cost of service goals wi th the
goals for simplicity, for minimizing rate shock , and for
promoting conservation - especially during high cost
periods.
The Company was not able to provide the data
necessary to divide Schedule 11 and 21 into multiple
schedules.Therefore several of my recommendations are
directed at the Company s next rate filling when these
issues can be more fully addressed wi th adequate data.
CUSTOMER CLASS REVENUE ALLOCATION - ELECTRIC
What cost of service study is Staff'
electric rate design proposal based on?
Staff witness Hessing has reviewed the
Company s cost of service (CaS) analyses, which he
discusses in his testimony.This is the COS methodology
that Staff believes is most appropriate and is the one
Staff has based its electric rate design analysis on.
Does Staff's rate design proposal strictly
follow the COS resul ts?
Staff witness Hessing proposes only anNo.
incremental move toward full cost serVlce
recogni tion the fact that cost serVlce resul ts are
not preclse and unacceptably large lncreases some
classes would occur.Staff's proposal for the revenue
CASE NOS. AVU-04-1/AVU-O4-06/21/04 1321
(Di)S CHUNKE , Staff
requirement lncrease for each rate class is comprised of
two parts.First, 20% of the increase dictated by cost of
service, is added to each class.The remainder of the
necessary revenue requirement increase is spread to each
rate class on a uniform percentage.These two adj ustments
shown in Column 5 and 6 of Staff Exhibi t No. 143 are added
to the Current Base Revenue to arrive at the Staff-
Proposed Base Revenue shown in Col umn 7 of Staff Exhibi
No. 143.These are the amounts that Staff used in its
rate design proposals and each class is moved 20% closer
to COS.
Why is the Staff proposal based on a move to
cost of service of only 20%?
One of my obj ecti ves in rate design is to set
rates that are more closely aligned to the cost
providing service.However , it - is also an objective to
keep rates reasonable by balancing the cost of service
goals with the goals for simplicity, for minimizing rate
shock , and for promoting conservation.I believe that a
20% move to COS balances these obj ectives to achieve
reasonable rates for all customer claBses.
In the last general rate case for Avista both
the Company and Staff recommended a 1/3 move to cost of
service for all customer classes.The Commission approved
a 20% move the first year and an additional 15% move the
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)SCHUNKE, D.Staff
1322
following year in order to accomplish the one-third move
proposed by the Company.In that order , the Commission
found:
Cost-of-service , however , is only one of
many factors to be considered by this
Commission in tariff design;
Order No. 28097 at 27
Important interests in rate stability
and continui ty preclude adopting the
extremely large double digit shifts in
revenues from one class to another that
were requested. In addi tion , we recognized
that the resul ts of cost -of - service studies
are not so precise that the determination
of appropriate revenue shifts is an exactcertainty.
Order No. 28097 at
In the recent Idaho Power general rate case
the Commission approved a 13.95% increase to the
irrigation class , which also represented a 20% move to
COS.In that order the Commission stated:
we find that the revenue requirement
assigned to the irrigation class should
be less than indicated by the cost ofservice study. The Commission has often
stated that consideration such as ratestabili ty and proportionali ty justify
limiting the amount of the rate increase
to any class of customers.
Order 29505 at
Staff believes that circumstances in this case also
justify limiting the COS adjustment, and we believe that a
20% move to COS is reasonable.Moving the residential
CASE NOS. AVU-E- 04 -l/AVU-G- 04-06/21/04 (Di)SCHUNKE , D.Staff
1323
class to full COS would require a rate increase of 30.7%.
Comparing the 20% Year 1 move to COS in the
last Avista general rate case and the 20% move being
proposed here , what is the magni tude of the increase
proposed in this case for Residential Schedule 1 and
Schedule 25 as compared to the increases in the last
Avista general rate case?
In the last Avista general rate case, a 20%
move to COS resul ted in increases to Residential Schedule
1 and Schedule 25 of 9.5% and 10%, respectively.In this
case, a 20% move to COS resul t s in an 18. 8 % increase to
Residential Schedule 1 and a 20% increase to Schedule 25.
