20040803Vol IV.pdf

ORIG
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF)
AVISTA CORPORATION FOR AUTHORITY
TO INCREASE ITS RATES AND CHARGES
FOR ELECTRIC AND NATURAL GAS
SERVI CE TO ELECTRI C AND NATURAL GAS)
CUSTOMERS IN THE STATE OF IDAHO.
CASE NOS.
AVU-E- 04-
AVU-04-
Idaho PublIc Utllttles Co mission
OffiCe of the SecretaRECEIVED
AUG - 1 2004
Boise. Idaho
HEARING BEFORE
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISSIONER MARSHA H. SMITH
COMMISSIONER DENNIS S. HANSEN
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:July 20, 2004
VOLUME IV - Pages 700 - 890
POST OFFICE BOX 578
BpISE, IDAHO 83701
208-336-9208
COURT REPORTING
cftl'Vi.v tk ~I' etJff(/I((Q(Io/! cSr,;.ce 1978
WITNESS EXAMINATION BY PAGE
HEDRICK COURT REPORTING
O. BOX 578, BOISE, ID
Mr. Ward (Cross)
Commissioner Smith
Mr. Meyer (Redirect)
700
725
727
Robert J. Lafferty
(Avista)
Mr. Meyer (Direct)
Prefiled Direct
Commissioner Smith
Commissioner Kj ellander
731
733
740
741
David D. Holmes
(Avista)
Mr. Meyer (Direct)
Prefiled Rebuttal
Mr. Ward (Cross)Mr. Purdy (Cross)
Ms. Nordstrom (Cross)
Commissioner Hansen
742
744
750
752
758
759
Jon Powell
(Avista)
Sworn
Mr. Meyer (Direct)
Prefiled Direct
Prefiled Rebuttal
Mr. Woodbury (Cross)Mr. Cox (Cross)Mr. Ward (Cross)
Commissioner Smith
761
762
765
812
827
831
835
838
Brian J. Hirschkorn
(Avista)
Ms. Nordstrom (Direct)
Prefiled Direct
Mr. Meyer (Cross)Mr. Purdy (Cross)
Commissioner Hansen
840
842
855
856
860
Lynn Anderson
(Staff)
Ms. Nordstrom (Direct)
Prefiled Direct
Ms. Nordstrom (Direct)
861
863
886
Marilyn Parker
(Staff)
INDEX
83701
NUMBER
For Avista:
PAGE
PremarkedAdmitted 740
PremarkedAdmitted 827
PremarkedAdmitted 827
PremarkedAdmitted 827
PremarkedAdmitted 827
Premar kedAdmitted 827
PremarkedAdmitted 827
Premar kedAdmitted 827
PremarkedAdmitted 855
Premar kedAdmitted 855
Premar kedAdmitted 855
PremarkedAdmitted 886
PremarkedAdmitted 886
13 .Historical Meter Reading Costs
18.Proposed Changes to Electric SerVlce
chedul e
19.Proposed Electric Service Rates
20.Electric Supplemental Information
21.Proposed Changes to Natural Gas
Service Schedules
22 .Proposed Natural Gas Service Rates
23 .Natural Gas Supplemental Information
30.Relative Rates of Return by Rate
Schedule
For the Staff:
132 .Avista DSM Program Review 5/19/04
133 .Avista's Electrici ty DSM Revenues,
Expenses and End-of - Year Balances
134.Avista's Current and Proposed DSM
Surcharges
149.Economic Indicators
150.Comparison of Energy Utilities
HEDRI CK COURT REPORTING
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EXHIBITS
Avista Complaints and Inquiries
152 .Complaint and Inquiry Comparison byUtility
PremarkedAdmitted 886
Premar kedAdmitted 886
151.
HEDRICK COURT REPORTING
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EXHIBITS
BOISE , IDAHO, TUESDAY , JULY 20, 2004 , 1: 15 P.
ROBERT J. LAFFERTY
produced as a witness at the instance of Avista, having been
previously duly sworn, resumed the stand and was further
examined and testified as follows:
COMM IS S lONER KJELLANDER:We'll go back on the
record.
MR . WARD:Thank you.
COMMI S S lONER KJELLANDER:And I believe you were
in the midst of cross.
MR . WARD:Yes.
CROSS - EXAMINATION
BY MR. WARD:
Mr. Lafferty, let's start at page 11 of your
rebuttal.Now, do you have that risk policy with you at the
stand?
I do.
You do?
I do.
Okay.Again , we're deal ing wi th another
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confidential document, so I'm going to ask for
- -
about a quote
that precedes the quote at the bot tom of page 11.
COMMISSIONER SMITH:m sorry, Mr. Ward, I don't
know where we are.What document are you looking at?
MR. WARD:m looking at his testimony on
page II, but he's got a quote from his risk policy.
testimony.
COMMISSIONER SMITH:Okay, got you.
MR . WARD:Oh, I'm sorry, it's rebuttal
MR . MEYER:And I think you were referring to a
page out of that risk policy.What was that?
MR . WARD:Yes.m going to ask him to read
some language that immediately precedes this quote on the
bot tom of page 11.
have there,
that quote?
MR.MEYER:Bottom of page II?Okay.Got you.
MR.WARD:that ka y?
MR.MEYER:That'fine.
BY MR.WARD:Now referring the quote you
would you please read the sentence that precedes
Okay.The beginning of the paragraph , the third
paragraph under Subsection B, begins:Open positions are
measured starting with the physical imbalances between loads
and resources.
And then it goes on from there to the rest.
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LAFFERTY (X)Avista
Okay.Now, when you put on Deal A and B
hedges - - well, first of all, let's get the time frame cleared
You made the original physical gas purchases in March up.
Is that correct?2001.
Tha t is correct.
And you put on the hedges in April and May of
2001 ?
Tha t is al so correct.
Okay.Now , when you
- -
once you have the
physical purchases made, did you any longer have a physical
imbalance between loads and resources?
Physical gas was present, but as stated in the
second sentence, that the resources and loads price based on
index values are considered to be an open position for the
purpose of measuring financial risk.
But that's for the purpose of measuringYes.
financial risk.Right?
Which is the focus of the risk policy.
Okay.And financial risk is a result of
financial instruments, is it not?
It's a funct ion of an exposure we have to market
conditions for open positions such as we had looking forward
and that we filled when we did the combination of a two-step
process, first of buying physical delivered gas as we discussed
earlier, and then taking that same gas and fixing the price
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it.And then we had a fixed-price physical delivered gas
product that we calculate a cost to generate and hedge a
portion of our portfolio, fill that need, close that position.
Now, let me refer you to the end of that
quotation.It says:
Generating plants may be included as resources to
cover open power posi tions
- -
et cetera
- -
if the plant
available for operation.
Was Coyote Springs available for operation at the
time?
It was planned for operation , and consistent with
the way we look at generating plants they may be off for
maintenance or other work and we planned to have them in
whenever they're scheduled to come in, so it's the best of
available information.
But the plant was not available for operation
when you made this decision , was it?
It was planned to be.
Pardon?
It was planned to be available for operation.
And the problem with planned plants lS sometimes
they don't make it on schedule, do they?
That's always a possibility.One of the features
of purchasing the natural gas that we did, we wanted to make
sure that that gas could also be delivered to other plants that
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we had connected to the PGT pipel ine
And , in fact, the two significant plants we have
In consideration in this rate case, nei ther one of them made
their
- -
began commercial operation on schedule, isn't that
Boulder Park and Coyote Springs?true?
That is true.
All right.And , consequently, that availability
couldn't cure your open position at the time the decision was
made, nor did it, in fact, cure it later when the plants were
scheduled to be on-line but, in fact, were not?
At any point in time as we're making decisions
around our resource portfolio, we're going to look at whatever
best available information we have at that and the schedule
for plants that are ei ther off on maintenance or for other
reasons, we make those adj ustments when they're scheduled to
come back , we plan for that.
Now , when you purchase a financial instrument or
when you are contemplating the purchase of a financial
instrument such as these hedges, isn't it normal Utility
practice to undertake a number of studies to determine what the
nature of the risk you're undertaking is?
Again, as I explained earlier , that the
combination of the index-based purchase wi th the fixed for
flowing swap gave us a fixed price for natural gas that we used
to calculate cost to generate and provide the forward benefit
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that we could see available at the time looking at the forward
prices as illustrated on the graph.And, of course, what we
were trying to do there is lock in a component of our portfolio
at a very reasonable price, 38 to $48 per megawatt hour
compared to a market that was very higher.Of course, thi s was
the market at the time.We had just in the past winter seen
prices much higher than this on a daily basis, two to $5,000
per megawatt hour on a forward basis, $800 a megawatt hour in
December looking ahead to January.The prices we're seeing
here are less than that, but they could have easily been higher
than that.
Well, and they could have easily been lower too,
and that's the way they ended up, isn't it?
They did, in fact, decline after Federal price
caps were insti tuted.
Mr. Lafferty, none of that analysis goes to the
reasonableness of the hedges.You would have to determine
those hedges were reasonable, determine whether - - run the
ordinary stress tests and other tests on the financial risk
you were undertaking.Isn't that true?
What we would do when we compare a cost to
generate to market is similar to the analysis that you see in
front of you on the left, and it's also included in the
rebuttal testimony where we're comparing a fixed price of
natural gas, which is an end resul t of the two transactions
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through a cost to generate, and compare that to the market.
But, Mr. Lafferty, let's suppose that yourYes.
analysis had showed an even greater gap than it did between
the - - I'll call it the spark spread , although that's not
exactly right.If it had shown an even greater gap still, why
wouldn't you want to run an analysis to determine whether the
prlce you were paying was reasonable in comparison to what you
could see in the future for gas prices?
What we could see in the future for gas prices
was the forward price for natural gas at the time, and that
information has been provided.The market information around
the natural gas conditions at that time were part of what
supplied in the exhibits.And the
- -
and so these products
that we purchased fixed the price of natural gas consistent
with the market conditions at that time.
Let me ask you thi s :If Avista Energy undertakes
a swap like this, do you think they do so without conducting
the sort of analysis I just referred to and asked about
earl ier?
I can't speak to Avista Energy.
And, in fact, of course as we know, Avista Energy
took the opposite side of one of these transactions?
As we did find, you know, active marketers as we
found, Avista Energy is one in our region.They will provide a
number of services in the market.
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If you refer to Exhibit 219, please?If you look
over to like the fifth page of that exhibit, following the code
of conduct , here you have an agency agreement between Avista
Corporation and Avista Energy.Do you recogni ze that
document?
I see it.
And wi thout going through the particulars,
doesn't that document make Avista Energy Avista Corporation'
agent for the purchase of natural gas?
For the local distribution company, the natural
gas local distribution company.
But it also acts as your purchasing agent for
electric purchases as well , doesn't it?
I don't follow.Could you direct me to that,
where you see that?
Does it , in fact, act as your agent?
For electric purchase?
Yes.
It does not, to my knowledge.
For electric fuel supply purchases?
To my knowledge, it does not.
Who does your electric fuel supply purchasing?
We purchase our electric fuel supply.
Meaning the
The power supply department makes acquisitions of
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fuel supply, but you mean natural gas or do you mean electric
supplies?
Yes.
Fuel for natural gas for generation?We have
made those purchases.
Are you testifying that you don't use Avista
Energy s expertise in the purchase of natural gas for your
electric plants?
Our decisions are based on Utility needs, and we
make the decisions with the staff that we have at the Utility
in the power supply department.We use our gas supply guru as
part of that process.
m having much trouble hearing you,
Mr. Lafferty.
We use our gas supply guru in the Utility to give
us information on natural gas prices or that type of thing, if
that's what you re asking.
Okay.Would you agree with me nonetheless that
Avista Energy has the greater trade
- -
has greater trading
expertise than Avista Corporation?
They have a much larger presence in the market.
And more experience?
- -
I guess I don't know what to respond to
that.
Okay.Now, let me
- -
when you undertook these
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transactions, what was the Company, what was Avista
Corporation's, response when Avista Energy attempted to and
ul timately did take the opposi te side of the swap?
Well , we were in the market , trying to find
counterparties that would transact wi th us at the time that
would perform the hedge transactions we were seeking.Avista
Energy was just one of three parties we were able to set up a
transaction with at market conditions to provide those hedges,
those four hedges.
Didn't anybody at Avista Corporation say, Wait a
minute.Why does Avista Energy want the opposite side of this
bet?
To my knowledge , you know , we didn t have those
kind of questions because we knew that those types of entities
in the marketplace that provide this type of hedging service
so we were just trying to find a counterparty that would do
business with us in the situation that we were in with the
financial circumstances, credit circumstances, et cetera.
Nobody at Avista Corporation raised any questions
about the idea of Avista Energy taking the opposite side of
this deal?Is that what you're telling me?
At the time, I don't recall that.
When you undertook the deal , page
- -
lost my
place.
In your direct testimony, you state that,
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essentially, these deals were required in part because of the
need to obtain a gas supply for CS2 for financial advantages?
The first step, the indexed and purchase step.
Okay.Now , first of all, do we have any evidence
that any potential lender insisted on anything other than a
physical gas transaction?
No.
So the decision to hedge that transaction was
yours?
Right, consistent with a risk policy to close
that financial open position for -- that we needed to, I guess,
close in the future.
If you had plant, right, like we just
discussed?
Tha t 's correct.But, you know, to the extent
that one might not have had,you know,that plant,still did
have the Rathdrum plant that could use that gas as we 11.
Now,Deal A.First of all Coyote Springs at
that point was scheduled to come on-line in July of 2002.
Correct?
I believe that's correct.
Now , if'd you turn to Dr. Peseau s Exhibit 202
if you would?
m there.
Now , in fact , notwi thstanding the fact that
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Avista
Coyote Springs 2 wasn't scheduled to come on-line until July of
2002, Deal A and the underlying physical purchases began in
November of 2001 , did they not?
Tha t 's correct.This gas was planned for use at
other generating plants as explained in the testimony, as well
as Coyote Springs 2.I might also mention that Coyote
Springs 2 was expected to start testing in June.
Did you, in fact, use this gas at other plants?
I would have to check to see to what extent that
did occur.I don't have that information.
Can't you tell by this exhibit?
If I -- looking at Exhibit 202 , what I see listed
lS Malin prices, apparently after-the-fact prices at Malin, the
number of dekatherms per day, 20,000 for Deal A and 20 000 for
Deal B , the contract prices and the differential, and then
says monthly dekatherms which appears to be a calculation of
just the total amount of dekatherms.I can't tell if the plant
is operating or not from this.
Okay.
MR . WARD:May I approach the wi tness?
COMMISSIONER KJELLANDER:Yes.
BY MR. WARD:I want to return to your statement
that Avista Energy doesn't buy gas on your behalf.
Okay.
MR.And I don't have a copy because WARD:
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didn't anticipate that answer , so if I may, I'd like to stand
he re .If you'd like to look , Counsel?
That's fine.MR. MEYER:Go ahead.
BY MR. WARD:Do you recognize that?
Okay, this appears to be a front page from the
transaction record on 3/22/01 for the 20,000 dekatherms a day
which we purchased from Avista Energy at index , which represent
Deal
Who's listed as the broker there?
Well , it was purchased from Avista Energy.
That's who the transaction was with.
What Mr. Ward is referring to is there's a line
drawn through the word "broker" and "A vista Energy" is written
off to the right -hand side, but, in fact, the transaction
documents - - I'm not sure why the line is drawn there.The
transaction is with Avista Energy, between the Utility and
Avista Energy.
Okay.Now , of course, I lost my train of
thought.You probably have too.
You mentioned earlier in discussions with
Mr. Woodbury meetings and discussions to evaluate these deals.
And did you furnish in response to Discovery Requests any
minutes of any meetings, any memos that summarized meetings,
any documents such as that?
You know , we provided the information that we
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had.These wereI don't recall any minutes of meetings.
working meetings, and minutes or that type of thing, to my
knowledge , were not kept.
Now , again , in your rebuttal at page 11 - - you
probably don't even need to turn to it - - you're attempting to
rebut or you obj ect to Dr. Peseau' s statement that these deals
were of unprecedented length.Do you recall that?
Yes, I do, compared to other medium-term
transactions that the Utility might do on the electric side.
Did you - - do you have any evidence of any gas
transaction at the time with terms -- any gas transaction, any
hedged gas transaction , wi th terms in excess of a year?
I didn't do any research into those types of
transactions.What we looked at , again , was a medium-term
transaction for the Utility through the cost of generating,
which is not an unusual thing for an electric utility to do.
And Dr. Peseau also testified that he reviewed
some 37 000 contemporaneous gas transactions and found not one
deal for the length of Deal Do you have any evidence that
that's not true?
I did not review the database that Dr. Peseau
used.m not sure what it contains or what the cri teria that
was used in developing that database.I did not research that.
Again , what was important to us from the electric
utility side was the filling of an open position and then
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Avista
financially closing that with a hedge transaction.I t was
simply a matter of measuring up the physical gas that had
already been purchased and converting it to a fixed-price
physical gas, doing it in two steps rather than , say, one step.
Well , I realize that's your explanation
Mr. Lafferty, but here's what I don't get:I f you - - once you
enter into a hedge like this , you are undertaking financial
risk , are you not?
We would view that risk the same as if you bought
a physical priced natural gas quantity.
Okay.Okay.And here's my question:
Why did you buy the physical gas at index and one
month later decide you want to hedge?
It was always the intent to hedge the gas after
we had some discussions on how we wanted to approach it , and we
did that.And as you know, we did not hedge the full amount of
natural gas, as the chart shows.We hedged 40,000 out of
approximately 47 000.
I'll acknowledge that , but why not simply do a
fixed-price gas deal?
My understanding, it's fairly common practice in
the natural gas industry to do the underlying transaction at a
index and then later on separately hedge it or that
counterparty may find another party to hedge it for you.
Isn't there one important distinction between a
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fixed-price contract for the future and a hedge instrument such
as this, and that is this:Wi th the hedge, if you re out of
the - - out of the money, you have to immediately start paying
payments to the other party, do you not?
I can't speak to that payment cycle.
Well, Dr. Peseau testified that the way a hedge
is settled is that each month after you undertake the hedge,
one party or the other is either up or down , either in the
money or out of the money on the hedge, and that you must then
immediately make a settlement for the difference between the
hedged prlce and the actual?
For the month.
Do you have any reason to believe that's not
true?
For the month?m just asking a clarifying
question.
Yes.
So you re settling for that month, so as you
approach that month, you would have a settlement between the
difference between the price in the contract and whatever the
index was determined to be for that month , and then that would
be settled out for that month.
Now, when we look at Deal B
- -
and Deal A , for
that matter - - there's a big difference, is there not, between
a fixed price contract which you would start paying for in the
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future when you took gas
That's how it works, is it not?
Well,guess I' m not
- -
I' m not following your
suggestion here that
- -
you talk about "in the future,and
tha t 'why was clarifying.You know,this
understanding, subj ect to checking wi th
- -
but as I understood
it, the settlement would be done on a month-to-month basis as
you walk through time, as you knew the index quantity in a
differential.So it's not -- it's just that month.
If I misstated myself or misled you with the
question , I apologize.My question was with a fixed-price
contract, if you go to another party and enter into a deal for
gas starting in July of 2002
Okay, do you have that thought in mind?
Okay.Yes.
Two-year deal , let us say.
- -
you don t start paying on that deal until you
actually take the gas.I sn 't that correct?
That would be my expectation , yes.
But with a hedged instrument, you start paying
immediately, if you're out of the money?
You mean currently by several months or a year in
advance?
Yes.
I don't
- -
I don't know that's the case with
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this, wi th the contracts we have.
Well , Dr. Peseau said that's the case, and I
assume somebody at the Company was capable of rebutting him if
that's not true?
Or maybe possibly didn't understand what the
point was.
So the difference here was that, as opposed to
And were parties offering firm contracts at that
time?Were they available?
At the time of March?
Yes, or February?
In March , as we were looking for the delivery of
natural gas , I know the counterparty that we worked with to get
the Deal A gas , that they wanted index.That's what their
preference was.They had physical gas, it was delivered to
Mal in , and met our needs.
I understand.
And we knew we could hedge it later.It's not an
unusual structure for natural gas.
It's not an unusual structure to make a firm term
purchase ei ther , is it?
It could -- yes , it would be either way.
works the same and the result is the same and with fixed-price
delivered natural gas.
Well, let me submit to you , Mr. Lafferty, that
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the resul t is not the same, because when you elected to
undertake these hedge instruments, once you were out of the
money - - which you were from the very first day, practically --
you had to start wri ting checks to BP, to Mirant , and to Avista
Energy; and had you taken a firm contract for the times that
you wanted the gas, you would not have had to wri te those
checks.Is that true?
Now that I understand what your point is, I can't
say that I would agree with it because I would have to check
and see if that was the case.That's not my understanding,
that these are settled on a month-to-month basis as the price
approaches, because you don't know what the index is until you
get there , so you don't know what the differential is until you
get there.
I understand.But the point is that if you
needed to fix the price for gas, if you decided you wanted to
do that , the big difference was if you made a fixed-price
contract deal , you would not have had to pay the hedge
settlements and you would have instead started paying when you
actually took delivery of the gas, presumably in November of
2001 and July of 2002.Isn't that true?
I can't agree with that because, again, that
contrary to my understanding of how these transactions were
settled.