By further comparison , in the last Idaho Power Company
general rate case, a 20% move to COS for the irrigation
Schedule 24 resul ted in a 13.95% increase to irrigators.
The impact of a 20% move to COS in this case
considerably greater than in the two cases ci ted.
Are you recommending a second step adj ustment
in COS at a later time, similar to what the Commission
ordered in the last rate case WWP-E- 98 -(Order No.
28097) ?
If the Commission finds that an additional
step in COS is needed, I am recommending that COS be
reviewed when the PCA balance drops to zero, or at the
next general rate case.If the Commission accepts the
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)SCHUNKE , D.Staff
1324
recommendation of Mr. Hessing to base the PCA adj ustment
on ~/kWh rather than uniform percent of revenue, that may
be an appropriate time to consider an additional
adjustment to COS.A general rate case is always an
appropriate time to review COS.
Are your rate design proposals limited to the
base rates?
My proposals are limited to base ratesYes.
and do not address the other rate adders including, PCA
rates, DSM rider , Centralia credit or the Residential
Exchange (BPA) credi
RATE DESIGN - RESIDENTIAL
What change in revenue requirement is Staff
recommending for Residential Schedule
Staff recommends an average overall increase
In revenue of 18.8% to Residential Schedule 1'
What is your recbmmendation for the
Residential Schedule 1 rate design?
I am recommending that (1) the basic charge
and minimum charge remain at $4.00;(2) the energy rate
for the first 600 kWh increase by 21.9% to $0. 05554/kWh
and (3) the rate for energy use in excess of 600 kWh/month
be priced 18.8% higher at $.06302/kWh.
Staff Exhibi t No. 144 shows the present and
proposed rates on page 2 along with the resulting revenue
CASE NOS. AVU-04-1/AVU-04-
06/21/04
(Di)SCHUNKE, D.Staff
1325
for Residential Schedule 1 on page 4.The proposed
increase for a residential customer using an average of
941 kWh per month is $9.40 per month or a 18.8% increase
in their electric bill.(The present bill for base rates
without the PCA for 941 kWh is $49.41 compared to the
proposed level wi thout the PCA of $58.82. Curren t and
proposed base rate bills are compared on Staff Exhibit No.
145.
The Company has proposed an increase in the
residential basic customer charge and minimum charge from
$4.00 to $5.00.Do you agree wi th this proposal?
The Company s proposal increases theNo.
customer basic charge and minimum charge 25%.Thi s woul d
have a disproportionate affect on customers wi th low
usage.I believe the basic charge and minimum charge
should remain at $4.00.
Why do you believe there should be no
increase in the customer basic charge and minimum charge?
The customer basic charge should be based on
the direct cost of meter reading and billing and should
not include any fixed plant cost.I believe this
consistent with the recent Commission order in an Idaho
Power rate case (Order No. 29505 at 53) "The Commission
finds that a monthly service charge should recover costs
that are directly attributed to the customer paying the
CASE NOS. AVU-04-1/AVU-04-
06/21/04
(Di)SCHUNKE, D.Staff
1326
charge.
, ,
Typically, those charges are related to meter
reading and customer billing.
The monthly cost associated with meter
reading and billing is $2.62 for this customer class.
Therefore, I believe no increase can be justified.
therefore believe the current rate of $4.00 is the
appropriate amount for both the basic and minimum charge.
RATE DESIGN SCHEDULE 11 and
What change in revenue requirement is Staff
recommending for General Service Schedule 11 and 12?
Staff is recommending an average overall
increase in revenue of 11.4% to General Service Schedule
11 and 12.
The Company has proposed an addi t ional energy
usage block that would provide a lower energy rate for
usage in excess of 3650 kWh per month.Do you support
thi s change?
I am opposed to the Company s proposal for
declining block for Schedules 11.However, I am
recommending that the Company s proposal be accepted for
thi s ease.I recommend that prior to the next general
rate case, the Company should gather sufficient data to
provide a proposal to eliminate the declining block rates
and divide Schedule 11 into two separate schedules, one
demand metered and the other not demand metered.