Okay.I want to read to you
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Well, first of all , would you agree with me
that
- -
and wi th Dr. Peseau' s testimony - - that hedges such as
thi s , or more correct y, f inanc ial deal s such as thi s , can be
and often are undertaken by people who have no intent ion of
actually taking any physical gas?
Certainly counterparties do that.
And, in fact, in the natural gas market, deals
like this are the way you go long or short the market, aren'
they?
Well , the parties that are doing financial
hedging are hedging a number of different products or services
in different directions, if that I s your point.
I understand.But , obviously, if I believe that
natural gas rates are golng up in the future , I want to be on
the same side of this financial instrument that Avista
Corpora t ion was.Correct?
Again, our perspective is we're fixing a price of
electric resource need.
Does Avista Corporation understand that with
instruments such as this , there can be significant gains or
losses depending on which way the market goes?
Avista Corporation , if you re referring to the
Utility business
Yes.
- -
we understand that when we buy any product in
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O. BOX 578 , BOISE, ID 83701
LAFFERTY (X)
Avista
the marketplace, that after that point in time , the price is
likely to change either up or down , it rarely stays the same,
and we know that there's then a differential.And that I s why
we pointed out there's other medi um- term transact ions we have
done and some of those are substantial.We have, you know , a
couple hundred megawatts that we secured back in I think the
year 2000 that produced over a couple million dollars in
benefi t.I mean , not that that's the right way to look at
things in retrospect , but, you know , after the fact, that the
price does change.That's true of any fixed-price transaction.
Are instruments such as this traded by parties
who are clearly speculating on market direction?
All counterparties have their own business
strategy, and I can't speak to anybody' s particular strategy.
A lot of parties that do hedging, my understanding is they'
hedging the other side of things qui te quickly.That's the
nature of their business.But others may have different
strategies.
Let me read you a portion of the Commission'
Order, Order No. 28097 , and this is in the last Avista rate
case.And in that case , did you
- -
I forgot, did you
participate in that case, Mr. Lafferty?
You'd have to refresh my memory.I wasn't a
wi tness.
Okay.
720
HEDRI CK COURT REPORTINGP. O. BOX 578 , BOISE , ID 83701
LAFFERTY (X)
Avista
Is that what you're asking?
there was considerably - - there was considerable testimony
Yeah , that's what I was asking.
Okay.
Well , let me represent to you that in that case,
about the Company's short-term purchases in particular but
speculative transactions in general, and the question was
whether or not ratepayers, since this was done, in part, at the
Avista Corporation level, whether the ratepayers were entitled
to share in some of those profits.And the Commission'
ultimate Decision was it was not, the ratepayers were not.
Now , let me read you a section from the
Commission's Order here:
Avista, in this case , proposes that commercial
short-term purchases and sales one year or less be excluded
from the 1997 pro forma results because the majority of such
transactions were for speculative purposes and unrelated to
operation of the Company I s resources or serving retail load.
The contracts for the commercial transactions that occurred
during the 1997 test period have all terminated.
Speculative transactions include wholesale
purchases of power that are made exclusively for resale to
other wholesale parties.They also include wholesale sales of
power that are covered later wi th purchases, also known as
selling short.
721
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
LAFFERTY (X)
Avista
And I'll omit a sentence.
Because they are speculative in nature, Avista
maintains that the risks and benefits associated with these
transactions should reside wi th the shareholders and should be
excluded from the retail rate making process.
That's a position the Commission ultimately
agreed wi th
But those transactions didn't
- -
were not
contemporaneously labeled as speculative.The Commission only
looked at the nature of the transaction and said, okay, this is
a speculative transaction and it remains with the shareholders.
When we look at the financial instrument hedge,
and swap, we now -- and it doesn't matter what you label it at
the time - - under the rationale the Commission used and the
acceptance of Avista' s argument last time, that's a speculative
financial instrument and it ought to remain with the
shareholders.Why should that not be the case here?
Again , I'm referring to my testimony:Avista'
purpose here was to secure or fix the f inanc ial open pos it ion
it had looking forward , to get a reasonable price of 38 to $48
per megawatt hour.
And that was our purpose here.It was not
speculati ve.
But, again, we don't have any documentation,
contemporary documentation , recording that.We have now the
722
HEDRI CK COURT REPORTING
P. O. BOX 578 , BOISE, ID 83701
LAFFERTY (X)
Avista
Company's after-the-fact testimony and that's all we have.
Isn't that true?
I don't agree.I think we provided support ing
testimony that was reflective of the analysis that the Company
had done first in respect to its open long-term position in
considering making these decisions.
We don't have any documents from the time that
that decision was made reflecting this supposed analysis at the
time, do we?Can you point me to any that were furnished in
Discovery?
In our own exhibits here, we produced, you know
information as to, you know , the nature of the transaction, you
know , the need for resources it provided in test imony .
looked at both
- -
showed you a cri tical water analysis, we
showed you the confidence interval analysis, we provided the
exhibi ts that were all from the data we had available at the
time that we looked at.We looked at that data and considered
and weighed these decisions.
And that's in addition , I should mention, of
course, to the shorter- term view which was the posi tion
reports.We looked at both long term and the short term viewed
together.
Let me ask you on one final subj ect ,
Mr. Lafferty:
If the Commission were to approve and accept for
723
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
LAFFERTY (X)
Avista
rate making purposes the expenses associated with Deal B , which
was the deal where Avista Energy was your counterparty, if the
Commission were to approve that , don't you think we would have
an open invitation to any utility that engages in energy
trading or has an affiliate that engages in energy trading to
simply siphon off revenues from the Utility anytime they
please?
No.
If I can do a financial transaction that
believe is golng to be in the money for me, as an affiliate,
with a utility, what is to stop the two from colluding to
produce an instrument that is certain to pay the affiliate
beginning day one - - or, day one of the first month after that
instrument is signed?
Again , our decisions are separate.We operate
our businesses separately, as I explained.And so I
- -
I don'
agree with your characterization.
I might mention that we have agreed in the State
of Washington , because of certain complexities of dealing with
our affiliate Avista Energy, that we've stipulated that we will
no longer do that for natural gas purchases for generation as
we have done here, just to avoid any concerns, but I don'
agree wi th your characterization.
m not necessarily talking about Avista now , but
if the Commission were to approve Deal B , isn't it an open?
724
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
LAFFERTY (X)
Avista
invitation to every utility under its jurisdiction to look to
the attractive features of cutting deals like this with the
utility?
Again , the transaction was at market, as we
provided in our evidence, testimony, and exhibi ts.Whether
it I S an affiliate or another counterparty, they re providing
the same benefit to the Utility.We're getting a fixed-price,
physical , delivered natural gas product in the end.
MR . WARD:That's all I have.
COMMISSIONER KJELLANDER:Thank you, Mr. Ward.
m not certain if we went to Mr. Cox and
Mr. Purdy.Am I correct?I believe we did at one point.
MR . COX:I believe you did.
MR . PURDY:Yes.
COMMI S S IONER KJELLANDER:Thank you.I didn'
want to bypass you.
I believe we're ready now for questions from the
Commission.Commissioner Smith.
EXAMINATION
BY COMMISSIONER SMITH:
Mr. Lafferty, you and Mr. Ward spent a great deal
of time talking about the Avista purchase of a turbine from
Enron for the 59.5 million?
725
HEDRICK COURT REPORTING
O. BOX 578, BOISE, ID 83701
LAFFERTY (Com)
Avista
Yes.
Were you a party to those negotiations or that
deal between Avista and Enron?
I was not.
Who was, on the Avista side?
Lloyd Myers.
Just one person?
And Alan Meyers.
Are those people still with the Company?
They are not.Lloyd is retired, and Alan left
the Company when we closed down the Avista Power operation.
So they were on the Avista Power side?
That's correct.
So who did the deal for the Avista Corp. when
they got it from the power side?
I was in charge in the RFP process where we
evaluated all the different 32 proposals, and particularly
was focused on the supply side proposals, and also where we
considered the Company build proj ect with Coyote Springs
Thank you.COMMISSIONER SMITH:
Any further quest ionsCOMMI S S IONER KJELLANDER:
from members of the Commission?
I f not, I bel ieve we're ready for redirect.
I just have just a few follow-up.MR. MEYER:
I 'll try to be brief.
726
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID
LAFFERTY (Com)
Avista83701
REDIRECT EXAMINATION
BY MR. MEYER:
I believe you were asked some questions about the
transformer which is currently being repaired, questions put to
you by Staff Counsel.Do you recall that?
Yes, I do.
Is this transformer currently being repaired
still under warranty?
It's my understanding it's still under warranty.
So presumably any costs of repair would be the
responsibility of the manufacturer?
That would be my expectation.
You were asked about whether there was any
supporting analysis at the time the Company entered into
Deals A and B, and that exchange went on for a while between
you and Mr. Ward.Correct?
Now , just recap briefly the sort of documentation
that you have provided here that goes to that very analysis.
Well, what I was going to look for , I was going
to look for the pages that Mr. Woodbury and I were talking
about where it lists
May I direct your attention to page 55 of your
direct testimony?
, t hank you.Yeah , 54 and 55, and then
727
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID
LAFFERTY (Di)
Avista83701
specifically, 55 and 56 as to documents that related to these
transactions.
And what sort of things did you look at as part
of this documented analysis?
We looked at the market conditions at the time,
both the price for natural gas, the price for electric, the
cost to generate, you know , the different plants that we had
available to utilize the natural gas, as we've discussed.
We considered, of course any transmission issues
that we would need to in that process and the overall
comparative economics between al ternati ves
You were also asked why, if this Commission were
to approve Deal B , that this wouldn't be essentially an open
invitation to hedge with affiliates.Do you recall that?
I do.
Now , isn't it true that this Commission , under
it's typical prudency analysis, looks to the available
information at the time of the transaction to determine whether
it was a prudent course?
That's my understanding.
And wouldn't that be true whether that
transaction was entered into with affiliates or with a third
party?
That would be my expectation as well.
So, essentially, the deal still needs to pass
728
HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
LAFFERTY (Di)
Avista
muster glven all the information available at the time of the
transaction and irrespective of whether it's with an affiliate
or third party.Correct?
Yes.
At the time that Avista entered into the hedged
deal , Deals A and Deal B, and given the information that it had
at that time , were those attractive to the Company?
Yes.They were at market and they provided a
cost to generate that was substantially better than the
al ternati ves that we had.
Well fact,
translate ultimately into an
$48 a megawatt hour?
electric price in the range of
didn't those Deal s A and B
That is correct.
And so when you factor in the impact of Deals A
and B, that's what you get?
That's correct, a combination.
How did those prices at the time the deals were
entered into compare wi th forward market prices?
As illustrated by our graph here , they compared
very favorably against the forward market prices at that time.
And, in fact , if the Company had not hedged
through Deals A and B, would the Company have been exposed to
price volatility?
It would.
729
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
LAFFERTY (Di)Avista
And could that prlce volatility, given recent
history just prior to Deals A and B , have resulted in prices
well excess,maybe double or triple,and $48?
could have.Certainly natural gas prlces
particular back in the winter were above $10 for several
months.The forward prices were also in excess of that.
saw some daily prices that were up in the $40 range.
And, lastly, why wasn't Avista , quote/unquote,
speculating in the market when it chose to enter into Deals A
and B?
Again , because we had a resource need.We were
looking to close that need with both physical and financially
consistent with the risk policy.
MR . MEYER:Thank you.That's all I have.
COMM IS S IONER KJELLANDER:Thank you.
And I believe we are finished then with this
wi tness and we appreciate your testimony, and we're ready for
your next witness.
(The wi tness left the stand.
MR. MEYER:Next wi tness would be - - let's do a
couple of short ones
- -
Mr. Holmes, please.
730
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
LAFFERTY (Di)
Avista
DAVID D. HOLMES,
produced as a witness at the instance of Avista, being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MR.MEYER:
Are you ready?
Yes.
Mr.Holmes,for the record, please state your
name and your employer.
My name is David D. Holmes.m employed by
Avista Corporation.
And have you presented direct testimony in this
case?
I have.
Any changes to make to that direct testimony?
No.
And if I were to ask you the questions that
appear In that prefiled direct, would your answers be the
same?
Yes.
Are you also sponsoring what has been marked for
identification as Exhibit 13?
Yes.
731
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
HOLMES (Di)
Avista
Was that prepared by you or under your direction
and supervision?
Yes.
With that, I ask that his testimonyMR . MEYER:
be spread as if read, and move the admission of Exhibit 13.
COMMISSIONER KJELLANDER:Without obj ection
spread the testimony as if read, and I guess we'll admit the
exhibi t
MR . MEYER:Thank you.
(The following prefiled direct testimony
of Mr. Holmes is spread upon the record.
732
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HOLMES (Di)
Avista
Please state your name, employer and business address.
My name is David D. Holmes and I am employed as the Manager of
Distribution Engineering for A vista Utilities, at 1411 East Mission Avenue, Spokane,
Washington.
experience?
Would you describe your educational background and professional
I am a 1977 graduate of Montana State University with a degree in Electrical
Engineering. I originally joined the Company in 1977 and spent eighteen years in various
engineering and management positions including five years managing the Company s electric
and natural gas metering departments. In 1995 , I left the utility to develop advanced metering
systems for A vista Advantage and then joined A vista Labs to direct their Application
Engineering staff. In early 2003, I rejoined Avista Utilities to supervise the Distribution
Engineering staff.
Washington.
am a Professional Electrical Engineer in the States of Idaho and
What is the scope of your testimony in this proceeding?
My testimony will describe Avista s proposal for implementation of Advanced
Meter Reading (AMR) for A vista s customers in the State of Idaho.
Please summarize the Company request in this case regarding
Advanced Meter Reading, or AMR.
The Company proposes to install AMR devices on all Idaho electric and
natural gas meters over a four-year period commencing January 2005. The Company is not
proposing a change in rates in this filing related to the implementation of AMR. Mr. Falkner
Holmes, Di
A vista Corporation
733
explains the Company s proposal for the future ratemaking treatment of the costs associated
with this program.
Has A vista been following the Commission s recent examination of
AMR?
Yes. The Company has been actively monitoring Case No. IPC-02-12.
While A vista has not submitted written comments in that proceeding, Company
representatives attended the Commission s June 5, 2003 technical workshop and participated
in the December 2, 2003 workshop via a conference bridge.
Please summarize the Company s perspective on AMR.
A vista has been following the development of AMR over the past decade, and
periodically assessing possible AMR implementation in areas where it is demonstrably cost-
effective. The Company has installed a small number of AMR devices on some meter
reading routes and customer locations that involve extensive driving, lack of access or have
represented a hazard for our personnel.
The Company has also monitored development of AMR technology with attention to
costs and with an eye to the future. Regarding costs, we have noted that AMR technology
has been improving and its costs are generally decreasing. Our plan is to select and install
systems that are compatible with existing systems, long-lived, and suitable for later
expansIon.
The cost of manual meter reading continues to increase. Meter reading expenses in
Idaho have increased an average of 4.8% per year since 1995, as shown in Exhibit No. 13.
Page 1 depicts historical meter reading expenses in Idaho, Washington and Oregon. We
Holmes, Di
A vista Corporation
734
believe that the expected continual increases in meter reading expenses and a decline in
equipment pricing indicate that now is the time to commit to a broader implementation of
AMR technology.
What technology, or type of AMR devices, is the Company proposing to
install?
The Company will utilize a combination of AMR technologies in its Idaho
service territory. We intend to install radio-based technology in areas with higher meter
densities, and a power line carrier (PLC) based technology in areas with lower densities.
will continue to use telephone-based technologies for selected industrial accounts. A number
of factors will determine where each technology is utilized including geography, distribution
configuration, installation costs and the presence of natural gas. All electric technologies will
have the capability to provide hourly or more frequent interval data. Meters utilizing a radio-
based technology will initially be read monthly through a mobile device. They will not
require modification when a fixed radio communication network is added to collect data in
the latter phases of the project.
Will the proposed AMR technology provide such functions as automated
meter reading, theft detection, accuracy improvement, improved outage monitoring,
flexible billing schedules, account aggregation, and improved customer service?
Yes. The equipment we propose to install will provide interval metering data,
as well as indications of tampering and information on outage conditions. Data collected
from this equipment will enable us to provide flexible billing schedules for our customers.
This equipment is not intended to provide aggregated demands for tariff calculations, but it
Holmes, Di
A vista Corporation
735
will enhance our ability to provide consolidated billing statements for customers with
multiple accounts.
This system will greatly reduce estimated reads, reduce the volume of phone calls
associated with estimated reads and the need for investigations related to such calls.
Customer billings will tend to be more accurate because estimates and misreads will be
reduced. The actual metering accuracy will not be affected by this automated system and will
continue to be monitored through our periodic sampling program.
Will this system provide the capability for future Time-of-Use or critical
peak pricing?
Yes. This technology will allow the remote capture of electric interval meter
readings in intervals of one hour or less. The significance of capturing interval readings is
that it provides the foundation for later adoption of retail energy pricing that may vary by
hour of the day or day of the week. This type of pricing can ultimately be used to provide
economic incentives to customers to curtail usage during critical energy periods.
Although this project does not include the necessary modifications to our billing
system to implement a time of use or critical peak rate structure, this equipment will provide
all the field data necessary to support this type of system in the future.
What other AMR systems did the Company review prior to selecting the
technology it did?
A vista has evaluated several advanced metering systems. A vista has installed
over 74,000 radio and 350 PLC based AMR devices throughout Washington, Oregon and
California including 1,700 within the State of Idaho. Our supplier for radio-based equipment
Holmes, Di
A vista Corporation
736
has been Itron, based in Spokane, Washington. We have utilized Hunt Technologies for PLC
based technology and are currently reviewing Distribution Control System s Incorporated
TW ACS PLC technologies. We will continue to review vendor technologies to ensure
program requirements are met and future technology migration and service is available.
How will you determine the AMR plan for roll out and the most cost-
effective area to begin implementation?
An efficient deployment of AMR systems is based on the specific attributes of
each geographic area. Our intent is to begin AMR installations in areas that will free up the
most labor, which in turn will be used to accelerate additional installations. These areas tend
to be more rural in nature, however, the same attributes that make these meters more costly to
read, reflect a generally higher AMR retrofit cost. Efficient utilization of PLC technology is
usually accomplished with the conversion of customers served by the same substation. The
efficient deployment of radio-based systems tend to be organized by the specific terrain and
geographic densities. Specific system design, vendor evaluation and selection will take place
in 2004.
What is the projected cost to install this system in Idaho?
We estimate the cost of installing this system in Idaho will be approximately
$16,300,000. We propose that this system be installed over a four year time period beginning
in 2005, with approximately equal expenditures in each year as shown in Exhibit 13. Page 2
is a summary of costs in 2003 dollars associated with the proposed AMR installation. It is
important to note that these are initial estimates. The selection of appropriate technologies
Holmes, Di
A vista Corporation
737
for each location, vendor, evaluation, and selection , as well as a refinement of cost estimates
will take place during 2004.
What are your anticipated hard dollar savings?
A vista believes that installing a fully networked AMR system on all of Idaho
meters will represent an annual operations savings of approximately $994,000. The majority
of these savings (92%) is achieved through a 91 % reduction in meter reading labor and
associated expenses.Other savings are represented by efficiencies in customer billing,
service, reduced energy diversion and reduced pteter maintenance, as shown in Exhibit 13.
Page 3 represents estimated savings associated with the installation on A vista s system.
Will the hard dollar savings offset all of the costs, or will this project
cause an increase in overall net costs?
Our current estimates indicate that the costs of this project, as compared to the
costs of continuing with the technology and operations that are currently in place, will result
in additional annual electric costs of $188,700. This additional cost represents approximately
13% of the Company s $146,000 000 of annual electric revenues.
With regard to natural gas, we estimate that the costs of this project, as compared to
the costs of continuing with the technology and operations that are currently in place, will
result in a decrease in costs of $63,000 per year. These cost savings represent approximately
12% of the Company s $51,000,000 annual natural gas revenues. These values are based on
an analysis of costs and benefits over a fifteen-year period. The costslbenefit analyses show
higher net costs in the early years, which decline over time. This is shown in Exhibit 13.
Holmes, Di
A vista Corporation
738
Pages 4, 5, and 6 depict estimated annual costs, savings and net annual revenue requirements
for an AMR system, compared to not installing an AMR system over a fifteen-year period.
We believe the relatively small levelized costs on the electric side are justified by
other benefits associated with this proposed system.
Please describe these additional benefits to the Company and its
customers.
There are a number of benefits to AMR that clearly exist, but for which dollar
values are difficult to quantify. For example, information obtained through a networked
AMR system will be of value in determining specifications for distribution equipment used to
serve our customers. Interval data provided by the system can be utilized for customer load
research and rate development programs.networked AMR system can provide
information to help manage operations during outages and may prevent extended customer
outages where a traditional outage report may have not been made.There may be
opportunities to provide meter-reading services for other utilities. Furthermore, the addition
of software in the future, not provided in the scope of this project, would allow customers on-
line access to hourly load profile data, which would allow them the opportunity to better
manage their electricity consumption.
Does this conclude your prefiled direct testimony?
Yes.
Holmes, Di
A vista Corporation
739
(The following proceedings were had in
open hearing.
(Avista Exhibi t No. 13, having been
premarked for identification , was admitted into evidence.
COMMI S S IONER KJELLANDER:And we're ready now for
Let's begin wi th Mr. Ward.cross.
MR. WARD:No questions.
COMMISSIONER KJELLANDER:Mr. Cox.
MR . COX:No questions.
COMMISSIONER KJELLANDER:Mr. Purdy.
MR . PURDY:No questions.
COMMISSIONER KJELLANDER:Mr. Woodbury.
MR. WOODBURY:No questions.
COMMISSIONER KJELLANDER:Any quest ions from
members of the Commission?
EXAMINATION
BY COMMISSIONER SMITH:
Mr. Holmes, were you here yesterday when I think
it was Mr. Morris I asked about investigating ongoing
looking into ways of doing advanced metering?
No, I wasn't here yesterday.
Ah.Well , my question to him wasOkay.
something along the lines of I'd heard of this VOlce-over power
740
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HOLMES (Com)
Avista
line and thought it might have potential for doing some of the
advanced metering that other AMR techniques have.I wonder if
the Company is looking into that.
Sure.The Company is examining what they call
BPL - - or , broadband power line - - carrier , and that's the
technology that also may allow voice-over power line.We'
examining this for a number of ways to provide services to our
It is true that it could be used in some cases tocustomers.
provide a communication link back out into the field.The
technology that we're proposing to install though basically
the technology that takes the reading from the meter itself and
transmits it back either through power line or through some
other kind of radio network.If BPL proves to be a viable way
of communicating, it very well could be integrated into our
system to reduce the costs that we've already proposed.
Thank you.
You're welcome.
EXAMINATION
BY COMMISSIONER KJELLANDER:
Just as a follow-up to that, are you actually,
through Avista, doing any type of internal investigation or
testing of the broadband technology via power line?
We've been examining the technology and we'
741
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HOLMES (Com)
Avista
visited some sites with the technology, and it's anticipated we
may have some sort of test of the technology.
Okay.Thank you.
COMMISSIONER KJELLANDER:Let's see.I believe
we're ready for redirect.
MR. MEYER:And I have none.
COMMISSIONER KJELLANDER:Okay.Thank you.
Appreciate your presence and your testimony.
THE WITNESS:Thank you.
(The wi tness left the stand.
COMMI S S IONER KJELLANDER:Would you like to call
your next witness?
MR. MEYER:Call Jon Powell , please.
JON POWELL,
produced as a witness at the instance of Avista , being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MR.MEYER:
All set?
Yes.
For the
employer.
record , please state your name and your
742
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
POWELL (Di)
Avista
Jon Powell , Avista Corporation.
Have you prepared and prefiled rebuttal
testimony?
Yes , I have.
And do you have any changes to make to that?
No, I don'
So if I were to ask you the questions in that
testimony, would your answers be the same?
Yes, they would be.
MR. MEYER:With that, I move the admission or
ask that it be spread as if read.
COMMISSIONER KJELLANDER:Wi thout obj ection
we'll spread the testimony as if read.
(The following prefiled rebuttal testimony
of Mr. Powell is spread upon the record.
743
HEDRI CK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
POWELL (D i )Avista
Please state your name, employer and business address.
My name is Jon Powell and I am employed as the manager of Washington and
Idaho demand-side management (DSM) activities for A vista Utilities, at 1411 East Mission
Avenue, Spokane, Washington.
Would you describe your educational background and professional
experience?
I have a Bachelor of Arts degree in economICS from the University of
California, San Diego and a Master of Arts degree in economics from San Diego State
University.I have also completed coursework towards a Ph.D. in economics at the
University of California, Santa Barbara and towards a Master of Business Administration
degree at San Diego State University. I have been employed in the utility industry since 1985
beginning with the San Diego Gas and Electric Company. I was first employed by the
Washington Water Power Company in 1990.In my current capacity I also represent the
Company in several regional organizations and forums including the Northwest Energy
Efficiency Alliance and Regional Technical Forum.
What is the scope of your testimony in this proceeding?
My rebuttal testimony will respond to the direct testimony of Staff Witness
Lynn Anderson, and Teri Ottens and Larry Stamper of the Community Action Partnership
Association of Idaho. My testimony will describe Avista s proposal for revisions in, and
modifications to, the level of electric DSM funding.I also discuss implementation
parameters of DSM programs available for our limited income and vulnerable customer
segment.
Powell, Di-Reb
A vista Corporation
744
Staff witness Anderson has proposed a reduction in the DSM tariff rider
rate from 1.950/0 of revenue to approximately 1.25010 of revenue, and has indicated that
Avista is in agreement with this reduction. Why is a reduction in the level of funding
for electric DSM appropriate at this time?
The current electric DSM tariff rider, equal to 1.95% of base rates was
established when the Company was carrying a negative tariff rider balance resulting from the
Company s efforts to significantly increase DSM resource acquisition in response to the
2000-2001 energy crisis. The Idaho electric DSM tariff rider balance has returned to, and
passed, a zero balance and the Company is currently managing a positive electric DSM
balance in spite of the expansion of several existing programs and launch of new programs.
A tariff rider equal to 1.25% of current base rates and the projected positive balance is
anticipated to be sufficient to meet forecasted funding needs for the subsequent year.
What would occur if the Company s proposed level of funding is less than
that needed for DSM acquisition?
The Company is committed to acquiring all available cost-effective DSM
resources. If this resource acquisition requires more funds than are available from DSM tariff
rider revenues, then a negative tariff rider balance would be incurred. Energy-efficiency
programs would continue to be developed and implemented and the Company would
continue to participate in the funding and implementation of regional market transformation
activities.
We propose to correct for any negative or positive balances in the electric or gas DSM
tariff riders through annual revisions to these riders based upon the forward balance and
Powell, Di-Reb
A vista Corporation
L~
projected funding requirements over the upcoming year. These periodic reassessments of the
tariff rider levels would also provide an opportunity for a timely review of the prudence of
the Company s investments in DSM resources.
Please explain what energy-efficiency programs are available to limited
income and vulnerable customers.
Limited income and vulnerable customers are eligible for our standard
residential rebates and additional DSM-funded programs offered in cooperation with
community action program (CAP) agencies. The Company enters into annual contracts with
these CAP agencies to provide an array of programs for this customer segment. These
programs are funded through the electric and gas DSM tariff riders and, since 2003 , have
been augmented with incremental BPA Conservation and Renewable Discount (C&RD)
funds for qualified energy-efficiency measures. The Company has sought to provide the CAP
agencies with as much flexibility as possible in applying these funds to various measures to
include weatherization and related shell measures, electric to natural gas conversion of space
and water heat, other HV AC improvements, residential lighting measures and other
efficiency measures. A limited amount of funding is available for health and human safety
measures to ensure the continued habitability of the home, as is generally required under
CAP standards, and to protect the longevity of the DSM investments made in the dwelling.
CAP agencies receive compensation for the administrative expense incurred on behalf of the
program through a reimbursement equal to 15% of the installed measure cost.
Powell, Di-Reb
A vista Corporation
746
Is a revision in limited income DSM programs reasonable as suggested
within the testimony of the Community Action Partnership Association of Idaho
(CAPAI)?
Yes, we believe that some of the proposed changes are reasonable. The
Company does periodically reevaluate the limited income DSM portfolio and makes
revisions as necessary. In order to ensure the continuity of programs, commitments have
been made to the five system-wide CAP agencies currently under contract to Avista for
funding contracts through 2005. A reevaluation of the portfolio has been anticipated for
funding in 2006 and beyond, coinciding with the expected depletion of funding available
through the BP A C&RD program. We believe it is reasonable, at that time, to increase the
funding availability based upon historic, current and projected future customer needs.
What is the Company s response to the proposed program revisions and
funding levels calculated by Commission Staff and CAP AI?
The Company proposes an increase in the annual funding of Idaho electric and
gas DSM programs to $350 000 commencing in 2006. This is slightly higher than the
calculation appearing in Staff witness Anderson s testimony, but less than the $490 000
originally proposed by CAP AI. This amount will come from the Company s tariff riders
Schedules 91 and 191 , and represents a reallocation of the current tariff rider programs. This
program funding commitment has been discussed with CAP AI and we understand that this
funding level is acceptable to them.
The CAP AI calculation of a $490 000 annual funding level, comparable to that
incorporated into the Idaho Power order, is based upon the assumption that the demographics
Powell, Di-Reb
A vista Corporation
747
of the northern ten counties of Idaho is representative of A vista s Idaho service territory. The
Idaho panhandle is served by a total of nine electric utilities and it is the Company s opinion
that such an assumption is inappropriate.
The proposed $350 000 does, however, represent a substantial but justifiable increase
in both authorized and actual funding for this market segment. To place this funding level
into perspective, it is over three times higher than the current A vista combined electric and
gas DSM funding contracts, and is substantially more than double the combination of DSM
and C&RD funds currently allocated in annual contracts within Idaho, and approximately
two-thirds higher than the total funding authorizations after mid-year transfers of funds to
Idaho.
The Company has also discussed a revision to the implementation protocols applied
to the limited income program and concurs with the CAP AI position on the following
recommendations: the extension of funding eligibility to include energy-efficient doors
electric or natural gas appliances, an expansion of window measures allowable within the
program, and the extension of eligibility for shell measures to include any customer with
permanently installed electric or natural gas heating appliances regardless of the historic
electric usage of the home. Customers eligible under U.S. Department of Energy income
qualification standards would be eligible for any measure meeting a savings to investment
ratio of 1.0 or above. Additional vulnerable customers may be deemed eligible as the
program implementation parameters are developed.
Why does the Company desire to defer this increase in DSM funding to
2006?
Powell, Di-Reb
A vista Corporation
748
The Company is targeting the limited income segment for the expenditure of
approximately $1.2 million of BP A C&RD funds system-wide during the three years ending
in 2005. Per discussions with CAP AI and a review of funding availability the Company is
prepared to commit to a minimum of$350 000 in funding for Idaho limited income programs
in 2005 using a combination of electric and gas DSM funds and BPA C&RD funds. This is
possible while continuing to fulfill contract commitments to CAP agencies system-wide.
With these changes, is it your understanding that you have addressed the
concerns raised by CAP AI in this case?
Yes, based on our discussions with CAP AI, that is my understanding.
Could you summarize your testimony to the Commission?
Yes.My testimony provides an elaboration of our recommendations
regarding two issues:
1. We recommend that the Commission revise the Company s Schedule 91 electric
tariff rider rates on a cents/kwh basis be an amount equal to 1.25% of current base retail rates
with the understanding that A vista will file as necessary to revise electric and gas tariff rider
levels to provide sufficient funding for cost-effective DSM programs.
2. We propose an increase in annual limited income electric and gas DSM funding to
$350 000 and revisions in the program implementation parameters as described in my
testimony. This funding will come from the Company s tariff riders, Schedules 91 and 191
and will result from a reallocation of current tariff rider budgets.
Does this conclude your prefiled rebuttal testimony?
Yes.
Powell, Di-Reb
A vista Corporation
749
(The following proceedings were had in
open hearing.
COMMISSIONER KJELLANDER:And we are now ready
then for cross.Let's start wi th Mr. Ward.
CROSS - EXAMINATION
BY MR. WARD:
Mr. Powell , I'm told you're the person that
should talk to about the new proposed method of funding DSM?
I wouldn't call it a new proposed method.
have Schedule 91 and Schedule 191 that have been in place since
1995.
Correct me if I'm wrong, it's difficult to tell
from the Company's direct case, but is the Company proposing to
change the way I'll call it the DSM surcharge is recovered from
a percentage of revenues to a flat fee per kWh?
You re partially right in that we are proposing
to revise Schedule 91 from a percent of revenues to an amount
equal to the percent of the current retail rate.I t breaks the
tie between the retail rate and the Schedule 91 so that we can
revise Schedule 91 as necessary to provide for DSM funding
sufficiency without the requirement to make such a revision
every time we change retail rates.
Okay.Would that schedule apply to Potlatch?
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HEDRICK COURT REPORTINGP. O. BOX 578, BOISE, ID 83701
POWELL (X)
Avista
As a Schedule 25 customer , yes, it would.
Now, you're aware , are you not , that when you
change from a percentage of revenues to a flat amount per kWh,
that I s going to be a huge shift for high load factor, high
consumption customers like Potlatch?
I think there's a misunderstanding there.We'
not talking about a flat cents per kilowatt hour across all
rates.We're talking about simply removing the percent of
retail rate language so that there is an independent procedure
for revising Schedule 91 that is not tied to retail rates.And
that's why in our previous conversations, we refer to it as an
amount equal percent current base rates.
Okay.t h i nk may understand.So what you
saying then Schedule customers other customers will
not see a significant shift in who does the funding?
From versus the current rate.There would be a
reduction from an amount equal to 1.95 percent of current base
rates which is today' s Schedule 91 to an amount equal to 1.
percent of current base rates.That is our proposal.
I understand.But in terms of the percentage
each customer pays, let's say that right now Potlatch pays
whatever it pays , 20 percent of the total to the State of
Idaho.And that's a big number , wouldn't you agree?
I don't know if the 20 percent is right.Twenty
percent would be a large number.
751
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
POWELL (X)Avista
Well I don't know that 20 percent is right
either , but it won't be exactly the same as their consumption
their revenues.But they pay a very significant percentage.
What m really trying find out that be i ng
the case,does this
- -
will this change result significant
increase or decrease in the amount Potlatch pays,
disregarding - - I mean , taking into account the fact that you
are lowering the overall funding?
I think what you're asking is wi 11 there be a
change in the distribution of funding across rate classes
versus what is currently in effect, and the answer to that is
no, we haven't discussed that, nor are we proposing it.
All right.Thanks.That's all I was trying to
find out.
COMMI S S IONER KJELLANDER:Thank you.
Mr. Cox.
MR. COX:I have no questions of this witness.
COMMISSIONER KJELLANDER:Mr. Purdy.
MR . PURDY:I actually do.
CROSS - EXAMINATION
BY MR. PURDY:
I guess I'm still a little confused, Mr. Powell.
To follow up to what Mr. Ward was asking you about, maybe
752
HEDRI CK COURT REPORTINGP. O. BOX 578, BOISE , ID 83701
POWELL (X)
Avista
you could turn to page 2 of your rebuttal and clear things up,
and I direct you to the first ine there.Do you have that in
front of you?
Yes, I do.
There you state that Staff wi tness Anderson'
proposed reduction in current DSM tariff rider from a rate of
95 percent of revenue to 1.25 percent of revenue.
Again, I'm a little confused because it sounded
like you testified earlier that you're going from a percentage
of revenue basis to some other basis.
Yes, our proposal is more accurately stated as
wishing to establish a Schedule 91 that is an amount equal to
25 percent of revenue but does not necessarily change with
each and every change in the retail state.That establishes
our abili ty to , independently of retail rate changes,
reapproach the Commission on a periodic, probably annual basis
to make revisions in the tariff rider.It is not necessarily
true that every time there's a change in retail rate up or down
that there's a change in the funding requirement for all
cost-effective DSM resources.
Okay.For the time being though , you are, in
terms of the total dollars collected from ratepayers for DSM
you are proposing a reduction for purposes of this case?
Yes, correct.We also have a carryover balance
that we expect this fall to be about six-tenths of a percent of
753
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
POWELL (X)Avista
retail rates, so there is a positive balance that mitigates
that reduction.
And are you making a firm commitment that in the
event that the DSM tariff rider balance goes negative , that you
will come before the Commission and seek an increase?
Our commitment is to acquire all cost-effective
DSM resources and come to the Commission whenever necessary to
establish sufficient revenues to obtain those resources.
All right.Wi th respect to the
Now, you're the only Company wi tness who'
provided testimony regarding the low-income weatherization
program.Is that correct?
Yes, it is.
And you are, I assume, quite familiar with that
program?
Yes, I'm reasonably familiar with it.
What is your official capacity with the Company
in that regard?
I manage the Washington and Idaho DSM portfolio
for the Company.
Okay.And in managing the portfolio, do you work
directly with the community action agencies?
Yes, we do.
What is the
- -
what is Avista' s current - - well
let me strike that.
754
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
POWELL (X)
Avista
The low income weatherization program is funded
through the DSM tariff rider.Correct?
It is.
What is the current level of low income
weatherization funding annually?
We have a contract for $108 000 per year for
Idaho.We also have an additional allotment of $43,000 from
BPA funds.That is the annual contract at the outset of the
year.
Over the course of the year, we reallocate funds
among the five CAP agencies that we work with for eliminating
DSM , and in the past those reallocations have always been
towards Idaho.Consequently, by the end of the year , they do
have more than the 108,000 and $43,000 available to them.
All right.Now , you said
- -
you mentioned BPA
funds.In your testimony, you also discuss I think we can call
it C&RD funds.Is that the same thing?
Conservation and renewable discount funds, yes.
And isn't it true that the future availability of
those funds is seriously in question?
Beyond October 2006, they are in question.
In fact, we don't even know if they're going to
be available?
No, we don'
Now , as reflected in your rebuttal testimony, the
755
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
POWELL (X)Avista
Company has reached an agreement of sorts with Community Action
Partnership Association.Is that right?
Yes , we have.
Okay.And is it fair to characterize the
agreement that was reached as a perhaps a compromise on the
parts of both parties?
Yes, it is.
And, in fact, the Community Action Partnership
Association was asking for 490,000 annually in funding.
Right?
Yes.
You indicate that the Company has agreed to
numerous program design changes.Just so the Commission
understands why that was important to my cl ient, would you
agree that the program design changes that the Company I s agreed
to provides considerable flexibility to the Community Action
Agencies in leveraging the funds available so that they can do
their best job in weatherizing homes?
Yes, it does.
All right.Now , let's see, I had a question.
you could turn to page 3 of your rebuttal for me?Actually, I
think thi s pertains more to page And on page 4, you testify
that the Company has agreed to the amount of $350,000 starting
in the year 2006 to fund the low income weatherization
program?
756
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
POWELL (X)
Avista
350,000 of gas and electric DSM funds in 2006.
And starting in 2006, that's exclusive of any BPA
funds that might be available?
Yes, it is.
But for the year 2005, you're going to use
whatever funds are available?
For the year 2005, we are committing to 108,000
in gas and electric DSM funds , with the remaining $242,000
being in BPA funds.
Okay.And because the low income weatherization
funds are collected through the DSM tariff rider and because
you are proposing, for the time being anyway, a decrease in the
tariff rider, just for the sake of anybody who might be
watching this hearing and might be concerned that we're robbing
Peter to pay Paul , is the Company's way of addressing that
concern by simply coming in a year from now and asking for an
increase in the DSM tariff rider should that be necessary?
Well , let me put that in a little perspective.
We're recoverlng 1. 95 percent at the moment because we were, in
the aftermath of the 2001 regional crisis, at a significant
deficit in that balance.The 1.95 percent helped us work our
way back to a zero balance in a timely way.We were not
expending that full amount during that time period.
Additionally, we now have a positive balance
that, when spread over the next year, would equal about
757
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
POWELL (X)
Avista
six-tenths of a percent of retail base rates.
So I think your question is will we have
sufficient funding to meet those obligations in the next year
and future years, and the answer would be, yes, we would
anticipate that we would.
Good.
That's all I have.MR . PURDY:Thank you.
COMMISSIONER KJELLANDER:Thank you.
Ms. Nordstrom.
MS. NORDSTROM:Thank you.
CROSS -EXAMINATION
BY MS. NORDSTROM:
Good afternoon.At the top of page 2, you state
that Mr. Anderson proposed a reduction in the DSM tariff rider.
Just to clarify, wasn't this reduction actually
proposed by Avista prior to Staff's conditional agreement to
and Mr. Anderson's testimony?
That would be more correct.The Company proposed
several al ternati ves and discussed them at length wi th our
triple E board.The settlement on this approach to
- -
this
approach and this amount to the tariff rider was something that
the Company has proposed.
At the top of page 3, you state that periodic
758
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
POWELL (X)
Avista
reassessments of tariff rider levels would provide opportunity
for prudence review of DSM investments.
By this do you mean that each year Avista would
ask the Commission to issue an Order declaring that Avista' s
electrici ty and gas DSM expendi tures were reasonable and
prudently incurred?
We haven't worked out the reporting requirements
that would be required for that or had anything other than very
brief discussions with our triple E board on the matter.
It's our anticipation that we would develop
reporting - - a reporting format that would be sufficient for
that sort of a request.
And if so, Avista would provide the Commission
with adequate information to make such findings?
Yes, we would.
Thank you.
I have no further questions.MS. NORDSTROM:
Quest ions from membersCOMMISSIONER KJELLANDER:
of the Commission?Commissioner Hansen.
EXAMINATION
BY COMMISSIONER HANSEN:
I guess I just would like to clarify one point
there that you made, see if I understood it correctly.
759
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID
POWELL (Com)
Avista83701
understand that you have a carryover of the tariff rider of
six-tenths of a percent.Is that correct?
Yeah, what we're projecting, about an $850 000
positive balance to the electric tariff rider at the end of
September , and that amount would be equal to about six-tenths
of a percent of retail base rates.
And what brought that about?
Well, the 1.95 percent tariff rider was In excess
of our needs.We were more successful at some of the
sustainable and unsustainable cost efficiencies than we had
anticipated.We were really not expecting to have that balance
back to zero until early in 2005.
I guess I'm just a little curious.Are you
finding that it's difficult to spend the money you'
collecting for DSM programs , to spend that money, and that'
part of the reason that you're creating this carryover
bal ance?
Well , we have eight programs that are ramping up
at the moment.Some of those have been ramping up more slowly
than expected and the cash incurrence of some of those programs
has lagged behind what we have expected.Consequently, we
reached a zero balance earl ier than expected and as resul ted in
a pos i t i ve bal ance as of today.