CASE NOS. AVU-E- 04 -l/AVU-G- 04-
06/21/04
(Di)SCHUNKE , D.Staff
1327
The Company argues that the declining block
rate is needed for Schedule 11, because under the present
rates, customers whose demand exceeds 20 kW end up being
billed a higher average amount per kWh than customers
using less than 20 kW.Do you agree?
It is true that the present rates effectively
bi II customers, wi th demand that exceeds 20 kW , a higher
amount per kWh than customers using less than 20 kW per
month.However, this is true only because the Company has
customers on Schedule 11 who are NOT demand-metered.
Schedule 11 , which has a demand charge, includes both
demand-metered customers and non-demand metered customers.
The non-demand metered customers , who cannot be billed for
demand, are assumed to use less than 20 kW.Therefore, no
customer in the class is billed for the first 20 kW of
demand.The effect this has on demand-metered customers
wi th higher usage is that they tend to pay more per kWh.
Do you believe there is a better more direct
solution to this problem than creating declining block
rates?
Yes.Two separate schedules should be
created. One for the demand metered customers and one for
the non-demand metered customers.Having both demand-
metered and non-demand metered customers on a demand
schedule is the real problem.The Company fix to not bill
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)S CHUNKE, Staff
1328
16
the first 20 kW of demand only created a new problem which
is higher use customers paying effectively more per kWh.
The Company s proposed fix for this is a declining block
rate.I believe the real fix is to create two separate
schedules.
Unfortunately the Company does not have
sufficient data at this time to separate the schedule
between demand and non-demand metered customers.
Therefore, I am recommending that the Company s proposal
for a declining block be accepted until the data can be
made available to properly separate the schedule.The
Company should be directed to collect the necessary
customer data and the rate class- should be separated as a
part of the next general rate case.
What rates are you recommending for General
Service Schedule 11 and 12?
I am recommending no change in the basic
charge the minimum charge or the demand charge.The
energy rate for the first 3650 kWh per month should be
7. 527 ~/kWh and for usage above 3650 kWh per month should
be 6.398 ~/kWh. Staff Exhibit No. 144 , page 2 , shows the
present and Staff -proposed rates along wi th the resul ting
revenue on page 4 for Schedule 11 and 12.
RATE DESIGN LARGE GENERAL SERVICE SCHEDULE 21 and
What is the overall rate change recommended
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)S CHUNKE , Staff
1329
by Staff for the Large General Service Schedule 21 and 22?
Staff recommends an overall revenue increase
of 12.9%.
What is your recommendation for the Large
General Service Schedule 21 and 22 rate design?
I am recommending that the Company s proposal
for the second block energy rate and the increases to the
demand charges be accepted.The first block demand charge
would increase from $225 to $250 and the second block
demand charge would increase from $2.75 to $3.00.The
first block energy rate would be 4. 664 /kWh and the
second block would be 3. 964 /kWh.These rates are shown
\ on Staff Exhibit No. 144 , page I al so recommend that
the Company develop additional information before the next
rate case assessing the economical impact of the second
block to justify continual use of a declining block energy
charge.
RATE DESIGN EXTRA LARGE GENERAL SERVICE SCHEDULE
What is Staff's recommended change in the
revenue requirement for Extra Large General Service
Schedule 25 (including Potlatch)?
Staff recommends an overall revenue lncrease
of 20% for Extra Large General Service 25, with Potlatch
recel vlng a 14.9% increase.
What is your recommendation for Schedule
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)SCHUNKE, D.Staff
1330
8 '
rate design?
I am recommending that the Company s proposal
for the second block energy rate and the increases in the
demand charges be accepted.The first block demand charge
would increase from $7,500 to $9 000 and the second block
demand charge would increase from $2.25 to $2.75. The
first block energy rate would be 3. 873 /kWh and the
second block would be 3.26 8 /kWh.These rates are shown
on Staff Exhibit No. 144 , page The Company should be
prepared to demonstrate that the Schedule 21 and 22 tail
blocked rates exceed the Company s variable costs and
provide a small contribution to the Company s fixed costs.