COMMISSIONER HANSEN:Thank you.That's a 11 I
have.
760
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
POWELL (Com)Avista
COMMI SS IONER KJELLANDER:Redirect?
MR. MEYER:No.
No redirect.Okay.COMMISSIONER KJELLANDER:
We appreciate your testimony.Thank you for
being here today.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:And I think at thi
point we'll take a ten-minute recess and be back promptly in
ten minutes, and you have one more wi tness Is that correct?
MR. MEYER:Mr. Hirschkorn.
COMMI SS IONER KJELLANDER:And we'll start there.
So we'll go off the record.
(Recess.
Very well.Mr. Hirschkorn to theMR. MEYER:
stand, please.
BRIAN J. HIRSCHKORN
produced as a witness at the instance of Avista, being first
duly sworn , was examined and testified as follows:
MR . MEYER:Just during the break, I passed out a
revi sed exhibi t sheet to everyone.You should have a one -page
document entitled Exhibit No. 20, page 9 of nine, and that is
part of Mr. Hirschkorn' s direct case, so that should be
inserted.But that goes in as a substitute page 9 of nine of
761
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID
HIRSCHKORN (Di)Avista83701
his direct Exhibi t No.2 0 .
COMMISSIONER SMITH:Mr. Chairman, could we maybe
put today ' s date on the corrected one so it doesn't get
confused wi th the previous one?
MR. MEYER:I can live wi th that.
COMMISSIONER KJELLANDER:And today is the 20th
and you said this is Exhibit 20.
MR. MEYER:, page 9 of nlne.
COMMISSIONER KJELLANDER:Thank you.
MR. MEYER:Thank you.
DIRECT EXAMINATION
BY MR. MEYER:
For the record , please state your name and your
employer.
My name is Brian Hirschkorn , and I'm employed by
Avista Corporation.
Have you prepared direct and rebut tal
testimony?
Yes , I have.
Any changes to make to that?
Along with the revised exhibit thatYes.
Mr. Meyer just handed out, on page 24 of my direct testimony,
on line 4 , six percent as shown on that line should change to
762
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HIRSCHKORN (Di)
Avista
five percent and then at the end of that ine, four percent
should change to three percent, and six percent should change
to five percent.And those numbers coinc ide wi th thi s revi sed
exhibi t here.
I might just briefly explain what this exhibit
shows too.This is comparative bill examples for Schedule
customers under our proposed rates, and the numbers that
changed from the original exhibi t are shown in bold on the last
three columns , the last lines.
Thank you.Any other corrections to make to your
testimony?
No.
So if I were to ask you the questions that
appeared in both your direct and rebut tal, would your answers
be the same?
Yes, they would.
Are you also sponsoring what have been marked for
identification as Exhibits 18 through 23, as well as
Exhibit 30?
Yes.
Was that prepared by you or under your direction
and supervision?
Yes, they were.
MR . MEYER:Wi th that, I ask that
Mr. Hirschkorn' s direct and rebuttal be spread as if read, move
763
HEDRI CK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
HIRSCHKORN (Di)
Avista
the admission of Exhibits 18 through 23, and 30.
COMMISSIONER KJELLANDER:Without obj ection,
spread the testimony and exhibit
- -
admit any exhibits that
were just referenced by Mr. Meyer.
(The following prefiled direct and
rebuttal testimony of Mr. Hirschkorn is spread upon the
record.
764
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
HIRSCHKORN (Di)
Avista
Corporation?
I. INTRODUCTION
Please state your name, business address and present position with A vista
My name is Brian J. Hirschkorn and my business address is 1411 East Mission
A venue, Spokane, Washington. I am presently assigned to the Rates Department as Manager
of Pricing.
Would you briefly describe your duties?
My primary areas of responsibility include electric and gas rate design,
customer usage and revenue analysis, and tariff administration.
Would you briefly describe your educational background?
I graduated from Washington State University in 1978 with Bachelor degrees
in Business Administration and Accounting.
Have you previously testified before the Commission?
Yes. I have testified before this Commission in several prior rate proceedings
as a revenue and rate design witness.
What is the scope of your testimony in this proceeding?
My testimony in this proceeding will cover the spread of the proposed annual
net electric revenue increase of $18,871,000, or 11.0%, among the Company s electric
general service schedules. The net increase consists of a proposed general increase of
$35,222 000 as well as the proposed reduction in the present Power Cost Adjustment (PCA)
surcharge $16 351 000. I will also provide information associated with electric service to
Potlatch's Lewiston Plant, and the basis for the proposed rates for service to the Plant. With
Hirschkorn, Di
A vista Corporation
765
regard to natural gas service, I will describe the spread of the proposed annual revenue
increase of $4,754 000, or 9.2%, among the Company s natural gas service schedules. My
testimony will also describe the design of the proposed rates within the Company s electric
and natural gas service schedules. I am also responsible for the revenue normalization
adjustments for both electric and natural gas, which I will briefly discuss.
Are you sponsoring any exhibits to be introduced in this proceeding?
Yes. I am sponsoring Exhibit Nos. 18, 19, and 20, related to the proposed
electric increase, and Exhibit Nos. 21 , 22, and 23, related to the proposed natural gas
increase. I will discuss these Exhibits in more detail later in my testimony.
II. EXECUTIVE SUMMARY
Pro osed Electric Increa
Q. What is the net proposed electric revenue increase in this Case, including the
proposed PCA surcharge reduction, and how is the Company proposing to spread the
increase by Schedule?
The net proposed electric increase is $18.9 million, or 11.0% over present
revenue/rates in effect, consisting of the proposed general increase of $35.2 million and a
proposed PCA surcharge decrease of $16.3 million. The net proposed increase by rate
schedule is as follows:
Hirschkorn, Di
A vista Corporation
766
Residential Service Schedule 1 13.
General Service Schedules 11 & 12
Large General Service Schedules 21 & 22 10.1 %
Extra Large General Service Schedule 25 15.
Potlatch (Lewiston) Schedule 25
Pumping Service Schedules 31 & 32 12.1 %
Street & Area Lighting Schedules 41-12.
This information is shown in detail on Page 2 of Exhibit No. 20.
What is the basis for the proposed increases by service schedule?
The Company used the results of the cost of service study, as sponsored by
Company Witness Knox as a guide in spreading the proposed general increase ($35.
million) by service schedule. The spread of the proposed general revenue increase, as shown
on Page 1 of Exhibit No. 20, results in moving the relative rates of return for the individual
rate schedules one half of the way toward unity (1.00). The rates of return for the individual
schedules are shown on Page 3 of Exhibit No. 20.
The proposed PCA surcharge is applied on a uniform percentage basis to each service
schedule and applied to the energy charge(s) under each schedule. The proposed level of the
surcharge is based on the recovery of the remaining estimated balance at October 1, 2004
($23 million) over the two-year period October 2004 - September 2006. The proposed level
of the PCA surcharge less the present surcharge level results in an annual revenue reduction
of $16.3 million.
Hirschkorn, Di
A vista Corporation
767
What is the proposed increase for a residential electric customer with
average consumption?
The proposed increase for a residential customer using an average of 941
kwhs per month is $7.85 per month, or a 13.9% increase in their electric bill. As part of that
increase, the Company is proposing that the basic / customer charge be increased from $4.
to $5.00 per month. The present bill for 941 kwhs is $56.52 compared to the proposed level
of $64.37.
Is the Company proposing any significant changes to the design of the
rates within any of its electric service schedules?
Yes. The Company is proposing to add an energy usage rate block to each of
its electric general service schedules (Schedules 11, 21 and 25), whereby the larger customers
served under those schedules would pay a lower incremental energy rate for usage beyond a
certain level. These proposals are reasonable and appropriate from a cost of service basis.
The result is that the proposed increase for customers within a Schedule will vary depending
on the customer s usage. This information is shown on pages 8 and 9 in Exhibit No. 20.
Where in your Exhibits do you show the proposed changes in rates within
the electric service schedules?
This infonnation is shown in detail on page 6 of Exhibit No. 20.
On January 15,2004, in Order No. 29418, this Commission approved a new
Power Purchase and Sale Agreement (Agreement) between A vista and Potlatch. The
Agreement states either Party can propose service rates for Potlatch's Lewiston Plant
Hirschkom, Di
A vista Corporation
768
that are different than Schedule 25. Is the Company proposing that Potlatch continue
to be served under Schedule 25 (rates)?
Yes. The Company is proposing that Potlatch continue to be served under
Schedule 25, however, the Company is proposing changes to the present Schedule 25 rate
structure that will result in Potlatch paying an average rate per kwh that is lower than the
average rate(s) paid by other Schedule 25 customers. The estimated incremental revenue
requirement resulting from the Agreement is $4.1 million which is included in general
revenue increase proposed in this filing.
~osed Natural Gas I,.crease
Q. How is the Company proposing to spread the overall natural gas increase of
$4,754,000, or 9.2% by service schedule?
The Company is proposing the following revenue/rate changes by rate
schedule:
General Service Schedule 101 10.
Large General Service Schedule 111/112
High Annual Load Factor - Lg. General Service Schedule 121/122
Interruptible Sales Service Schedule 131/132 3.4%
Transportation Service Schedule 146 18.
The proposed increase for Transportation Service Schedule 146 excludes gas costs;
including gas costs would result in an increase of approximately 3.2%. This information
also shown on Page 1 of Exhibit No. 23. The proposed increase by rate schedule results in a
Hirschkorn, Di
A vista Corporation
769
reasonable movement of the rates toward the cost of providing service (approximately one-
half way toward unity), as shown on page 2 of Exhibit No. 23.
What is the proposed monthly increase for a residential natural gas
customer with average usage?
The increase for a residential customer using an average of 73 therms of gas per
month would be $5.75 per month, or 9.6%, which includes a proposed increase in the monthly
basic customer charge from $3.28 to $5.00. A bill for 73 therms per month would increase
from the present level of $60.01 to a proposed level of $65.76.
III. PROPOSED ELECTRIC RATE INCREASE
Revenue Normaliza.!i!!!!
Would you please describe the electric "revenue normalization
adjustment" which you have referred to?
The electric revenue normalization adjustment represents the difference
between the company s actual recorded retail revenues during the test period and retail
revenues on a normalized (pro forma) basis. The total revenue normalization adjustment
increases Idaho revenues by $15,947,000 and net operating income by $10,195,000 as shown
in column (j) on page 5 of Exhibit No. 14. Nearly all of the adjustment results from restating
revenue from service to Potlatch's Lewiston plant (Plant) as a result of the 2003 Power
Purchase and Sales Agreement (Agreement) between A vista and Potlatch, which became
effective July 1,2003. Under the Agreement, Avista purchases approximately 60 average
megawatts of Potlatch's generation at the Plant and serves Potlatch's entire load requirement
Hirschkorn, Di
A vista Corporation
770
of approximately 100 megawatts under Rate Schedule 25. During 2002, Potlatch used its
generation to serve a major portion of its load requirements at the Plant, and A vista served
only about 40 average megawatts. As a result, the revenue adjustment associated with
service to Potlatch includes additional retail revenue based on the sale of an additional 60
average megawatts at Schedule 25 rates.
The remaining portion of the revenue normalization adjustment consists of three
components: 1) repricing customer usage (adjusted for known and measurable changes) at
present base tariff rates in effect, 2) adjusting customer loads and revenue to a calendar-year
basis (unbilled revenue adjustment), and 3) weather normalizing customer usage and revenue.
The net amount of these three components is a decrease in 2002 revenue of $746,000.
Is the calculation of the revenue adjustment associated with the three
components listed above the same as was used in the Company s last general case?
Yes, it is.
General Information
Could you briefly describe any significant changes in customer electric
consumption (energy usage) since the Company s last general case?
Yes. Since the Company s last general rate case, usage per customer appears
to have declined significantly for all customer classes. From 1997 (last general case test year)
to 2002, residential use per customer has declined from 1,037 kwhs per month to 941 kwhs,
or about 9%. Use per customer has declined about 8 % for commercial and industrial
customers during that time, and about 14% for the Company s largest customers served under
Schedule 25.
Hirschkorn, Di
A vista Corporation
771
Why do you think average customer usage has declined so significantly
since 1997?
I believe there are several reasons for the significant decrease in customer
usage. The first is the "energy crisis" which occurred during this period, where rising market
energy prices, blackouts, and energy company bankruptcies were all making daily headlines.
The second factor is the actual increase customers have seen in their energy bills during the
past several years. While the increase in the Company s electric rates has been only a
fraction of the increase in natural gas rates/prices during that time, customers appear to be
responding by decreasing all energy usage. Lastly, both the national and local economy went
through a downturn during this period, resulting in a loss of jobs.
Would you please explain what is contained in Exhibit No. 18?
Exhibit No. 18 is a copy of the proposed changes (strikeouts and underlines)
to the Company s electric general service tariffs as part of this filing.
Turning now to Exhibit No. 19, would you please state what is contained
in that Exhibit?
Exhibit No. 19 contains the proposed tariff sheets that are being filed with the
Commission as a part of our revised tariff, IPUC No. 28. Included in Exhibit No. 19 are the
proposed general service tariffs and the proposed Schedule 66 Temporary Power Cost
Adjustment, to become effective at the estimated conclusion of this case (September 2004).
The proposed change to Schedule 66 reflects the proposed reduction in the present PCA
surcharge.
Could you please explain what is contained in Exhibit No. 201
Hirschkorn, Di
A vista Corporation
772
Exhibit No. 20 contains information regarding the proposed rate spread and
rate design of the proposed revenue components in this case. Page 1 shows the proposed
general revenue and percentage increase by rate schedule compared to the present revenue
under base tariff rates (excluding the present PCA surcharge and other rate adjustments).
Page 2 shows the net proposed revenue and percentage changes for the combined effect of the
general increase and the PCA decrease, compared to revenue under present billing rates
including the present rate adjustments for the PCA surcharge and other rate adjustments.
Page 3 shows the rates of return by rate schedule before and after application of the proposed
general increase, based on the cost of service information presented by Company Witness
Knox. Page 6 shows the present billing rates under each of the rate schedules, the proposed
changes to the rates within the schedules, and the proposed rates after application of the
changes. These pages, as well as the other pages contained in Exhibit No. 20, will be referred
to later in my testimony.
Why do you compare the proposed revenue increase(s) to both present
revenue under base tariff rates (page 1) and revenue under present billing rates (page 2)?
Typically proposed rate spread and rate design information is shown as
compared to revenue and rates under base tariff rates, which exclude any temporary rate
adjustments, such as the Company s present PCA surcharge. However, the percentage
change(s) that customers will see on their bills will be based on present rates including the
present PCA surcharge and other rate adjustments. Because of the magnitude of the existing
PCA surcharge and the proposed reduction in the level of the surcharge, the Company
Hirschkorn, Di
A vista Corporation
773
believes that it is important to provide the information as it will ultimately affect customer
bills, as shown on Page 2 of Exhibit No. 20.
Would you please describe the Company s present rate schedules and the
types of electric service offered under each?
Yes. The Company presently provides electric service under Residential
Service Schedule 1 , General Service Schedules 11 and 12, Large General Service Schedules
21 and 22, Extra Large General Service Schedule 25, and Pumping Service Schedules 31 and
32. Additionally, the Company provides Street Lighting Service under Schedules 41-46, and
Area Lighting Service under Schedules 47, 48 and 49. Schedules 12,22,32, and 48 exist for
residential and farm service customers who qualify for the "Residential Exchange" program
operated by Bonneville. The rates for these schedules are identical to the rates for Schedules
11, 21, 31 , and 47 , respectively, except for the present Residential Exchange rate credit of
252 cents per kwh, as set forth under Schedule 59 of the Company s tariff. The following
table shows the type of customer and the approximate number of customers served in Idaho
(as of December 2003) under each of the schedules (except street and area lighting):
Schedule Tvpe of Customer No. of Customers
Residential Sch. 1 Residential 89,900
General Sch. 11&12 Small Commercial!less than 50 16,500
Lge. General Sch. 21 &22 Med. - Lge. Comm. & Industrial! over 50 kw 800
Ex. Lge. General Sch. 25 Lge. Comm. & Industrial! over 2,500 kva
Pumping Sch. 31&32 Water & effluent Pumping 1,100
Hirschkorn, Di
A vista Corporation
774
General Rate Increas~ - Proposed Rate Spread
How does the Company propose to spread the total general revenue
increase request of $35,222 000 among its various rate schedules?
The Company is proposing the following general revenue / rate increase(s) by
service schedule:
:emposed Genera1 Increase by Rate Schedule
Residential Service Schedule 26.
General Service Schedules 11 & 12 22.
Large General Service Schedules 21 & 22 23.
Extra Large General Service Schedule 25 27.
Potlatch (Lewiston) Schedule 25 19.
Pumping Service Schedules 31 & 32 23.4%
Street & Area Lighting Schedules 41-26.
This information is also shown on Page 1 of Exhibit No. 20. The proposed revenue increases
shown in the table above compare to an overall general revenue increase of 24.1 % over base
tariff revenue (excluding PCA surcharge and other rate adjustments), if applied uniformly to
each of the schedules.
Why is it necessary to examine the rate spread associated with the
proposed general increase?
It is necessary to eXamIne the spread of the proposed general increase
separately from the proposed PCA reduction as the general increase represents the proposed
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Hirschkorn, Di
A vista Corporation
change in base tariff rates , and revenues and costs associated with the PCA are excluded from
the cost of service study.
What rationale did the Company use in this proposed spread of the
overall general revenue increase to the various service schedules?
The Company utilized the results of the cost of service study, as sponsored by
Company Witness Knox, as a guide in developing the proposed rate spread. The primary
goal of the proposed rate spread is to move the rates of return of the individual service
schedules closer to the overall rate of return (unity) so that all customers contribute fairly to
the cost of providing service. The table below shows the relative rates of return by schedule
before and after the proposed increases are applied. The relative rate of return is determined
by dividing the rate of return for each schedule by the overall rate of return for the
Company s Idaho electric operations. This information is also shown on Page 3 of Exhibit
No. 20.
Relati ve Rates of Return by Service Schedule
Residential Service Schedule
Before Increase After Increase
0.42
1.53
1.73 1.36
1.11 1.05
1.54 1.27
General Service Schedules 11 & 12
Large General Service Schedules 21 & 22
Extra Large General Service Schedule 25
Potlatch (Lewiston) Schedule 25
Pumping Service Schedules 31 & 32
Street & Area Lighting Schedules 41-
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A vista Corporation
776
Application of the proposed revenue increase by schedule was based on moving the
relative rate of return approximately one-half way toward unity (1.00) after application of the
increase, with the exception of street and area light schedules.
Why is the Company proposing a spread of the proposed general rate
increase that results in the relative rates of return moving one-half toward unity?
Given the present disparity between the relative rates of return by rate
schedule, the Company believes that reducing that disparity by one-half in this proceeding is
reasonable balance between cost of service and other considerations.Further,
implementation of the proposed reduction in the present PCA surcharge will reduce the
amount of the general increase by 46%, from $35.2 million to $18.9 million. Therefore, the
proposed PCA surcharge reduction provides an opportunity to move base tariff rates closer to
the cost of providing service on a relative basis.
You mentioned earlier that the proposed increase in base tariff rates
results in a movement in the relative rate of return one-half of the way toward unity,
except for the proposed increase for street and area light schedules. Why don t you
propose an increase for these schedules that results in a similar movement toward
unity?
Even though the present relative rate of return for street and area light
schedules is 97% of unity (line 7, column (d) on page 3), a base rate increase of over 30%
(compared to the average of 24%) would need to be implemented just to maintain the present
97% of unity. This is because street and area light schedules have a higher percentage of rate
base per kwh compared to other schedules, and therefore, require a disproportionately higher
Hirschkorn, Di
A vista Corporation
777
revenue increase just to maintain the same relative rate of return. The higher level of rate
base for street and area lights results from an allocation of general system rate base and the
direct assignment of street lights and poles. Rather than propose an increase for street and
area light schedules substantially higher than that proposed for other schedules, the Company
is proposing a general increase of 26.8%, which is similar to the higher proposed increases by
schedule. The proposed general increase would result in a relative rate of return of 0., or
92% of unity, which the Company believes is a reasonable level.
What is the net proposed increase by service schedule including both the
proposed general increase and the reduction in the present PCA surcharge?
The following table shows the proposed net effective increase for each service
schedule:
Residential Service Schedule 13.
General Service Schedules 11 & 12
Large General Service Schedules 21 & 22 10.1 %
Extra Large General Service Schedule 25 15.
Potlatch (Lewis ton) Schedule 25
Pumping Service Schedules 31 & 32 12.1 %
Street & Area Lighting Schedules 41-12.
These net increases are based on present customer billing rates, including the present
PCA surcharge and other rate adjustments. In other words, they are the average percentage
Hirschkorn, Di
A vista Corporation
778
increase in customer bills under each Schedule. This information is also shown in more
detail on Page 2 of Exhibit No. 20.
f!:!!posed PCA Surcha.!)!e Reduction
Please describe the proposed reduction to the present PCA surcharge and
how the Company proposes to spread the proposed PCA surcharge level among its
service schedules.