RATE DESIGN IRRIGATION SCHEDULE 31
What is Staff's recommended revenue
requirement increase for Pumping Schedule 31?
Staff recommends that Schedule 31 rates be
increased by 13.5%.
What is your rate design proposal for
Schedule 31?
I accept the Company s recommendation that
all of the proposed increase for Schedule 31 be applied to
the energy rate.The first block energy rate would be
295 ~/kWh and the second block energy rate would be
5 . 3 51
~ /
kWh.The basic charge would remain at $6.00.
These rates are shown on Staff Exhibit No. 144 , page
CASE NOS. AVU-04-1/AVU-G-O4-06/21/04 (Di)S CHUNKE, Staff
1331
RATE DESIGN STREET AND AREA LIGHTS SCHEDULES 41-
What is Staff's recommended revenue
requirement increase for Street and area lights Schedule
41-49?
Staff recommends that revenue for Schedules
41-49 be increased by 13.5%.
What is your rate design proposal for Street
and Area Lights Schedules 41-49?
I am recommending a uniform increase in all
the Schedule 41-49 tariff rates to accomplish the 17.
lncrease In revenue.
NATURAL GAS GENERAL
How did Staff calculate the revenue
allocation between the natural gas customer classes?
Staff balanced the obj ecti ve to move each
class closer to cost of service wi th the obj ecti ve of
achieving an equal contribution to the non-gas related
costs (which is referred to the margin) from Schedules
121 , 131 , and 146.Staff's proposed revenue allocation
between classes was achieved by starting wi th the cost of
servlce resul ts provided by Mr. Fuss.Then Schedules 121
131 and 146 were moved closer to an equal contribution to
the margin.
What cost of serVlce study is Staff's rate
design proposal based on?
CASE NOS. AVU-04-1/AVU-04-
06/21/04 1332
(Di)SCHUNKE , D.Staff
Staff witness Fuss has completed a review
the Company s gas cost of service (COS) analyses and has
made a number of adj ustments, which he discusses in his
testimony.This is the cost of service methodology that
Staff believes is most appropriate and is the one Staff
has based its natural gas rate design analysis on.
Why is it important to equalize the
contribution to the non-gas related costs (margin) for
Schedules 121 , 131 , and 146?
In order to discourage swi tching between
schedules and to protect against a revenue shortfall for
the Company the margin for each of these schedules should
be fairly close.The difference in the margin in Staff'
proposal is equal to the difference in the Company s rate
proposal.
The Final Revenue allocation is shown in
Column '' of Staff Exhibit No 146.This is the amount
that Staff used in its rate design proposals.Present and
proposed rates for all the natural gas schedules are
summarized in Staff Exhibit No. 147 , pages 2 , 3 and 4 and
again on Staff Exhibi t No. 148.
GENERAL SERVICE SCHEDULE 101
What change in revenue requirement is Staff
recommending for Residential Schedule 101?
Staff recommends an average overall increase
CASE NOS. AVU-04-1/AVU-04-06/21/04 1333
(Di)SCHUNKE, D.Staff
In revenue of 6.97% to Residential Schedule 101.
What is your recommendation for the
Residential Schedule 101 rate design?
I am recommending that (1) the basic charge
and the minimum charge remain at $3.28, and (2) the energy
rate be increased to 79. 678 /therm.
Staff Exhibi t No. 147 shows the existing and
proposed rates along wi th the resul ting revenue for
Residential Schedule 101.
The Company has proposed an increase in the
residential basic charge and the minimum charge from $3.
to $5.00.Why are you proposing no increase in these
charges?
The Company Exhibi t No.2 3, page 4 , shows
that the cost of meter reading and billing for Schedule
101 is $2.46.These are the costs that I believe are
appropriately recovered in the basic charge.This is
consistent with the recent Commission order in an Idaho
Power rate case (Order No. 29505, page 53) "The Corrnnission
finds that a monthly service charge should recover costs
that are directly attributed to the customer paying the
charge.Typically, those charges are related to meter
reading and customer billing.
LARGE GENERAL SERVICE SCHEDULE 111
What change in revenue requirement is Staff
CASE NOS. AVU-04-1/AVU-04-06/21/04
(Di)S CHUNKE , Staff
1334
recommending for Large General Service Schedule Ill?
Staff recommends an average overall increase
In revenue of 2.78% to Schedule 111.
What is your recommendation for the Schedule
111 rate design?
I am recommending that the energy rate be
increased to 78 .190 ~/therm in the first block , 76.379
/therm in the second block and 66. 182 /therm in the
third block.
LARGE GENERAL SERVICE-HIGH LOAD FACTOR SCHEDULE 121
What change in revenue requirement is Staff
recommending for Large General Service-High Load Factor
Schedule 121?
Staff recommends an average overall lncrease
In revenue of 1.86% to Schedule 121.
What is your recommendation for the Large
General Service-High Load Factor Schedule 121 rate design?
I .am recommending that the energy rate be
increased to 77. 103 /therm in the first block, 76.379
/therm in the second block and 66. 182 /therm in the
thi rd block and 64. 313
~ /
therm in the fourth and final
block.
INTERRUPTIBLE SERVICE SCHEDULE 131
What change in revenue requirement is Staff
recommending for Interruptible Service Schedule 131?
CASE NOS. AVU-04-1/AVU-04-06/21/04
(Di)SCHUNKE , D.Staff1335
Staff recommends an average overall increase
in revenue of 1.45% to Interruptible Service Schedule 131.
What is your recommendation for the
Interruptible Service Schedule 131 rate design?
I am recommending that the energy rate be
increased to 56.531 ~/therm.
TRANSPORTATION SERVICE SCHEDULE 146
What change in revenue requirement is Staff
recommending for Transportation Service Schedule 146?
Staff recommends an average overall increase
in revenue of 6.94% to Transportation Service Schedule
146.
What is your recommendation for the
Transportation Service Schedule 146 rate design?
I am recommending that the Company-proposed
basic charge of $200/month be approved and the energy rate
be increased to 10. 908
~ /
therm.
Does this conclude your direct testimony in
this proceeding?
Yes, it does.
CASE NOS. AVU-04-1/AVU-04-06/21/04 (Di)SCHUNKE, D.Staff
1336
(The following proceedings were had
open hearing.
(Staff Exhibit Nos. 143 through 148,
having been premarked for identification, were admitted into
evidence.
MR. WOODBURY:And Staff at this time would
present Mr. Schunke for cross-examination.
COMMISSIONER KJELLANDER:Let's begin wi
Mr. Purdy.
MR . PURDY:None, thank you.
COMMISSIONER KJELLANDER:Mr. Cox.
MR . COX:None, thank you.
COMMISSIONER KJELLANDER:Mr. Ward.
CROSS - EXAMINATION
BY MR. WARD:
Just quickly, Mr. Schunke.In the last
general - - last Avista general rate case, the Commission
ordered a 20 percent move to cost of service uni ty, did
not?
Yes, it did.
And did that, in fact , produce any progress, any
real progress toward cost of service, an even-handed cost of
service application?
1337
HEDRI CK COURT REPORTINGP. O. BOX 578, BOISE, ID 83701
S CHUNKE ( X )Staff
Well, the same customer classes that were out of
line in that case are still out of line.I didn't analyze
specifically to see if there was
- -
how much progress was made.
I can't answer that, but --
Let me see, since people are get ting hungry, let
me see if I can take a little shortcut by taking a small
liberty.I went back and looked at the last cost of service
analysis in the last case , and the relationship of the
residential class to uni ty was, I believe, exactly the same as
it is in this case,59.Would you
- -
do you have any reason
to believe that wouldn't be true?
I would accept that.
Now - - I lost my place here while we did the
correct ions.I f you go to page 7 of your test imony .
Yes.
In the answer that begins on line 14, you note
first that:One of my obj ecti ves is to move more closely to
cost of service.