The present PCA surcharge (Schedule 66) represents a 19.04% increase over
base tariff rates (2002 pro forma revenue), applied on a uniform percentage basis to each
service schedule. Within each schedule, the surcharge is applied only to the energy charge(s),
with the surcharge being the same rate for all energy usage within the schedule, except for
Residential Schedule 1. For Street and Area Light rates (Schedules 47-49), the surcharge is a
uniform percentage increase applied to base tariff rates. Page 4 of Exhibit No. 20 shows the
derivation of the present 19.04% surcharge level.
The proposed PCA surcharge level is based on recovery of the estimated deferral
balance at the end of September 2004 over the two-year period October 2004 - September
2006. September 2004 was used as the estimated date that the rates resulting from this Case
would go into effect. The estimated deferral balance in September 2004 is approximately
$23 million. By dividing the estimated balance by two (years), the Company would need to
recover $11.5 million each year, resulting in a 7.86% proposed PCA surcharge level
compared to present base tariff revenue/rates. As shown near the bottom of page 4 of Exhibit
No. 20, the proposed PCA surcharge would result in an 11.18% reduction in the present
surcharge level compared to revenue from base tariff rates.
Hirschkorn, Di
A vista Corporation
779
The overall proposed PCA surcharge level of 7.86% has been spread to the individual
rate schedules on the same basis as the present surcharge, i.e., on a uniform percentage basis
to each rate schedule and then applied as a single rate for all energy usage within the schedule
(except Schedule 1 which presently has a different PCA rate for each block), and as a
uniform percentage to all street and area light rates. The calculation of the proposed PCA
surcharge rates for each schedule is shown on Page 5 of Exhibit No. 20.
How does the Company propose that the final PCA surcharge rates as a
result of this Case be determined?
If the Commission accepts the Company s proposed methodology, the
(approved) annual PCA revenue to be recovered should be divided by the total approved level
of base tariff revenue, resulting in the new overall PCA surcharge percentage to apply to base
tariff rates / revenue. The overall percentage would then be applied to the approved base
tariff revenue by rate schedule, and the resulting surcharge revenue (by schedule) divided by
the total kwhs within each schedule to derive the new surcharge rate per kwh by schedule.
Is the Company proposing that the PCA surcharge rate for Potlatch be
different than the rate for other Schedule 25 customers?
Yes. Even though the Company is proposing that Potlatch continue to be
served under Schedule 25, as discussed later in my testimony, the Company is proposing a
slightly lower PCA surcharge rate for Potlatch, as shown on Page 5. This lower rate is based
on Potlatch's present average rate for service under Schedule 25 (3.80 cents/kwh) being less
than the average rate for other customers under the Schedule (4.07 cents/kwh).
Hirschkorn, Di
A vista Corporation
780
~osed Increase bv~hedu'e - Proposed Rate DeSifm
Where in your Exhibits do you show a comparison of the present and
proposed rates within each of the Company s electric service schedules?
Page 6 of Exhibit No. 20 shows a comparison of the present and proposed
rates within each of the schedules, which I will describe below. Column (a) shows the billing
components under each of the Schedules, column (b) shows the base tariff rates within each
of the schedules, column (c) shows the present PCA surcharge and other rate adjustments,
and column (d) shows the present billing rates. Column (e) shows the proposed general rate
increase to the rate components within each of the schedules, column (f) shows the proposed
PCA surcharge decrease, column (g) shows the net proposed increase (decrease) to the rates
within each schedule, and column (h) shows the proposed billing rates within each schedule.
Column (i) shows the proposed base tariff rate, which is the total of columns (b) and (e).
Is the Company proposing changes to the existing rate structures within
any of its rate schedules?
Yes. The present rate structures for general service Schedules 11 , 21 and 25
all have a single rate for all energy usage for customers served under these schedules. The
Company is proposing to add an additional energy rate block to each of these schedules. I
will describe these proposed changes, as well as the rationale behind them, later in my
testimony.
Turning to Residential Service Schedule 1, could you please describe the
present rate structure under this Schedule?
781
Hirschkorn, Di
A vista Corporation
Yes. Residential Schedule 1 has a present customer basic charge of $4.
per month, and two energy rate blocks for monthly usage below and above 600 kwhs. The
present base tariff rate for the first 600 kwhs per month is 4.555 cents per kwh and 5.303
cents per kwh for all usage over 600 kwhs.
How does the Company propose to spread the proposed general revenue
increase of $13.9 million to Schedule I?
The company proposes to increase the monthly customer charge from $4.00 to
$5.00, with the remaining revenue requirement recovered through a 1.303 cents per kwh
increase applied to all energy usage (both rate blocks) under the Schedule, as shown in
column (e) on page 6.
Why is the Company proposing an increase of $1.00 per month in the
customer charge?
The monthly customer charge should, at a minimum, recover the direct fixed
costs associated with providing service to customers. These costs include the average cost
for a service line and meter, and the monthly cost associated with meter reading and billing.
Page 7 of Exhibit No. 20 shows the monthly cost associated with these items to be $5.40 per
month at the proposed rate of return for the Schedule (7.03%). While a case can certainly be
made for the recovery of other fixed costs through the customer charge, such as customer
service and A&G costs, the Company believes that the charge should at least recover the
minimum average cost associated with providing this basic level of service.
What is the Company s present basic charge for residential customers
served in Washington?
Hirschkorn, Di
A vista Corporation
782
$5.00 per month.
What is the average monthly electric usage for a residential customer,
and what is the affect of the proposed increase on a customer s bill?
The average monthly usage for a residential customer is 941 kwhs. Based on
the net proposed increases to the rates under the Schedule, including the PCA surcharge
decrease, the average monthly increase would be $7.85, or 13.9%. The present monthly bill
for 941 kwhs of usage is $56.52 and the proposed monthly bill would be $64.37.
Turning to General Service Schedule 11 (and 12), you previously stated
that the Company is proposing to add an additional energy rate block to the Schedule.
Could you please describe the present rate structure and rates under the Schedule, as
well as the Company s proposal to add an additional rate block?
Yes.The present rate structure under the Schedule includes a monthly
customer charge of $6.00, a single energy rate of 6.564 cents per kwh for all usage under the
Schedule, and a demand charge of $3.50 per kw for all demand in excess of 20 kw per month.
There is no charge for the first 20 kw of demand.
The additional energy usage block would provide a lower energy rate for usage in
excess of 3,650 kwhs per month than for usage below that amount. The present rates under
the Schedule contain a single energy charge for all kwh usage and a demand charge for
monthly peak demand in excess of 20 kw. The present rates result in a higher average kwh
charge for customers in excess of 20 kw than for customers below 20 kw, regardless of their
load factor. The proposed rate design under the Schedule would be more reasonable when
compared to the cost of providing service, as well the rates under the Company s other
Hirschkom, Di
A vista Corporation
783
general service schedules 21 and 25. Generally, larger customers cost less to serve than
smaller customers on a per kwh basis and customers with higher load factors cost less to
serve than customers with poor load factors. The present rates under Schedules 21 and 25
have a monthly minimum charge that provides for a slightly lower average kwh rate for a
larger-use customer as compared with a smaller-use customer with the same load factor. The
present rates under Schedule 11 actually result in a higher average kwh charge to larger-use
customers than smaller-use customers with the same load factor, as well as a higher rate per
kwh for a customer whose peak demand exceeds 20 kw than the rate for a customer whose
demand is less than 20 kw , regardless of their load factors.
Page 8 of Exhibit No. 20 shows the average rate per kwh to several customers with
various load factors and energy and demand levels. Column (e) shows the average rate per
kwh under present rates and column (g) shows the average rate under the proposed rates, with
the addition of the rate block for usage in excess of 3,650 kwhs. Lines 1-3 show three
customers with different usage levels resulting in a 25% load factor. Lines 4-6 show three
customers with different usage levels resulting in a 50% load factor. As shown in column
(e), a higher-use customer always pays a higher average rate than a smaller-use customer with
a similar load factor, and a customer with a peak demand in excess of 20 kw always pays a
higher rate than a customer with 20 kw or less, regardless of load factor. As shown in
column (g), the proposed rates will result in approximately the same average rate per kwh as
usage increases, given similar load factors. The proposed rates will also provide an incentive
for most customers under the Schedule to improve their load factor. The addition of the
proposed energy rate block under Schedule 11 is a reasonable way to provide rates that are
8L~
Hirschkorn, Di
Avista Corporation
more consistent with the cost of providing service and the rates under the Company s other
general service schedules.
How is the Company proposing to apply the proposed general revenue
increase of $3.56 million to Schedule II?
The Company is proposing that no increase be applied to the present customer
charge or the demand charge (over 20 kw); the increase would be applied only to the energy
charge(s). As shown in column (e) on Page 6, the proposed increase for usage below 3,650
kwhs per month is 1.798 centslkwh and an increase of 0.040 centslkwh for usage above 3,650
kwhs per month.
You stated earlier that the Company is also proposing to add an energy
rate block under both Large General Service Schedule 21 and Extra Large General
Service Schedule 25. Could you explain these proposed changes and the rationale
behind them?
Yes. The Company is proposing to add an energy rate block to Schedule 21
for monthly usage in excess of 250,000 kwhs/month and a rate block to Schedule 25 for
usage in excess of 500 000 kwhs/month. Both schedules will have a lower incremental
energy rate for usage above these levels. The rate for usage above 250,000 kwhs under
Schedule 21 is proposed to be the same as the Schedule 25 rate for usage below 500,000
kwhs.
Approximately 1,800 customers take service under Schedule 21. Customers served
under the Schedule can have a monthly demand anywhere from 50 kw up to 2,500 kw, which
is the minimum level required for service under Schedule 25. Obviously, there is a wide
Hirschkorn, Di
A vista Corporation
785
range of customers served under Schedule 21, ranging from a small retail establishment to a
large manufacturing plant. Generally, larger use customers under the Schedule are less costly
to serve than smaller use customers on a cost per kwh basis, as some fixed costs are spread
over a larger base of usage. Therefore, a lower incremental! average rate for service to larger
use customers under a Schedule generally is supportable on a cost of service basis, which is
true for customers served under Schedule 21.
Additionally, the difference in the present rates under Schedules 21 and 25 are
substantial. There are a number of large customers served under Schedule 21 that are
somewhat similar in size and usage to Schedule 25 customers. In fact, several of these
customers have a higher load factor than many customers served under Schedule 25.
However, they pay an average energy rate under Schedule 21 that is presently up to 50%
higher than what they would pay under Schedule 25. As shown on page 3 of Exhibit No. 20
the cost of service results show that, in total, the rates for Schedule 21 exceed the cost of
service and the rates for Schedule 25 are less than the cost of service. Therefore, the rates
paid by large Schedule 21 customers are well above the cost of service and the rates paid by
smaller Schedule 25 customers are well below the cost of service.
Can large customers served under Schedule 21 take service under
Schedule 25? If so, what is the effect of such a change on the customer and the
Company?
Customers can switch from service under Schedule 21 to Schedule 25 if they
meet the minimum peak demand requirement of a 2 500 kva under Schedule 25. Because of
the present rate differential between the two Schedules, a customer switching from Schedule
786
Hirschkorn, Di
A vista Corporation
21 to 25 can see a lower annual energy bill well in excess of $100,000, which represents a
revenue/margin loss to the Company until it is eventually spread among other customers as a
result of a general rate change.
Have any customers switched from Schedule 21 to 25 recently?
Yes. Two of the fifteen customers presently served under Schedule 25
switched from Schedule 21 in 2003. Under present rates, both customers will see an annual
energy bill that is about 27% less under Schedule 25 than under Schedule 21 , or about
$180,000 per year (each). A portion of this savings is due to the differential in the present
PCA surcharge rates between the Schedules.Under the proposed rates, the present
differential of $180,000 is approximately cut in half.
How many customers are served under Schedule 21 whose monthly usage
exceeds the proposed energy block of 250,000 kwhs?
There are approximately 40 customers (out of 1,800), or 2% of customers
served under the Schedule, whose monthly usage exceeds 250,000 kwhs at some time during
the year. Approximately 15 of these 40 customers average more than 250,000 kwhs per
month. These fifteen customers include industriaVmanufacturing companies, hospitals, large
retail stores, a college campus, and a municipal account. Six of these customers average
more than 500,000 kwhs per month.
Have you examined how the proposed rates under Schedule 21 would
affect the bills of customers served under the Schedule at various usage levels?
Yes. Page 9 of Exhibit No. 20 shows the estimated change in customers' bills
under the Schedule at various usage levels, assuming they have a 50% load factor. As shown
Hirschkorn, Di
A vista Corporation
787
in column (f), about 98% of the customers under the Schedule would see about a 12.
increase under the proposed rates (including the PCA decrease). About 1 % of the customers
(who use more than 250,000 but less than 500,000 kwhs per month) would see an increase
between 6% and 12%, and about 6 customers would see an increase between 4% and 6%
based on their average usage in excess of 500,000 kwhs per month. Again, the purpose for
the additional rate blocks in Schedules 21 and 25 is to address the differences in the cost of
service for customers served within the Schedules, as well as reduce the level of rate disparity
for similar size customers served under the Schedules.
Could you please describe all of the proposed (general) rate changes
under Schedules 21 and 25?
As previously stated, the Company is proposing that the base tariff rate(s) be
the same for usage over 250,000 kwhs under Schedule 21 and for usage under 500,000 kwhs
under Schedule 25. This proposed rate is 4.393 cents per kwh, as shown in column (i) on
page 6. As shown in column (e), the proposed base rate increase for the first 250,000 kwhs
used per month under Schedule 21 is 1.254 cents per kwh, and the increase for kwh usage
over 250,000 per month is 0.497 cents per kwh. The Company is also proposing that the
present minimum demand charge be increased by $25 per month, from $225.00 to $250.00,
and the demand charge for kw over 50 per month be increased by $0.25 per kw, from $2.
to $3.00. These proposed changes result in the total proposed general revenue increase of
$8.3 million to Schedule 21, as shown on line 3, page 1, of Exhibit No. 20.
Regarding Schedule 25, as shown in column (e) on Page 6, the proposed base rate
increase for the first 500,000 kwhs used per month under Schedule 25 is 1.519 cents per kwh,
Hirschkorn, Di
A vista Corporation
788
and the increase for kwh usage over 500,000 per month is 0.546 cents per kwh. The
Company is also proposing that the present minimum demand charge be increased by $1,500
per month, from $7,500 to $9,000, and the demand charge for kva over 3,000 per month be
increased by $0.50 per kva, from $2.25 to $2.75. These proposed changes result in the total
proposed general revenue increase of $2.9 million to Schedule 25 (excluding Potlatch), as
shown on line 4, page 1, of Exhibit No. 20.
Is the Company proposing that Potlatch's Lewiston Plant continue to be
served under Schedule 25?
Yes.I will describe how the proposed Schedule 25 rates result in the
proposed increase to Potlatch (19.7% general, 7.1% net of PCA decrease) later in my
testimony.
Have you estimated the increase to individual Schedule 25 customers
based on the proposed rates?
Yes. There are 15 customers served under Schedule 25, including Potlatch.
The proposed rates result in an increase ranging from a low of 11 % to a high of 22%, with
the average being 15% (line 4, column h, on page 2 of Exhibit No. 20). As a result of the
proposed two-block energy rate structure, lower energy users under the Schedule would see a
higher percentage increase, while higher users would see a lower percentage increase.
What changes does the Company propose to the rates under Pumping
Schedule 31 to recover the proposed general revenue increase of $597,000?
The proposed general increase applicable to Pumping Service Schedule 31 is
spread on an equal cents per kwh basis to the present energy blocks in the Schedule. This
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results in a total general increase of 1.221 cents per kwh for all energy usage under the
Schedule, which is shown in column (e) on Page 6 of Exhibit No.20.
How is the Company proposing to spread the general revenue increase of
$500,000 applicable to street and area lights to the rates contained in those schedules
(Schedules 41-49)?
The Company proposes to increase all present street and area light rates on an
equal percentage basis. The resulting (base tariff) rates are shown in the proposed tariffs for
those Schedules, contained in Exhibit No. 19.
f!:2posed Electric Service to Potlatch's Lewiston PIW!!
On January 15, 2004, in Order No. 29418, this Commission approved a
new Power Purchase and Sale Agreement (Agreement) between A vista and Potlatch.
Please provide a brief description of the Agreement.
The Agreement is for a ten-year term, beginning July 1,2003 and ending June
30, 2013. As the sole purchaser of Potlatch's generation at the Plant, A vista pays Potlatch
$42.92 per megawatt-hour for up to 543,120 megawatt-hours (62 average megawatts)
generated by Potlatch during each "Operating Year" (July 1 through June 30) of the
Agreement. This amount is equivalent to 62 average megawatts and is referred to in the
Agreement as the "Base Generation Amount". There are special provisions in the Agreement
for the purchase of additional amounts generated by Potlatch in excess of the Base
Generation Amount. A vista will serve Potlatch's entire load requirements at the Lewiston
Plant, approximately 100 average megawatts, under its Extra Large General Service Schedule
25 rates, including the present Power Cost Adjustment (PC A) surcharge and all other
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applicable rate adjustments, unless the Commission issues an order in the future authorizing
different billing rates. Nothing in the Agreement prejudices either Avista s or Potlatch'
right to propose, or the Commission to order in future rate proceedings, that Avista s service
to Potlatch should be priced at rates other than Schedule 25.
The Agreement states either Party can propose service rates for Potlatch
that are different than Schedule 25. Is the Company proposing that Potlatch'
Lewiston Plant (potlatch) continue to be served under Schedule 25 (rates)?
Yes. The Company is proposing that Potlatch continue to be served under
Schedule 25, however, the Company is proposing changes to the present Schedule 25 rate
structure that will result in Potlatch paying an average rate per kwh that is lower than the
average rate(s) paid by other Schedule 25 customers. Based on the 2002 actual customer
loads used in this filing, the proposed average Schedule 25 base tariff rate per kwh for
Potlatch would be approximately 3.81 cents per kwh, compared to 4.39 cents per kwh for all
other Schedule 25 customers. Including the proposed PCA surcharge and other rate
adjustments, Potlatch's average rate per kwh would be 4.07 cents, and the average rate for all
other Schedule 25 customers would be 4.68 cents per kwh.
Based on the proposed rates for Schedule 25, why is Potlatch's average
rate so much lower than the average rate for other customers served under the
Schedule?
As discussed earlier in my testimony, the Company is proposing a two-tier
declining block energy rate structure for Schedule 25, as compared to the present single
energy rate for all usage under the Schedule. Because of the magnitude of Potlatch's load
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requirements, over 99% of their (2002) energy usage would be priced at the lower second-
block rate. For all other Schedule 25 customers in total, only 72% of their usage is priced at
the lower second block rate. Additionally, Potlatch's load factor is substantially higher than
other Schedule 25 customers, resulting in a lower effective demand charge per kwh as
compared to the other customers. As a result of these two factors, the average proposed rate
for service to Potlatch is lower than the average proposed rate for service to other Schedule
25 customers.
Why does the Company believe that the effective (average) rate for
Potlatch should be less than the rates for service to other Schedule 25 customers?
As shown in Exhibit No. 16, which is the Company s recommended cost of
service study sponsored by Company Witness Knox, the Company has analyzed service to
Potlatch's Lewiston Plant separately from other Schedule 25 customers. The relative size
Potlatch's load requirements alone warrants their separation in the cost of service study.
Potlatch's energy usage at the Plant represents 28% of the Company s total Idaho retail load
and their energy usage is approximately three times the combined load of the fourteen other
Schedule 25 accounts. As shown on lines 4 and 5, column d, page 3 of Exhibit No. 20, the
results of the cost of service study show that the rate of return under present rates for service
to Potlatch is higher than the Company s overall rate of return, while the rate of return for
service to other Schedule 25 customers is substantially less than the overall rate of return. As
discussed by witness Knox, one of the primary reasons for the difference in the present rate of
returns for Potlatch and the other Schedule 25 customers is the assignment and allocation of
distribution costs. Other Schedule 25 customers receive an allocation of all primary
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A vista Corporation
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distribution costs, as well as a direct assignment of the substation costs from which they
receive service. Potlatch receives service from only one A vista substation which is dedicated
to provide them service. The costs associated with that substation are directly assigned to
Potlatch. As service into that substation is at transmission voltage, no other primary
distribution costs are allocated to Potlatch. Therefore, the cost of providing service to
Potlatch is less than that for other Schedule 25 customers.
As discussed earlier, the Company is proposing a spread of the overall general
increase to result in a one-half movement toward unity. Based on the present rates of returns
shown in column (c) on page 3 of Exhibit No. 20, the Company is proposing a general
increase for other Schedule 25 customers (27.4%) that is higher than the overall increase
(24.%), and a general increase to Potlatch (19.7%) that is significantly lower than the overall
increase. As Potlatch has less rate base per kwh allocated to it relative to other customers
(opposite of street and area lights discussed earlier), Potlatch would receive a smaller
percentage increase than the overall increase in order to maintain the same relati ve rate of
return before and after the increase. This rate base effect, together with the small movement
toward unity in Potlatch's relative rate of return, results in the proposed general increase of
19.7% (7.1 % net of PCA decrease) compared with the overall general increase of 24.1 %
(11.0% net of PCA decrease). This overall proposed increase is accomplished by continuing
to serve Potlatch under Schedule 25 at the proposed rates and changes to the rate structure
under the Schedule.
It was estimated that the revenue and costs from the Agreement would
result in an incremental annual revenue requirement to the Company s Idaho
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operations of approximately $4.1 million. Is the $4.1 million estimate still reasonable,
and if so, is that amount included in the total revenue requirement in this Case?
The $4.1 million estimate that was part of the analyses supporting the
Agreement has not changed and is part of the overall revenue requirement requested in this
Case. The $4.1 million incremental revenue requirement included in this Case represents the
incremental net cost of the new Agreement to the Company compared to the net revenue and
costs associated with the prior agreement which is reflected in the Company s present base
tariff rates.
In the Company s proposed rate spread by service schedule, how much, if
any, of this $4.1 million incremental revenue requirement is included in the proposed
rates for service to the Lewiston Plant?
The cost associated with the purchase of Potlatch's generation is treated like
any other purchase power cost in the Company s cost of service study and allocated to all
service schedules based on energy usage and peak demand. Based on the allocation of
production expenses to Potlatch, Potlatch receives approximately 25.2% of these total
expenses. Applying this percentage to the incremental revenue requirement of $4.1 million
associated with the Agreement, Potlatch is being allocated approximately $1,033,000 of this
incremental amount.
IV. PROPOSED NATURAL GAS RATE INCREASE
Turning now to the Company s proposed natural gas increase, would you
please explain what is contained in Exhibit No. 21, entitled "Proposed Changes to
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Natural Gas Service Schedules
Exhibit No. 21 is a copy of the proposed changes (strikeouts and underlines) to
the Company s natural gas general service tariffs as part of this filing.
Would you please explain what is contained in Exhibit No. 22?
This Exhibit, entitled "Proposed Gas Rates , contains the proposed gas rates
and schedules which are being filed with the Commission as a part of our revised tariff, IPUC
No. 27.
Would you please describe what is contained in Exhibit No. 23?
Exhibit No. 23 contains supplemental information regarding the spread of the
proposed gas revenue increase to the Company s service schedules and the proposed rates
within the schedules, which I will refer to later in my testimony.
Revenue Normalizatiop Ad~ment
Could you please describe the "revenue normalization adjustment"
applicable to natural gas sales?
Yes. The gas revenue normalization adjustment is similar to the electric
adjustment and represents the difference between the company s actual revenues during the
test period and revenues based on normalizing and pro forma adjustments. The adjustment
includes the repricing of pro forma sales and transportation volumes at present rates using pro
forma sales volumes that have been adjusted for unbilled revenue, abnormal weather, and any
material customer load or schedule changes. The gas cost adjustment also includes the
normalization of purchase gas costs based on pro forma retail sales volumes. The total net
amount of both the revenue normalization and gas supply adjustments is a decrease of
795
Hirschkorn, Di
A vista Corporation
$112,000 on a net operating income basis, as shown in column (p) page 6 of Exhibit No. 15.
The rates used to price pro forma sales and transportation volumes include the present
rates contained in Schedule 150 - Purchase Gas Cost Adjustment, which is used to reflect
approved changes in the Company s cost of gas in PGA filings. The rates used exclude: 1)
temporary Gas Rate Adjustment Schedule 155, which reflects the approved amortization rate
for deferred gas costs approved in the Company s last PGA filing, and 2) DSM rider
adjustment Schedule 191.
Would you please explain the purchase gas cost adjustment, which is
included in the revenue normalization adjustment?
Pro forma purchase gas costs were determined by multiplying pro forma
customer usage for the test period by the purchase gas cost(s) per therm, which were
approved by the Commission in the Company s last PGA filing, effective October 3, 2003.
The purchase gas cost adjustment is then determined by subtracting actual gas costs during
the test year from pro forma gas costs. By making this adjustment, there is a matching of
revenue and gas costs, using pro forma sales volumes for the test period and the approved
rates and gas costs from the Company s last PGA filing.
Is the Company proposing any changes to the present allocation of
purchase gas costs by service schedule in this Case?
No, it is not.
General Information
Would you please review the Company s present rate schedules and the
types of gas service offered under each?
796
Hirschkorn, Di
A vista Corporation
Yes. The Company s present Schedules 101, 111, and 121 offer firm sales
service. Schedule 101 generally applies to residential and small commercial customers who
use less than 200 therms/month. Schedule 111 is generally for customers who consistently use
over 200 therms/month and Schedule 121 is generally for customers who use over 10,000
therms/month and have a high annual load factor. Schedule 131 provides interruptible sales
service to customers whose annual requirements exceed 250,000 therms. Schedule 146
provides transportation/distribution service for customer-owned gas for customers whose
annual requirements exceed 250,000 therms.
The Company also has rate schedules 112, 122, and 132 on file with the
Commission. Could you please explain what customers are eligible for service under
these schedules?
Schedules 112, 122, and 132 are in place to provide service to customers who
at one time were provided service under Transportation Service Schedule 146. The rates
under these schedules are the same as those under Schedules 111, 121, and 131 respectively,
except for the application of temporary Gas Rate Adjustment Schedule 155. Schedule 155 is a
temporary rate adjustment used to amortize the deferred gas costs approved by the
Commission in the prior PGA. Transportation service customers are analyzed individually to
determine their appropriate share of deferred gas costs. If those customers switch back to
sales service, the Company continues to analyze those customers individually, otherwise,
those customers would receive amounts of gas costs defeITals which are not due them, thus the
need for Schedules 112, 122, and 132. There are presently only 4 customers in total served
under these Schedules.
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797
How many customers does the Company serve under each of its rate
schedules?
As of December 2003, the Company provided service to the following number
of customers under each of its schedules:
Schedule No. of CustomersTvpe of Customer
General Service 101 Residential & Sm. Commercial 61 ,200
Lg. General Service 111 Comm. & Ind. - over 200 therms/mo.580
Ex. Lg. Gen. Service 121 Comm. & Ind. - over 10,000 therms/mo.
Interruptible Service 131 Interruptible - over 250,000 therms/yr.
Transportation Service 146 Transportation of Customer-owned Gas
Does the Company serve any natural gas customers under special.
contracts, with rates for service not included in any of its flied tariffs?
Yes. The Company serves three transportation service customers under special
contracts, all of which were filed with and approved by the Commission. All three of the
contracts were negotiated, executed, and approved based on the customer s close proximity to
an interstate pipeline and their reasonable ability to bypass the Company s distribution system.
The first contract is with Potlatch for transportation service to their Lewiston Plant. This
agreement was executed in 1993 and approved by Commission Order No. 25023 in Case No.
WWP-93-4. The next agreement is with Lignetics, a wood pellet manufacturing plant
located near the city of Kootenai. This agreement was approved by Commission Order No.
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798
24813 in Case No. WWP-93-1. The last agreement is with IMCO (formerly Imsamet), an
aluminum recovery plant located in Kootenai County. This agreement was approved by
Commission Order No. 26559 in Case No. WWP-96-2. All of the agreements presently
evergreen from year-to-year except for the agreement with Potlatch, which has a four-year
prior notice requirement for cancellation.
How much revenue was collected from these special contract
transportation customers during 2002, and how is this revenue treated in the Company
cost of service study?
Approximately $500,000 in revenue/margin was received from these three
customers during 2002. That revenue has been credited back to the other service schedules in
the cost of service study presented by Company Witness Knox.
Natural gas prices and rates have risen substantially over the past several
years. Has the Company seen a decrease in customer gas usage during this time?
Yes. From 1999 to 2002, Idaho residential and small commercial customers
decreased their gas usage from an average of 82 therms per month to 73 therms per month, or
about 11 %. During this same period, the number of residential and small commercial
customers served in Idaho increased by 11 %, or about 5,800. The net result is that total gas
sales to customers was essentially unchanged from 1999 to 2002, even though the Company
added 5,800 customers.
If residential customers used an average of 82 therms per month in 2002,
compared to their actual use of 73 therms, how much additional margin (revenue less
gas cost) would the Company have received during 2002?
Hirschkorn, Di
A vista Corporation
799
The Company would have received approximately $1.3 million in additional
margin which would reduce a substantial portion of the proposed revenue requirement.
Do you foresee customers increasing their average consumption in the
future?
I certainly would not expect customers to increase their consumption in the
near-term. There are no evident signs of gas prices falling considerably in the next year or so,
and with the rapid increase customers have seen in natural gas prices, it is unlikely they would
substantially change their consumption level unless prices decreased substantially and
remained at a lower level for several years.
Pro osed Rate S read
How does the Company propose to spread the overall revenue increase of
$4,754,000, or 9.2%, among its general service schedules?
The Company is proposing the following revenue/rate changes by rate
schedule:
General Service Schedule 101 10.
Large General Service Schedule 111/112
High Annual Load Factor - Lg. General Service Schedule 121/122
Interruptible Sales Service Schedule 131/132 3.4%
Transportation Service Schedule 146 18.
This information is also shown on Page 1 of Exhibit No. 23.
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A vista Corporation
800
Why is the Company proposing such a substantial increase for
Transportation Schedule 146?
The proposed increase for Transportation Schedule 146 is not comparable to
the proposed increases for the other (sales) service schedules, as Schedule 146 revenue does
not include an amount for the cost of gas or pipeline transportation, whereas the other sales
schedules include those costs/revenue (Transportation customers acquire their own gas and
pipeline transportation). Including an assumed level of 50.0 cents per therm for the cost of gas
and pipeline transportation, the proposed increase to Schedule 146 rates represents an average
increase of 3.2% in those customers' total gas bill, which is then expressed on a relatively
comparable basis to the proposed increase to the other (sales) service schedules.
What rationale did the Company use in its proposed spread of the overall
revenue increase to the various rate schedules?
The Company again utilized the results of the cost of service study, as
sponsored by Company witness Knox, as a guide in developing the proposed rate spread. The
proposed spread of the increase results in approximately a one-half movement of the rate of
return for each of the sales service schedules toward unity.
Page 2 of Exhibit No. 23 shows the rates of return for each of the Company s gas
schedules before and after application of the proposed increases. Column (d) shows the
relative rates of return under present rates and column (f) shows the relative rates of return
under proposed rates. The relative rates of return before and after application of the proposed
increases by schedule are as follows:
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A vista Corporation
801
Before After
Schedule 101:
Schedule 111:1.21 1.11
Schedule 121:1.25 1.13
Schedule 131:1.49 1.24
Schedule 146:1.58 1.28
As shown, the relative rates of return for all schedules move approximately halfway toward
unity (1.00) after application of the proposed increase(s).
Rate Deshm
Could you please explain what is shown on Page 3 of Exhibit No. 23?
Yes. Page 3 of Exhibit No. 23 shows a comparison of the present and proposed
rates within each of the Company s gas service schedules.
Could you please explain the present rate design of the Company s gas
service schedules?
General Service Schedule 101 generally applies to residential and small
commercial customers who use less than 200 therms/month. The schedule contains a single
rate/therm for all gas usage and a monthly customerlbasic charge.
Large General Service Schedule 111 has a three-tier declining-block rate structure and
is generally for customers who consistently use over 200 therms/month. The schedule consists
of a monthly minimum charge for the first 200 therms or less, and block rates for 201-000
therms/month and usage over 1,000 thenns/month.
High Load Factor - Large General Service Schedule 121 has a four-tier declining-block
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A vista Corporation
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rate structure with a monthly minimum charge for the first 500 therms or less, and block rates
for 501-1000 therms/month, 1 001-10,000 therms/month, and usage over 10 000
therms/month. There is also a minimum annual load factor requirement of approximately
58% under the Schedule.
Interruptible Sales Service Schedule 131 has a single rate for all usage and an annual
minimum charge based on a usage requirement of 250,000 therms per year.
Transportation Service Schedule 146 consists of a single rate for all volumes
transported on the Company s distribution system and an annual minimum charge based on
250,000 therms per year.
Is the Company proposing any changes to the present rate structures
contained in its gas service schedules?
Yes, but only one. The Company is proposing that a monthly customer basic
charge be added to Transportation Service Schedule 146. I will discuss this proposed change
later in my testimony.
You stated earlier in your testimony that the Company is proposing an
overall increase of 10.0% to the rates of General Service Schedule 101. Is the Company
proposing an increase to the present basic/customer charge of $3.28/month under the
schedule?
Yes, it is. The Company is proposing that the basic charge be increased from
$3.28 to $5.00 per month. The present basic charge of $3.28 has been in effect since 1989.
During that time, the Company s costs associated with providing gas service have increased
substantially. Page 4 of Exhibit No. 23 shows the monthly cost associated with meters, meter
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reading, billing, and service lines, as extracted from the Company s cost of service study. The
service line provides a connection from the distribution main, which typically runs along side
the street in front of a customer s residence, to the customer s meter. As shown, these costs
average $9.71 per customer per month; therefore, the proposed basic charge of $5.00 would
only recover about one-half of these basic fixed costs required to provide service. The
Company believes that the basic charge should, at a minimum, recover these costs. However
given the level of the overall increase proposed in this filing, the Company believes that the
proposed increase from $3.28 to $5.00 is reasonable.
What is the present gas basic customer charge for the Company
Schedule 101 customers in Washington?
$5.00 per month.
Given the proposed increase to the basic charge, what is the resulting
increase to the rate per therm under Schedule 101, in order to achieve the proposed
revenue increase of 10.0%?
The resulting proposed increase to the energy rate under the schedule is 5.515
cents per thermo
What would be the increase for a residential customer using an average
amount of natural gas?
The increase for a residential customer using an average of 73 therms of gas per
month would be $5.75 per month, or 9.6%. A bill for 73 therms per month would increase
from the present level of $60.01 to a proposed level of $65.76, including all gas rate
adjustments presently in effect.
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A vista Corporation
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Could you please explain the proposed changes in the rates for Large and
Extra Large General Service Schedules 111 and 121?
The present rates for Schedules 101, 111, and 121 provide a clear distinction
for customer placement: customers who use less than 200 therms/month should be placed on
Schedule 101 , customers who use between 200 and 10,000 therms per month should be placed
on Schedule 111 , and only those customers who generally use over 10,000 therms per month
should be placed on Schedule 121. The rates provide a guide for customer schedule
placement, as well as a reasonable classification of customers for analyzing the costs of
providing service.
The Company s proposed rates for Schedules 111 and 121 will maintain the rate
structure within the schedules and continue to provide a guide for appropriate schedule
placement for customers and a reasonable classification for cost analysis. The proposed
increase to the minimum charge for Schedule 111 (for 200 therms or less) of $12.75 per month
was derived by multiplying the proposed increase to the Schedule 101 rate per therm (5.515
cents) by 200 and adding the proposed increase in the customer charge of $1.72 ($5.00 less
$3.28). The remaining proposed revenue increase for Schedule 111 was then spread on an
equal cents per therm basis (4.140 cents) to the remaining two rate blocks under the Schedule,
resulting in an overall revenue increase of 6.6% for the Schedule.
For Schedule 121 , the increase in the minimum charge (for 500 therms or less) of
$29.30 was derived by multiplying the proposed increase in the Schedule 101 rate per therm
by 500 and adding the increase in the customer charge of $1.72. The second and third block
rates were then set equal to the corresponding block rates under Schedule 111 (4.140 cents per
Hirschkom, Di
A vista Corporation
805
therm increase). The proposed increase to the tail-block rate (over 10,000 therms) is 1.066
cents per therm, resulting in an overall revenue increase of 3.8% for the Schedule.
The Company is also proposing an annual minimum usage requirement of 60 000
therms for service under the Schedule. This requirement will not affect any customers
presently served under the Schedule and will provide a guide for customer placement under
the Schedule. This annual minimum usage requirement has been in effect for several years
under the corresponding rate schedule in Washington where it has mitigated past problems
regarding improper customer placement under the Schedule.
What is the proposed increase in the rate for Interruptible Service
Schedule 131?
The proposed increase is 1.876 cents per therm, which results in the proposed
revenue increase of 3.4% for the schedule.
Is the Company proposing any other changes to the rates set forth under
Schedule 131?
Yes. The present annual minimum charge is based on 250,000 therms times
the per therm sales under the Schedule, which includes gas costs. The Company proposes to
revise the annual minimum charge to an annual minimum deficiency charge based on margin
as it appears unreasonable to charge the customer for gas costs when the gas was not used.
This annual deficiency charge will be determined by subtracting the customer s annual usage
from 250,000 therms. Any resulting usage deficiency will be multiplied by the present margin
(revenue less gas costs) per therm under the Schedule, with the proposed margin level being
10.735 cents per thermo
Hirschkorn, Di
A vista Corporation
806
You mentioned previously that the Company is proposing a change in the
rate structure for Transportation Service Schedule 146. Could you please explain the
proposed change?
As shown in column (c) on Page 3 of Exhibit No.23, the Company is proposing
a monthly customer charge of $200.00, which is equivalent to the present customer charge for
transportation customers served in Washington. There are significant administrative costs
associated gas scheduling, balancing, and billing transportation customers. The proposed
customer charge is reasonably reflective of these administrative costs.
Given the proposed customer charge of $200 per month under the
Schedule, what is the proposed increase in the rate per therm.
The proposed increase in the rate per therm under Transportation Schedule 146
is 1.526 cents, as shown in column (b) on page 3.
Is the Company proposing any changes to the terms and conditions under
its gas service schedules?
Yes. The Company has added several provisions under Transportation
Schedule 146 related to gas interruption and entitlement, and the proposed penalty provisions
for customer overrun or underrun volumes in these various situations. These proposed
provisions are contained in Schedule 146 - Sheet A in Exhibit No. 22.
Are these proposed provisions consistent with the penalty provisions
contained in Northwest Pipeline s tariff and the Company s approved Washington
transportation tarim
Yes they are.
Hirschkorn, Di
A vista Corporation
807
V. ELECTRIC AND NATURAL GAS ENERGY EFFICIENCY
PRUDENCE REQUEST
What is the Company s request in this case regarding energy efficiency?
When the Commission approved the Company s energy efficiency programs
In 1995 (in Case Nos. WWP-94-12 and WWP-94-6), Avista committed
demonstrating the prudence of program expenditures in future general rate cases. In the
Company s last general electric rate case (Case No. WWP-98-11), the Commission issued
a finding that electric expenditures from the inception of the program through December 31
1998 were prudently incurred. At this time, the Company respectfully requests that the
Commission issue a finding that electric energy efficiency expenditures from January 1, 1999
through December 31, 2003 and natural gas energy efficiency expenditures from March 13,
1995 through December 31,2003 were prudently incurred.
Would you please summarize the Company s energy efficiency-related
programs?
Yes.As the Commission is aware, the Company s tariff riders under
Schedules 91 and 191 were the first non-bypassable distribution charges in the United States
to fund energy efficiency. The electric energy efficiency tariff rider is a 1.95% surcharge to
all rate classes, with the exception of pre-existing special contracts; the natural gas tariff rider
is a 0.50% distribution surcharge. Due to rising gas costs, it was reinstated in 2001 after its
initial implementation from 1995 through 1997.
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A vista Corporation
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The tariff rider and the corresponding energy efficiency programs, have been very
successful. Over 286 million kWh and 5.8 million therms have been saved through the
Company s energy efficiency programs since 1995.
Please summarize the Company s conclusions.
The Company s expenditure of tariff rider revenue has been reasonable and
prudent. A portfolio of programs covering all customer classes have been offered with a total
savings of over 286 million annual kWhs and 5.8 million therms. A 15-year levelized utility
cost per saved kilowatt hour of 1.4 cents per kWh has been achieved. The levelized avoided
costs during this similar period has been 4.7 cents per kWh. The 15 year levelized utility cost
per saved therm has averaged 14 cents per thermo
From a qualitative perspective, the rider and programs have been very successful.
Participating customers have benefited through lower bills. Non-participating customers
have benefited from the Company having acquired low cost resources as well as maintaining
the energy efficiency message and infrastructure for the benefit of our service territory.
During 2001 , when energy prices rose to unprecedented levels, the Company was able
quickly ramp up its energy efficiency programs. During a six-month period, Avista s energy
programs acquired three times its annual target savings at two times the price in half the time.
How are the energy efficiency programs organized?
The programs are organized around an expertise-based technical assistance
program portfolio. The Company s approach focuses on educating the customer about the
benefits of energy efficiency, providing a third party review, and outlining potential savings
of the project.
809
Hirschkorn, Di
A vista Corporation
What customer classes can benefit from these programs?
The Company s programs are delivered across a full customer spectrum.
Virtually all customers have had the opportunity to participate and a great many have directly
benefited from the program offerings. All customers have indirectly benefited through
enhanced cost-efficiencies of both the public and private sectors as a result of this portfolio.
For example, A vista has worked in cooperation with governmental entities such as the
Coeur d' Alene and Post Falls School Districts, the University of Idaho, North Idaho College
and others to secure cost-effective energy savings that directly benefit those specific agencies
but also indirectly benefit the community at large. Avista s work with major regional
employers in the private sector has materially improved their ability to compete in global
markets through implementing cost-effective energy-efficiency measures. Avista has directly
benefited residential customers through a broad array of well-received electric and gas
energy-efficiency programs.
Has there been ongoing review of the Company s programs?
Yes. The Company has regularly convened a stakeholders forum known as
the External Energy Efficiency Board.These meetings have included customer
representatives, Commission staff members, and individuals from the environmental
communities.These stakeholder meetings have reviewed each program as well as the
underlying cost-effectiveness tests and results.
VI. MISCELLANEOUS FEES
Is the Company proposing any changes to miscellaneous fees in this case?