But then what follows is this:However, it
also an obj ecti ve to keep rates reasonable by balancing the
cost of service goals with the goals for simplicity, for
minimizing rate shock , and for promoting conservation.
believe that a 20 percent move to cost of service balances
these obj ecti ves to achieve reasonable rates for all customer
classes.
1338
HEDRICK COURT REPORTING
O. BOX 578, BOI SE , ID 83701
S CHUNKE ( X )
Staf f
There I S another way we could achieve those
obj ecti ves, is there not?That is, we could simply move only
20 percent of the rate to full revenue requirement recovery for
the Company?
Well , obviously, my list is incomplete.This is
a list for rate design obj ecti ves.Outside of this list would
be objectives for, you know , setting the overall revenue
requirement, which would include keeping the Company whole.
But if that was not an obj ecti ve, you could - - you're right.
Well , again
--
let me mentally edit out a few
questions here
--
the objective you just referred to of keeping
the Company whole is mandated by Statute, is it not that is,
the Company is entitled to a just and reasonable return on its
investment?
Yes.
But isn't there also a Statute that says that
ratepayers are entitled to just and reasonable rates?
Yes.
So isn't it rather difficult to cite these
factors - - that is, the concerns of one or more ratepayer
classes who are underpaying
- -
as reason for imposing, at least
on cost of service basis, unj ust and unreasonable rates on
other customer classes over any long period of time?
Your question is that you're posing that it'
unreasonable to move to a cost of service or to be concerned
1339
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
S CHUNKE ( X )Staff
about rate shock for one class and hold another class above
cost of service.Is that the heart of your question?
Well , no.I asked theLet me put it this way.
question badly, I will concede.
If rate stability and minimizing rate shock
cause for denying the customers who are now overpaying redress,
wouldn't it equally be cause for denying the Company recovery
of its revenue requirement?How can you distinguish between
those two?Both parties are entitled to just and reasonable
resul ts.
Well , I suppose that one could make an argument
to that end.That's not my position , but
Okay.And have you been in the hearing room
through most of the test imony?
ve been listening to most of the testimony.
Okay.ve forgot ten which wi tness recounted the
fact that the Company has had -- that this would make its
second rate case in roughly 15 years.Do you agree wi th
that?
Yes.
Now, if we were to proceed 20 percent of the way
to cost of service uni ty in the future and the Company averages
a rate case every seven and a half years, we're nearly 40 years
before we get there, aren't we, if we follow that pattern in
the future?
1340
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
S CHUNKE ( X )Staff83701
That's a possible scenarlO, yes.
Last item:Did you - - did you hear
Mr. Hirschkorn' s testimony about the difficulty of trying to
implement variations in revenue requirement for Schedule
when Potlatch is included on that schedule?
Yes.
And, in fact, on that schedule, Potlatch looks
like an elephant next to rodents, does it not?
Yes, it's very large in that schedule.
Okay.Is there any reason why Potlatch should
not be treated as all other special contract customers are and
assigned a separate schedule?
I think that's a reasonable solution.
Okay.
MR. WARD:That's all I have.
COMM IS S lONER KJELLANDER:Thank you, Mr. Ward.
Mr. Meyer.
No questions.Thank you.MR . MEYER:
COMMISSIONER KJELLANDER:Are there questions
from the Commission?Commissioner Smi th.
EXAMINATION
BY COMMISSIONER SMITH:
Well, Mr. Schunke, Mr. Ward kind of came on to my
1341
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID
SCHUNKE (Com)Staff83701
question.
So if you take Potlatch off of 25, what about the
diversity that still remains on that schedule from under nine
million kilowatt hours up to over 46, and from the load factor
of 71 down to 33?Is that an acceptable range of diversity
among customers who should be in the same schedule and treated
the same?
Commissioner , it I S my recommendation that we
revisi t the division wi thin those Schedules 25, 21, and 11, and
look at how we re splitting up those schedules.It may be
reasonable to have that di versi ty if we I re able to define the
billing determinants in a way that properly tracks the costs of
the individual customers.