810
Hirschkorn, Di
A vista Corporation
Yes. The Company is proposing minor changes to non-recurring charges for
reconnection for gas service following either voluntary or involuntary disconnects, as well as
after-hours service turn-ons. The proposed changes to reconnection rates on Schedules 70-
170-e, and 170-2 reconciles these rates so there is only one set of charges that applies to any
reconnect or service turn-on situation. The proposed rate is $24 for reconnections occurring
during normal business hours and $48 for after hours plus $4 for each additional service
connected at the same time. The net change to revenue would be less than $5,000 based on
2003 activity at the new rates. This is essentially a housekeeping revision to miscellaneous
fees.
Does that complete your pre-filed direct testimony in this proceeding?
Yes, it does.
811
Hirschkom, Di
A vista Corporation
Please state your name, business address and present position with the
Company.
My name is Brian J. Hirschkorn and my business address is 1411 East Mission
Avenue, Spokane, Washington. I am the Manager of Pricing in the Rates Department.
Mr. Hirschkorn, did you file direct testimony in this Case? If so, what
area(s) did your direct testimony address?
I filed direct testimony in this Case that discussed the Company s proposed
spread of the general increases for electric and natural gas service among its general service
schedules, as well as the proposed rates within each of the schedules. I also provided
information regarding the Company s proposal to reduce the level of the present PCA
surcharge by extending the recovery period, and information associated with electric service
to Potlatch's Lewiston Plant, and the basis for the proposed rates for service to the Plant.
What is the scope of your rebuttal testimony in this proceeding?
My rebuttal testimony in this proceeding will address certain rate spread and
rate design proposals contained in the direct testimony of Staff witness Schunke, Potlatch
witness Peseau, and Coeur Silver Valley witness Yankel.I will also address several
proposals made by Staff witnesses Hessing and Fuss related to revenue and rates.
Additionally, I provide minor revisions to the Company s original rate spread and rate design
associated with the proposed general electric increase based on the proposed revisions to the
Company cost of service study, as discussed in Company witness Knox rebuttal
testimony. Lastly, I provide guidelines that the Company recommends the Commission use
in the spread of the approved revenue requirements in this Case.
Hirschkorn, Di-Reb
A vista Corporation
812
Are you sponsoring any exhibits to be introduced in this proceeding?
Yes. I am sponsoring Exhibit No. 30, which I will discuss later in my
testimony.
Electric Rate Spread & Rate Desi~
Have you examined the Staff's proposed spread of their recommended
general electric revenue increase?
Yes. Staff witness Schunke describes the Staff's proposed general increase by
rate schedule. He uses the results of the cost of service study prepared by Staff witness
Hessing, who accepts the Company s original study presented in this Case with the revenue
adjustments proposed by the Staff. The results of the Staff's cost of service study are
presented on a slightly different basis as compared to the results presented by the Company.
The Staff presents the results of its study based on a revenue to total cost ratio, with the total
cost for each schedule including the Staff's overall proposed rate of return. The Company
study provides the resulting rate of return for each schedule, which assumes all other costs
have been offset by the revenue received from customers. While the Staff's presentation of
the cost of service results is reasonable, it should also be examined with the rate of return
results provided by the Company. As a comparative example, a revenue to total cost ratio for
a specific schedule could well exceed 80%, but produce a rate of return less than zero
(negative).
Have you prepared a comparison on a relative rate of return basis (rate
of return by schedule divided by overall rate of return), of the Staff's proposed rate
spread and the Company proposed spread?
Hirschkorn, Di-Reb
A vista Corporation
813
Yes. Column (d), page 1 of Exhibit No. 30 shows the relative rate of return by
schedule based on the Company s proposed spread of the original requested general revenue
increase of $35.2 million. As set forth in my direct testimony, the Company proposed a
spread of the proposed increase that resulted in a movement in the relative rate of return
.wproximately half way toward unity (1.00). This is illustrated on page 1 of Exhibit No. 30
by comparing columns (c) and (d). Column (e) shows the relative rates of return based on the
Staff's proposed rate spread and their overall recommended general increase of $23.
million. A comparison of columns (d) and (e), the results of Company s and Staff's proposed
rate spread, shows generally similar movement in the relative rates of return toward unity.
However, the results for Potlatch's Lewiston Facility show no movement in relative rate of
return under the Staff's rate spread.
In Company witness Knox s rebuttal testimony, she proposes two
revisions to the Company s cost of service study, one which revises the allocation
common costs and the other which revises the allocation of primary distribution costs,
related to Coeur Silver Valley witness Yankel's testimony. The result of these two
revisions increases the present rate of return for Schedule 25 customers (including
Potlatch's Lewiston Facility), and decreases the rate of return for other schedules. Is
the Company proposing to revise its original rate spread recommended in its direct
testimony based on these cost of service revisions?
Yes. Based on the significant increase in the present rate of return for
Schedule 25 that results from these revisions, the Company is proposing to reduce the
original proposed general increase for that Schedule from 27.4% to 25.5%. Including the
Hirschkorn, Di-Reb
A vista Corporation
814
Company s proposed PCA reduction, the net proposed increase for the Schedule is reduced
from 15.0% to 13.1 %. The reduction in the proposed increase for Schedule 25 is offset by an
additional increase to Residential Schedule 1 of 0.3%. These proposed revisions are
highlighted (outlined figures) in columns (1) and (h) on page 2 of Exhibit No. 30. No other
changes are proposed to the original general increases proposed by the Company for the other
schedules.
Do these proposed revisions result in a movement in the rates of return of
approximately one-half toward unity, as originally proposed by the Company?
Yes. Column (1), page 1 of Exhibit No. 30 shows the relative rates of return
by schedule with the revisions to the Company s cost of service study. Column (h) shows the
relative rates of return after application of the proposed increases shown in column (h) on
page 2 of Exhibit No. 30, including the revisions to Schedules 1 and 25. As shown in column
(h) on page 1, the relative rates of return move approximately half way toward unity, which is
consistent with the Company s original proposal.
Has the Company made adjustments to the Staff's cost of service study to
reflect the revisions made by Company witness Knox?
Yes. I have estimated the impact of the revisions discussed by witness Knox
in the Staff's cost of service results, which I will utilize below.
The Company s original requested general increase was $35.2 million. It
has reduced its requested increase in its rebuttal testimony to $31.1 million. Do you
recommend a guideline that the Commission could use that results in a movement of
one half toward unity re2ardless of the overall approved increase?
Hirschkorn, Di-Reb
A vista Corporation
815
Yes. Based on the Company s (revised) proposed revenue increases by
schedule, shown in column (g), page 2 of Exhibit No. 30, I divided the revenue increase for
each schedule by the original overall request ($35.2 million), which results in a ratio of the
revenue increase proposed for each schedule. These resulting ratios are shown in the table
below and in column (k), page 2 of Exhibit No. 30.
Comt!ill!Y Recommended Spread of Awroved Revenue Increase
Residential Schedule .401
General Service Schedule 11 101
Large General Service Schedule 21 236
Extra Large General Schedule 25 076
Potlatch (Schedule 25)155
Pumping Service Schedule 31 017
Street & Area Light Schedules 41-014
Total 000
Applying these ratios to the Staff's overall proposed revenue increase results in
revenue and percentage increases by schedule shown in columns (1) and (m) on page 2 of
Exhibit No. 30. Application of the resulting revenue increases by schedule under both the
Company s original proposed increase of $35.2 million and the Staff's overall proposed
increase to the respective cost of service studies results in the relative rates of return shown in
the following table:
Hirschkorn, Di-Reb
A vista Corporation
816
Relative Rates of Return by Schedule - Co. & Staff Proposed Revenue Requirement
Company Proposed Staff Proposed
Present Rates Revenue Re uire.Revenue Re uire.
Residential Sch. 1
General Service Sch. 11 1.96 1.48 1.51
Lge. General Service Sch. 21 1.68 1.33 1.33
Ex. Lge. General Service Sch. 25
Potlatch Sch. 25 1.19 1.09 1.10
Pumping Service Sch. 31 1.48 1.23 1.23
Street & Area Lights Schs. 41-
This information is also shown in columns (f), (h) and (i) on page 1 of Exhibit No. 30.
As shown, application of the proposed rate spread ratios in the table on page 5 to both the
Company and Staff overall revenue increase amounts results in nearly the same one-half
movement toward unity in the relative rates of return for each schedule. Therefore, the
Company recommends that the rate spread ratios in the table shown on page 5 be applied to
the general increase approved by the Commission.
What changes is the Company proposing to the rates within Residential
Schedule 1 and Extra Large General Schedule 25 to result in the rate spread revisions
discussed earlier?
Page 3 of Exhibit No. 30 shows the Company s revised proposed rates for
Schedules 1 and 25, with the changes shown in bold. This Exhibit is similar to page 6 of
Exhibit No. 20, filed in my direct testimony, and the rates within the two Schedules can be
Hirschkorn, Di-Reb
Avista Corporation
817
compared between the two Exhibits. As shown, the rates for each of the two blocks
contained in Residential Schedule 1 have been increased by 0.02 cents per kwh compared to
the proposed rates in my direct testimony. For Schedule 25, the first block energy rate has
been decreased by 0.244 cents per kwh and the second block rate has been increased by 0.002
cents per kwh compared to the original proposed rates for the Schedule. The proposed
changes to the rates for Schedule 25 was an iterative process that maintained the original
proposed revenue increase for Potlatch's Lewiston Facility and resulted in the reduction in
the proposed increase for other Schedule 25 customers.
Depending on the overall general electric revenue level approved by the
Commission in this Case, how would you propose to adjust the rates within the
Schedules, given the rate spread methodology discussed earlier?
Starting with Residential Schedule 1 , if the Commission approves the
Company s proposed increase in the monthly basic charge from $4.00 to $5.00, I would
propose that the rates for the two energy usage blocks be adjusted on an equal cents per kwh
basis from the proposed levels shown in column (e), page 3 of Exhibit No. 30. However, if
the Commission does not approve an increase in the basic charge, I would propose that a
higher percentage increase be applied to the present first block rate (0-600 kwhs), as
recommended by Staff witness Schunke, on page 10 of his testimony.
With regard to General Service Schedules 11,21 and 25, the Staff agrees with the
Company s proposed increases to the minimum and demand charges under those Schedules.
The Company recommends that the proposed energy rates within those Schedules be adjusted
on a uniform percentage basis from the proposed rates for Schedules 11 and 21, shown in
Hirschkom, Di-Reb
A vista Corporation
818
column (e) on page 6 of Exhibit No. 20, and for Schedule 25, as shown on page 3 of Exhibit
No. 30.
For Pumping Schedule 31 , the Company proposes that the rates be adjusted on a
uniform cents per kwh basis, and for Street and Area Light Schedules, all rates be revised by
the overall increase applied to the Schedules.
Other Electric Issues
On pages 10 and 11 of Staff witness Schunke s testimony, he recommends
that the Residential basic charge not be increased from the present level of $4.00 per
month to $5.00, as proposed by the Company. He states that the basic charge should
not recover any fixed plant costs and references Commission Order No. 29505 in the
recent Idaho Power Case to support his proposal. Does the Company still propose to
increase the basic charge in light of Mr. Schunke s testimony?
Yes, it does. With all due respect to the Commission s recent Order, the
Company believes that the basic charge should recover more than meter reading and billing
costs. There is a meter and a service line on the customer s property that is dedicated to serve
that customer. It is appropriate for the basic charge to cover the cost associated with plant
(meter and service line) that is on the customer s property and dedicated to serve that
customer, as well as meter reading and billing costs. As shown in column (e) page 7 of
Exhibit No. 20, these costs exceed the $5.00 basic charge proposed by the Company.
With regard to the Company s proposed two energy block rate structure
for General Service Schedule 11, on pages 12-14 of Mr. Schunke s testimony, he
recommends that the Company s proposal be accepted for now. However, he also
Hirschkorn, Di - Reb
A vista Corporation
819
recommends that in the Company s next general case, this rate structure be eliminated
and that customers served under Schedule 11 be divided into two schedules, those with
demand meters and those without. Do you have any concerns with regard to Mr.
Schunke s recommendation to create these two schedules in the future?
Not at this time, however, as stated by Mr. Schunke, the Company does not
have all the information at this time to implement such a change in rate structure. Over
16,000 customers are served under this Schedule and, as pointed out by Mr. Schunke, a study
is needed to assess the effects of separating those customers into two rate schedules. The
Company will conduct such a study prior to its next general filing, provide the results of the
study to the Commission, and collectively assess whether Mr. Schunke s proposal should be
implemented.
On pages 21 and 22 of Staff witness Hessing s testimony, he agrees with
the Company s proposed PCA rate reduction methodology, however, he proposes using
the actual PCA deferral balance, rather than the estimated balance provided in the
Company s direct Case. Do you agree with Mr. Hessing s recommendation?
Yes. The PCA rate reduction could be based on recovery of the most recent
actual deferral balance over the next two years. The Company used an estimated balance and
implementation date in its direct testimony, as that was the best information it had at that
time.
On pages 22-24 of Mr. Hessing s testimony, he also recommends that once
the present PCA balance is recovered, that the PCA rate spread methodology for any
future rebates or surcharges be changed from the present uniform percentage spread
Hirschkorn, Di-Reb
A vista Corporation
820
across the schedules to a uniform cents per kwh to all schedules. Do you agree with Mr.
Hessing proposal?
Yes. From a cost causation viewpoint, an equal cents per kwh application to
all schedules is more appropriate than the present methodology. I also agree with Mr.
Hessing s proposed timing of the change in methodology, when the present deferral balance
is recovered.
Turning now to Potlatch witness Peseau s testimony, on pages 45 and 46
of his testimony, he recommends that a separate rate schedule be established for
Potlatch's Lewiston Facility. Do you agree with his recommendation?
Mr. Peseau s recommendation does have merit, especially as rates are moved
closer to the cost of providing service in the future. In the Company s direct filing, I have
proposed a two-block rate structure for Schedule 25 that partially addresses cost of service
and fairness issues between large Schedule 21 customers and Schedule 25 customers (pages
21-25 of my direct testimony). That rate structure also reflects the lower cost of providing
service to Potlatch's Lewiston Facility as a Schedule 25 customer by pricing the majority of
their usage at the lower tail-block rate. As a result of the changes to the Company s cost of
service study discussed earlier, in order to accomplish the same relative movement toward
cost of service and maintain Potlatch as a Schedule 25 customer, the reduction in the
proposed general increase for Schedule 25 (from 27.4% to 25.5%), had to be accomplished
entirely through a reduction in the first block rate. If rates are to move closer to cost of
service in the future, it will become more difficult to design Schedule 25 rates that maintain
Potlatch's Lewiston Facility as a Schedule 25 customer.
Hirschkorn, Di-Reb
A vista Corporation
821
If the Commission created a separate rate schedule for Potlatch'
Lewiston Facility as a result of this proceeding, would the Company alter its
recommended revision to Schedule 25 energy rates, as discussed earlier?
Yes. If the Commission created a separate schedule for Potlatch, I would
propose that the original proposed energy rates for Schedule 25 , shown in column (e), page 6
of Exhibit No. 20, be reduced by a uniform percentage to yield the revised overall increase
for the Schedule.
On pages 44 and 45 of Mr. Peseau s testimony, he also recommends that
the rates for all service schedules be moved to full cost of service (unity) in this Case if
the overall increase is less than 10%. If the overall increase exceeds 10%, he
recommends that all schedules be moved to unity over the next two years. Do you agree
with this proposal?
No. I believe that the cost of service study is a primary guide to be used in
establishing rates and the Company s proposal to move approximately half way toward unity
as a result of this Case is appropriate. Even though cost of service should be used as a
primary guide, the testimony in this Case has shown that one or two adjustments in cost
allocation can significantly change the results of a study. Further, with the changes that have
occurred in the electric industry and may continue to occur in the future, unforeseen events
could affect current costs and cost allocation. Therefore, I don t believe that it makes sense at
this time to establish a schedule for further rate adjustments based on a current cost of service
study.
Hirschkorn, Di-Reb
A vista Corporation
822
Turning now to Coeur Silver Valley witness Yankel's testimony, on pages
10-15 he essentially states that the proposed demand charges under Schedule 25 are too
low and that the proposed rates for Schedule 25 do not send a strong enough price
signal for customers to improve their load factor. Do you agree with this portion of Mr.
Yankel's testimony?
I do agree with this portion of Mr. Yankel's testimony, however, I believe the
Company s proposed increases to the demand charges under Schedule 25 are appropriate in
this Case. The Company is proposing over a 20% increase to the demand charges under
Schedule 25, which exceeds the overall increase for the Schedule (net of PCA reduction).
agree that Schedule 25 demand charges should be further increased, but in reasonable
amounts over time.
Within pages 10-15 of his testimony, Mr. Yankel also states that Coeur
Silver Valley has the highest energy usage and the highest load factor of the customers
served under Schedule 25 (except for Potlatch) and that the proposed rates for Schedule
25 do not reasonably reflect this fact. Do you agree?
No. Page 4 of Exhibit No. 30 shows the proposed increase for each of the
present Schedule 25 customers based on the revised rates shown on page 3 of Exhibit No. 30.
As shown, Coeur Silver Valley would receive the lowest increase (10.3%) of any customer
and significantly less than the overall increase for the Schedule (13.
%).
Natural Gas Rate Issues
On page 19 of Mr. Schunke s testimony, he proposes no change to the
present basic charge under Gas General Service Schedule 101 (residential and small
Hirschkorn, Di-Reb
A vista Corporation
823
commercial), which is presently $3.28. Does the Company still believe its proposed
increase to $5.00 per month is reasonable?
Yes. As stated on page 39 of my direct testimony, the present basic charge of
$3.28 has been in effect since 1989. Obviously, the cost of providing service has increased
over the past fifteen years. As previously stated, the Company believes that the basic charge
should recover a reasonable level of costs that are dedicated to provide service to a customer.
The Company believes these costs not only include meter reading and billing, but also the
cost associated with providing a meter and service line. As shown on page 4 of Exhibit No.
, the average cost associated with these expenses is well over $9 per customer per month.
Increasing the basic charge to $5.00 per month in this proceeding is not unreasonable.
Does the Staff support uniform customer (basic) charges for residential
electric and natural gas service?
Yes. Staff witness Parker states on page 6 of her testimony that "Uniform
customer charges are certainly easier for customers to understand and for the Company to
administer." Witness Parker goes on to state "Although the Staff supports uniform customer
charges, Staff does not support the Company s proposed increase to $5.00." Witness Parker
also discusses customer opposition received to the Company s proposed increases in
customer charges. However, it should be noted that customer charges of $5.00 or more per
month are common for other utility services such as telephone, water, sewer, etc.
Given the Staff's overall proposed gas revenue increase , do you have any
other concerns with the Staff's proposed rates for the Company s gas service schedules?
824
Hirschkorn, Di - Reb
A vista Corporation
Yes. As stated on pages 41 and 42 in my direct testimony, the rates for
General Service Schedules 101, 111 and 121 provide a distinction for customer placement on
a schedule based on usage. The Staff's proposed rates under Schedules 111 and 121 changes
the present relationship between the Schedules and could cause additional customer shifting
between rate schedules. Further, the Staff's proposed minimum charges for Schedules 111
and 121 incorporate current PGA gas costs under Schedule 150, regardless of the customer
usage. The Company believes that it is more reasonable to increase the fixed minimum
charge under those Schedules by the increase in margin, as described in my direct testimony,
and bill the present Schedule 150 rate only for those therms used by the customer. The
Company s proposed rates incorporate the present Schedule 150 rate in the block usage rates
under those Schedules and as an additional variable charge to the monthly minimum charge.
Would you propose to use the rate design methodology described on
pages 41 and 42 of your direct testimony, regardless of the level of the approved gas
increase?
Yes.
Have you revised the Staff's proposed rates for Schedules 111 and 121
based on the Staff's proposed increase to those Schedules and the parameters you
addressed above?
Yes. Page 5 of Exhibit No. 30 shows a comparison of the rates proposed by
Staff and the rates the Company would propose to produce the same level of revenue for
those Schedules and meet the parameters addressed above.
Hirschkorn, Di-Reb
A vista Corporation
825
On page 11 of Staff witness Fuss' testimony, he proposes an adjustment
that increases current gas revenue and decreases the Company s proposed revenue
requirement by $23,000. Do you agree with his proposed adjustment?
appropriate.
Other Issues
Yes. I have discussed this adjustment with Mr. Fuss and agree that it is
On page 17 of Mr. Fuss' testimony, he proposes that the Company add a
tariff sheet that shows the actual billing rates under each schedule by summarizing the
base tariff rate and all other applicable (adder) rate schedules. Do you agree with his
proposal?
Yes. In fact, the Company presently prepares such a summary sheet for
internal purposes and revises it each time rates change. Filing a summary sheet with this
information would provide the Commission and other interested parties with a quick
reference to the Company s actual billing rates.
On pages 7 and 8 of Staff witness Parker s testimony, she recommends
elimination of the Company s present charge of $4.00 for reconnecting an additional
service at a premise where more than one service (electric and gas) have been
disconnected. Do you agree with her proposal?
I believe this proposal is reasonable and the Company would make the tariff
changes set forth in her testimony if approved by the Commission.
Does that complete your rebuttal testimony in this proceeding?
Yes, it does.
Hirschkorn, Di-Reb
A vista Corporation
826
(The following proceedings were had in
open hearing.
(Avista Exhibit Nos. 18 through 23, and
, having been premarked for identification, were admitted
into evidence.
COMM IS S lONER KJELLANDER:And we're ready then
for cross-examination.Let's begin wi th Mr. Woodbury.