And what would be the time frame for this
revisi ting?
Well , I I m suggesting that as a minimum , at the
next rate filing, that we would
- -
we would see a thorough
review of that, but --
And if that doesn t happen for seven and a half
years, is that timely enough?
It may not be.
So should we say if they haven t filed within two
years we need to start a case looking at it, or should we just
start a case now?
Well , I think either of those would be reasonable
1342
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
SCHUNKE (Com)Staff
approaches.
I guess Commissioner
- -
or, Mr. Ward asked some
questions.I was looking at your Exhibit No. 143, which I
think caused me to have the same concerns he was raising.And
I was looking at your Columns 11 and 12 and wondering is
more important to have consistency in Column 12 than in
Column II?
No, I don't believe it is necessarily more
important to
- -
I think, ideally, I'd like to see the cost of
service index at 100 percent , or unity, for all the classes,
but that the difficulty I had was balancing a move to cost of
service and keeping the overall increase to the customer
classes - - in particular , 25 and the residential schedule
one - - to a manageable amount.
Well , I think 100 percent probably is an
admirable goal , but I guess one of my thoughts was recognizing
the uncertainty in all cost of service studies and that they'
not really science, that there may be some range that may be
acceptable.I don't know , pick some numbers, like from 90 to
100 is wi thin the range, or 95 to 105, or whatever you thought
was reasonable.What's your reaction to something like that?
Well , I think that makes sense.In fact, I
believe Mr. Hessing alluded to the uncertainty of cost of
service studies, and I certainly agree that there's uncertainty
and sometimes small changes in the cost of service study can
1343
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
SCHUNKE (Com)Staff
make material differences in the classes.So I think to try to
be too precise on arriving at 100 percent index is a bit of
a -- well , it's not a -- it's not an essential goal.
Finally, looking at page 12 of your testimony, at
line 18 --
Yes.
- -
where you're opposing the Company's proposal
for a declining block for Schedule 11 but you're recommending
that it be accepted, that's a little cognitive dissidence for
me, and I guess that's because you say:Prior to the next
general rate case we're supposed to get sufficient data to
eliminate a divide.
Is this the same issue we were discussing earlier
about real igning these schedules?
We II , ye s , it is.Eleven has a unique problem
in my opinion.Schedule 11 actually has customers that have
demand metering capability and customers that don't have demand
metering capability, and yet Schedule 11 lS a demand metered
schedule.And so I think that I s really at the heart of the
problem of Schedule 11.I think we need to move those
customers that are not demand metered onto a nondemand metered
schedule.
And how long is it reasonable to wait to do
that?
Well , I think that could be done after the
1344
HEDRI CK COURT REPORTING
O. BOX 5 7 8 , BO I S E , I D 83701
SCHUNKE (Com)Staff
Company is
- -
the Company was concerned about making the move
without knowing how it was going to impact the customers.I --
I believe that that should be able to be accomplished in a
fairly short time period.
Is that similar to what we did with Idaho Power
when they wanted to go to , what was it, and we gave them six
months and dual bills and so customers could see what I s going
to happen to them and make changes before it actually happened
to them?Is there any similarity there?
Well, I think there I s some similarities.
fact, I think the time of use metering
Right.
- -
was a very significant change for the
industrial customers, so, yes, I think
Is this as significant?Would you require
something like that?
I think that kind of a schedule would be
reasonable.I don t think this is as big of a change as the
time of use change.
Finally, we ve identified, I guess, a couple of
issues that need further attention.Are there any that we
haven t mentioned?It seemed like from the Idaho Power case we
ended up with this whole long list of things, cases to open
issues to address, that were issues that came up as a result of
doing the rate case but weren I t actually resolved.I s there
1345
HEDRI CK COURT REPORTING
O. BOX 578, BOISE, ID 83701
SCHUNKE (Com)
Staff
anything that we need to add to that list?
, I haven't identified anything else.
COMMISSIONER SMITH:Thank you.
COMMISSIONER KJELLANDER:Thank you.We're ready
now for redirect.
MR . WOODBURY:Staff has no redirect.
HEARING OFFICER:Okay.Thank you very much,
Mr. Schunke.Appreciate your presence and your testimony.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:I believe that is the
end of the list with the exception of
MR. WOODBURY:Terri Carlock.
COMMISSIONER KJELLANDER:- - Terri , and I was
wondering if we could perhaps get a status update on that.
MR. WOODBURY:I haven't personally talked to
Terri.I did get the status report from her as a result of her
meeting wi th the doctor last Thursday, and the date that we
ini tially talked about at the beginning of this hearing,
August 16th, was what fell out of those comments and I know
nothing to the contrary.So if I get any addi t ional
information , I'll keep the Commission apprised and the parties,
but I would move that we set a time in
- -
on August 16th for
Ms. Carlock's cross-examination and spreading of testimony and
exhibi ts.
COMMISSIONER KJELLANDER:Okay.So is there any
1346
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID
COLLOQUY
83701
obj ection to that Motion?
MR. MEYER:No.
MR . WARD:And, Mr. Chairman, I may be the only
one who's holding out here for at least the opportunity to
cross Ms. Carlock , but if there should be some problem with
that date , I certainly don't have any problem doing it wi
just a court reporter and submitting the written record to the
Commission if the Commissioners can't be in attendance.
COMM IS S lONER KJELLANDER:All right.Well
certainly we appreciate that flexibility, and we will cross
that as we get closer.
Are there any other matters that need to come
before the Commission at this point?Mr. Purdy.
MR . PURDY:Mr. Chair, I'm sorry, I don't recall
did the Commission set a deadline for Petitions for Intervenor
Funding?
COMMISSIONER KJELLANDER:We have not set a
deadline.Next week we have the public hearing portion of
this.And I guess this is as good a time as any to talk about
what that deadline would be, what's appropriate.
MR . PURDY:I would propose it be the last day
that the Commission receives public testimony.Is that --
COMMI S S lONER KJELLANDER:It wasn't your intent
to do any cross of Terri , was it?
MR . PURDY:No.
1347
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID
COLLOQUY
83701
COMMISSIONER KJELLANDER:So it shouldn't affect
your lssue with respect to intervening?
MR . PURDY:No.
COMMISSIONER KJELLANDER:That seems appropriate.
Any other matters that need to come before the
Commission?
If not, if not then , we're to the point where we
will close this portion of the technical hearing, wi th a
reminder that next week the Commission will be headed up to
Avista service territory to conduct the public hearing portion
of this specific case.And we thank everybody for your
willingness to assist us in getting everything into the record
and moving forward, and also for relentless ability that
everyone showed and the ability to move through the case as
rapidly as we have.So, thank you, and we'll see many of you
in North Idaho next week.
(Potlatch Exhibit Nos. 214 through 219
were admi t ted into evidence.
(The hearing adj ourned at 12: 08 p. m. )
1348
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID
COLLOQUY
83701
AUTHENTICATION
This is to certify that the foregoing is a
true and correct transcript to the best of my ability of the
proceedings held in the matter of the Application of Avista
Corporation for authority to increase its rates and charges for
electric and natural gas service to electric and natural gas
customers in the state of Idaho, Case Nos. AVU-04-1 and
AVU-04-1, commencing on Monday through Wednesday, July
through 21 , 2004 , at the Commission Hearing Room, 472 West
Washington , Boise , Idaho, and the original thereof for the file
of the Commission.
Accuracy of all prefiled testimony as
originally submitted to this Reporter and incorporated herein
at the direction of the Commission is the sole responsibility
of the submitting parties.
,tI"""""""
." tAU-
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.s.
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~7' Ii rEo 0 ~')10~I!."~~;;/J"'
WENDY J. MUR ota Publicin and for t State of Idaho,
residing at Meridian , Idaho.
My Commission expires 2-2008.
Idaho CSR No. 475
1349
HEDRI CK COURT REPORTING
O. BOX 578 , BOISE , ID
AUTHENTICATION
83701