MR. WOODBURY:Thank you, Mr. Cha i rman .
CROSS - EXAMINA T I ON
BY MR. WOODBURY:
Mr. Hirschkorn , In your rebuttal testimony,
page 14 , and in your direct testimony, pages 41 , 42 , the
Company expresses concern wi th the potential of natural gas
customers switching between general service rate schedules, and
the schedules you're talking about are 101, Ill , and 121.Such
a shift would have what consequence?
I guess two consequences could resul t from that:
Potential customer confusion from switching schedules, and the
other could be some revenue deficiency.If a customer
better off, he saves money under another schedule, we could end
up with revenue deficiency.So kind of a two-part effect that
could resul t
Would you accept that the difference between the
827
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HIRSCHKORN (X)
Avista
first block rates for Schedules III and 121 is greater for both
Staff's proposed rates in the Company's base case than those
proposed in the Company's rebut tal?
Yes, I would accept that.
Would you accept that the break-even point, the
shift between 101 and III under Staff's proposed rates, is
192 therms?
Yes, that's correct.
And as proposed by the Company, it'
approximately 200 therms?
Yes.
And do you believe that eight therms is a
significant difference and that customers would shift for about
$6.25?
They certainly could.Under Schedule 101, it
serves pretty much all of our residential customers and about
two-thirds of our commercial customers.We have 62 000 total
gas customers.Over 61 , 000 are served under Schedule 101.
Even though eight therms sounds like a fairly small amount,
typically, a customer using less than 200 therms is better off
with Schedule 101.
It's about four percent - - that eight therms
about four percent of 200 therms.If you take four percent , if
those customers' usage was evenly distributed from zero to 200
therms and you took four percent of the customers, that's like
828
HEDRI CK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
HIRSCHKORN (X)
Avista
500 customers.Granted , they're not evenly distributed, but
even if a quarter of the customers of that 2,500 were to fall
in that last eight therms, that could be 500 customers that
could potentially shift because of this small change.
So even though it doesn't sound ike a lot in
terms of changing that break-even level , it certainly could be.
It could be quite an affect.
I sn 't the proposed one -year contract requirement
for Schedule III and the 60,000 therm annual minimum
requirement for Schedule 121 an attempt by the Company to
discourage swi tching?
Yes.Yes, it is, but if -- I'm not sure what we
would do if a rate change caused a customer to be on the wrong
schedule.In other words, they're on the right schedule now,
we change rates , oop, you'd be bet ter off on another schedule.
Do we change them since maybe they haven't been on that
schedule for a year?I don't know.
It's true that Staff supported the Company'
one -year contract requirement and 60, 000 - therm annual
minimum?
Under Schedule 121.
Yes.
Yes, that's correct.
Regarding Staff's proposed minimum charge
addressed by you on - - in your rebuttal on page 14, line
829
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HIRSCHKORN (X)
Avista
isn't it true that the existing base rates include all base gas
cos t s and the mini mum charge?
Yes , but that level is only
- -
I think it's less
than 20 cents a thermo
Isn't it arbitrary to include any other amount of
gas in that minimum?
Arbitrary?
Uh-huh.
m not
- -
I don't understand the question.
It's not a -- well , it's not a base cost, and so
anything over and above that is just an amount selected by the
Company?
Well , as I explained in my direct and my rebuttal
testimony, typically what we've proposed in this case and then
proposed in the past, that the minimum charge for III be
increased by the amount of the margin increase to 101 so that
we don't change the break-even level.To include gas costs in
that minimum is something different than we do now , and some of
the customers on Schedule III don't necessarily consistently
use over 200 therms a month.So if they use, say, 150 one
month, all of a sudden their minimum would increase
substantially, and I'm guessing we would get some customer
complaints , some significant customer complaints, because we'
also included that gas cost in the minimum charge.
MR. WOODBURY:Thank you, Mr. Cha i rman .Staff
830
HEDRICK COURT REPORTING
O. BOX 578 , BOISE , ID 83701
HIRSCHKORN (X)
Avista
has no further questions.
COMMISSIONER KJELLANDER:Thank you,
Mr. Woodbury.
Let's move to Mr. Purdy.
Oh.MR . PURDY:m sorry.No.
COMMISSIONER KJELLANDER:Okay.Mr. Cox.
MR . COX:Yes, I have some.
COMMISSIONER KJELLANDER:Okay.
CROSS - EXAMINATION
BY MR. COX:
Mr. Hirschkorn , I want to direct some questions
to you that relate to your rebuttal testimony and Mr. Yanke 1 , s
testimony.If I can , I would like to summarize your rebuttal
testimony with respect to Mr. Yankel's position.
Basically, as I understand it, you agree that
Schedule 25 demand charges should be increased further than
what the Company's proposed , but you think that you've gone far
enough?
In this case , that's exactly what I said in my
rebuttal testimony.
Okay.And you seem to gauge your sufficient
movement by the fact that the Coeur would be given a 10.
percent increase while the overall increase to Schedule
831
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HIRSCHKORN (X)
Avista
is 13.Is that- correct?
What I said, given not just on the increase that
resul ts for Coeur, but looking at the increase in the demand
charges compared to the overall increase for the schedule as
well , I think I stated that those charges increase over
20 percent.
Okay.And do you have your Exhibi t 30 handy?
Yes, I do.
And I believe on that exhibit, you have listed a
change for each Schedule 25 customer, is that correct, on
page 4 of
- -
page 4 of five?
Yes.
Please explain to me how you can look at
Exhibi t 30 , page 4 , and discern that this resul ted in a spread
that is appropriate.
m sorry, I didn't hear the last part of your
question.
Oh.Could you please take a look at Exhibit
and explain to me how this resul t in rate spread you consider
is appropriate?
First of all, is this an appropriate spread?
Gi ven what we've proposed in the case and our
goals as far as overall rate design for Schedule 25, as well as
the other schedules, this is the resul Smaller customers on
this schedule, both in terms of usage and lower load factors,
832
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HIRSCHKORN (X)
Avista
the increasing resul ts for those customers is higher , so that'
generally summary.
I don't think I answered your question.
Well , I'm just trying to
- -
I thought maybe
you were trying to explain to us how you came up wi th why you
believe this spread is appropriate.
As I said , our goals were to bridge
- -
we had a
couple of goals.One was to bridge the gap between
Schedule 21 , large customers served under Schedule 21 , and
smaller customers under Schedule 25, and we proposed a
two-block schedule - - or , two-block rate structure for both
schedules.We also propose an increase in demand charges that
we fel t was appropriate given the overall increase for the
schedule in this case, and this is the resul Generally,
lower load factor customers, lower usage customers, get a
higher percentage lncrease.
Okay.And i s there kind of a ratio you shoot for
when you'between the high and the low?
No.looked the results and tested
different results, and we looked at making further movement in
both primarily in terms of the block structure in getting
Schedule 21 and Schedule 25 closer , but we fel t that the spread
was big enough in this case between lowest and highest.
So there's not a two-to-one ratio or five-to-one
or anything ike that?
833
HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
HIRSCHKORN (X)
Avista
No.
Okay.Okay, please look at revised Exhibi
No. 20.
Page 9 of nine that was just handed out?
Yes , the revised exhibi t, page 9, I'm sorry.And
the reason I was asking about any kind of ratios is I look at
this exhibit and it looks to me like you have a high of 12.
and then you have a low of 2.6 on your revised exhibi t , okay,
and that is certainly more than two to one looks like, what,
five to one?
Yes, about five to one.
Okay.And so if the Commission were to look at
that , that kind of a ratio, at least from your testimony, this
exhibi t would be acceptable?
Given the circumstances in this case and the
current situation between large Schedule 21 customers and small
25 customers, that is what we're proposing in this case.
Okay.So if the Commission were to agree to a
schedule here that had a five-to-one ratio, would you accept
would be reasonable in this case?
For which schedule?Schedule 25?
For Schedule 25 , yes.
I would have to accept whatever the Commission
ordered.I guess we always have the opportunity for
reconsideration.
834
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
HIRSCHKORN (X)
Avista
Given the circumstances, we looked at those
percentages and felt for the Schedule 25 customers, given the
magni tude of the increase, that that was a reasonable
differential from lowest to highest.
But given the fact that you agreed with five to
one in the revised exhibit , my only question is would you
consider that to be reasonable for the Commission as the same
thing for Schedule 25?
If that's what the Commission determined and its
rationale was, we fel t, was reasonable.
Thank you.That's all the questions I have.
COMMISSIONER KJELLANDER:Thank you , Mr. Cox.
Mr. Ward.
MR . WARD:Just a couple.
CROSS - EXAMINATION
BY MR. WARD:
Mr. Hirschkorn, looking at your rebuttal
testimony, it seems to me you're on the verge of saying you
agree that Potlatch should be its
- -
on a separate schedule of
its own but never quite say that.What was your intention in
that rebuttal testimony?
After
- -
in my rebuttal testimony, we revised
rates for Schedule 25, as well as a slight change to
835
HEDRICK COURT REPORTING
O. BOX 578, BOISE, ID 83701
HIRSCHKORN (X)
Avista
Schedule 1 , residential one.
After doing some creative things to the rates on
Schedule 25 to retain Potlatch on the schedule yet not change
our original revenue increase, that's when I realized that at
some point , it may no longer be reasonable to keep Potlatch
Schedule 25.
When is the appropriate time?Now is probably as
good as any, given the exercise that I went through in revising
those rates and at the same time trying to keep Potlatch on
Schedule 25.I had to change totallyIt was very difficult.
the first block of rates in order to do that.So this case is
probably as good a time as any.
Okay.The other question I wanted to ask you had
to deal with Dr. Peseau' s rebuttal testimony.Did you read
that testimony?
Yes, I did.
In that testimony, he proposed that in this case
as an alternative proposal that the Commission move 50 percent
to cost of service uni ty but
- -
as you propose - - but wi th the
additional proposal that if there's no rate case in two years,
there should be an addi t ional 50 percent.Wha t 's your comment
on that?
- - well , I did address that issue in my
rebuttal testimony, and I
- -
my testimony basically said
don't believe it's reasonable at this time, given all the
836
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
HIRSCHKORN (X)
Avista
issues before the Commission in this case, including a couple
of large cost of service issues , to establish a schedule to
move toward uni ty You make additional steps toward unity, and
that that was basically my testimony.
In order to do that, too , a substantial increase
would be required for residential customers, a substantial
decrease for commercial customers.And I just think that
may not be appropriate to set a schedule.The Commission may
feel otherwise.
And, of course, the reason why further movement
to uni ty would produce substantial increases for those classes
of customers is that other classes of customers
- -
the most
noteworthy, particularly Potlatch
- -
are substantially
overpaYlng on a cost of service basis?
Our cost of service study shows that Potlatch
over or higher than the overall rate of return. Commercial
customers are even further away from uni ty.
Okay.I can't remember a case of thi s sort ever
occurrlng before this Commission, but there's no reason in law
is there, why a customer cannot propose a further rate
adjustment down the road?
No.
Okay.
MR. WARD:That's all I have.
COMMISSIONER KJELLANDER:Thank you, Mr. Ward.
837
HEDRICK COURT REPORTINGP. O. BOX 578, BOISE, ID 83701
HIRSCHKORN (X)
Avista
Are there any questions from members of the
Commission?
COMMISSIONER SMITH:I have one.
COMMISSIONER KJELLANDER:, you have one.
Commissioner Smi th.
EXAMINATION
BY COMMISSIONER SMITH:
Looking at Exhibi t 20, page 9 of nine, and those
percentages that you just discussed with Mr. Cox --
Yes.
- -
i sn 't it the case that when you change the
flat monthly fee, a customer charge, or lncrease the demand
charge , those who use less will always see a higher percentage
increase because you're spreading that over
That more goes toward - - to load factor
Okay.
- -
if you're speaking of the demand charges
specifically.That's more load factor dependent, which I think
Mr. Cox was speaking both in terms of load factor and the level
of energy usage.And so in this case , specifically wi th regard
to thi s exhibi t , that it is based on usage.
So if you use less , then your percents, generally
when you divide it, the percentage is bigger?
838
HEDRICK COURT REPORTING
O. BOX 578, BOISE, ID 83701
HIRSCHKORN (Com)
Avista
Yes , yes, to the extent you incur fixed charges,
no ques.tion.
COMMISSIONER SMITH:Thank you.
COMMI S S IONER KJELLANDER:Any redirect?
MR . MEYER:No redirect.
COMMISSIONER KJELLANDER:I want to say thank you
for your testimony and your presence here today.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:All right.Does that
conclude Avista's witness list?
MR . MEYER:It does, yes.
COMMISSIONER KJELLANDER:Okay.And we are,
guess, ready now for Staff.Probably a good time at this point
in the day to at least find out where we think we are with
regards to our schedule, and whether or not we should move
forward and call some witnesses with regard to the Staff'
case.
MR. WOODBURY:There are two Staff witnesses that
we would like to put on , we feel they will be rather short for
purposes of cross:Lynn Anderson and Marilyn Parker.
COMMISSIONER KJELLANDER:Let's move forward.
MS. NORDSTROM:The Staff would call
Lynn Anderson as its first witness.
MR. WOODBURY:I'll get him.
839
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HIRSCHKORN (Com)
Avista
LYNN ANDERSON
produced as a witness at the instance of the Staff , being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MS. NORDSTROM:
Please state your name and spell your last name
for the record.
Lynn Anderson , A-
By whom are you employed and in what capacity?
The Idaho Public Utilities Commission as a Staff
economist.
Are you the same Lynn Anderson that filed direct
testimony on June 21, 2004 , and prepared Exhibit Nos. 132
through 134?
Yes.
Do you have any corrections or changes to your
testimony or exhibits?
No.
If I were to ask you the questions set out in
your prefiled testimony, would your answers be the same
today?
Yes.
MS. NORDS TROM :I would move that the prefiled
840
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
ANDERSON (Di)Staff
direct testimony of Lynn Anderson be spread on the record as
read , and Exhibits 132 through 134 be marked for
identification.
COMMI SS lONER KJELLANDER:Wi thout obj ection
we'll spread the testimony across the record as if read, and
admit the noted exhibits as referenced by Ms. Nordstrom.
(The following prefiled direct testimony
of Mr. Anderson is spread upon the record.
841
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
ANDERSON (Di)
Staff
Please state your name and business address for
the record.
My name is Lynn Anderson and my business
address is 472 West Washington Street, Boise, Idaho.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
Commission as a Staff economist.
What are your duties with the Commission?
My duties include evaluating electricity,
natural gas, water and telephone utility applications and
customer peti tions, as well as conducting generic
investigations, the resul ts of which are used to make
recommendations to the Commission.
Would you please outline your academic and
professional background?
I have a Bachelor of Science degree in
government and a Bachelor of Arts degree in sociology,
both from Idaho State Uni versi ty where I also studied
economics and archi tecture.I studied engineering
Northwestern Uni versi ty and Brigham Young Uni versi ty and
public administration and quanti tati ve analysis at Boise
State Uni versi ty.I have attended many training seminars
and conferences regarding utility regulation , operations
forecasting, and marketing.
I began my employment with the Commission in
CASE NOS. AVU-E-04-1/AVU-G-04-06/21/04 ANDERSON (Di)
STAFF
842
17
1980 as a utility rate analyst.In 1983 I was appointed
to the position of telecommunications section supervisor
and in 1992 I was appointed to my present position as an
economist.In that capacity I have been a Staff
representative to the Northwest Energy Eff iciency
Alliance, Avista s External Energy Efficiency Board and
Idaho Power s Energy Efficiency Advisory Group.Since
1999 I have served the Commission as a policy strategist
for electricity and telecommunications issues on an as-
needed basis.
From 1975 to 1980 I was employed by the Idaho
Transportation Department where I performed benefit/cost
analyses of highway safety improvements and other
statistical analyses.
What is the purpose of your testimony?
The purpose of my testimony is to make
recommendations regarding Avista s request that its
electricity and gas demand side management (DSM or energy
efficiency) expenditures be deemed reasonable and
prudent.I will also present changes to Avista ' s
electricity DSM funding level that the Company proposed
at the May 19, 2004 meeting of its External Energy
Efficiency (EEE) Advisory Board and that it reiterated to
the Staff on June 2, 2004.Finally I will comment on
Avista s proposed advanced meter reading (AMR) proposal.
CASE NOS. AVU-04-1/AVU-04-
06/21/04
ANDERSON (Di)
STAFF
843
11
Demand Side Management/Energy Efficiency
Please describe the energy efficiency
expenditures that the Company has requested be deemed
reasonable and prudent by the Commission.
The Company is asking that its electricity DSM
expenditures from January 1, 1999 through October 31,
2003, and its gas DSM expenditures from March 13, 1995
through October 31, 2003 be found to have been prudently
incurred.(Company witness Hirschkorn s pre-filed direct
testimony has a slight error , showing December 31, 2003
as the end date.As noted by Avista witness Brian
Hirschkorn on page 44 of his pre-filed testimony, the
Commission previously found that the Company
electricity DSM expenditures were prudently incurred
through December 31 , 1998.
How does Avista collect revenues that finance
its energy efficiency programs?
Avista collects revenues for its DSM programs
from surcharges described in its tariff Schedule 91 for
electricity DSM and Schedule 191 for its gas DSM.
Currently, the electrici ty surcharges amount to 1.95% of
base revenue and the gas surcharges amount to 0.5% of
base revenues.For 2002 these surcharges collected about
$2.7 million and $279,000 per year for electricity and
natural gas DSM, respectively.
CASE NOS. AVU-E- 04 -l/AVU-G- 04-06/21/04 ANDERSON (Di)
STAFF844
Do you believe Avista has been reasonable and
prudent in managing its DSM revenues?
Through my participation in Avista ' s EEEYes.
Advisory Board and the Northwest Energy Efficiency
All iance (NEEA) Board and various commi t tees, I have
observed Avista s conscientious approach to obtaining
energy efficiency for its customers.I have al
reviewed Avista s detailed DSM cost-effectiveness
reports.As stated by Mr. Hirschkorn on page 45 of his
pre-filed, direct testimony, Avista estimates that its
average, historical, 15-year levelized utility cost of
electricity savings is 1. 4~ per kilowatt hour (kWh)
Avista s similarly calculated utility cost of gas savlngs
is 2 5~ per thermo (Hirschkorn erroneously states that
Avista s utility cost of gas savings is 14 ~per therm.
Both the electrici ty and gas costs of energy saved are
well below Avista ' s avoided costs.Al though there may be
room for some minor disagreements among reasonable
evaluators about Avista s DSM cost-effectiveness
calculations, Avista ' s assumptions and calculations are
easily wi thin a range of reasonableness.
What changes did Avista propose to its
electrici ty DSM funding level at its May 19 EEE Board
meeting and again when it met with Staff on June 2, 2004?
Avista proposed reducing its electricity DSM
CASE NOS. AVU-04-1/AVU-O4-06/21/04 ANDERSON (Di)
STAFF
845
surcharge from the current 1.95% to about 1.25% of base
revenues.(See page 10 of Exhibi t No. 132.This
equates to nearly a $1 million dollar reduction.Avista
also proposed that the surcharge be set on a cents-per-
kWh basis rather than on a percent of revenue basis as
currently done.
Does Staff agree wi th Avista ' s proposed
reduction in its DSM tariff rider?
Yes, Staff is willing to accept the reduction
In total DSM revenue collections contingent upon the
following two condi tions
1) Assurance by Avista that the reduction in DSM
revenues will not affect the Company s pursuit of cost-
effective energy efficiency measures, regardless of
whether such measures resul t in Avista DSM fund balance
being negative; and,
2) An increase in Avista ' s contribution to the Low
Income Weatherization (LIWA) program to a level
determined to be reasonable by the Commission in this
rate case.
Has Avista indicated agreement to those two
condi tions?
Yes.Jon Powell, Avista ' s DSM manager, assured
its EEE Advi sory Board on May 19 that the proposed
reduct ion in DSM tari f f rider revenue wi 11 not reduce the
CASE NOS. AVU-E- 04 -l/AVU-G- 04-
06/21/04
ANDERSON (Di)
STAFF
846
availability of cost-effective energy efficiency
incentives and assistance for its customers.(See
pages 2 and 4 of Exhibit No. 132.Furthermore, it is my
understanding that Avista will request that its DSM
surcharges be increased if its surcharge balance becomes
too negative for too long.Mr. Powell restated these
assurances to me after other Company representatives
rei terated the proposal at its meeting wi th the Staff on
June 2.Mr. Powell also suggested that Avista is not
opposed to a reasonable increase to its funding of LIWA.
What have been the historical levels of
Avista s electrici ty DSM surcharges?
The DSM surcharge was initiated at 1.55% in
1995, decreased slightly to 1.503% in 1996, decreased
significantly to 1.0% in 1999 due to a large balance
being carried, and was increased to the current 1.95% in
June of 2001 shortly after Avista had begun rapidly
accelerating its DSM efforts in response to the western
states energy crisis.
What is the history of Avista ' s electricity DSM
revenue collections and expenses?
The table in Exhibit No. 133 shows Avista ' s
reported annual DSM revenues, expenses and fund balance.
What general programs does Avista ' s electrici ty
DSM surcharge fund?
CASE NOS. AVU-04-1/AVU-O4-06/21/04 ANDERSON (Di)
STAFF
847
Avista s electrici ty DSM surcharge funds all of
the Company s own electricity DSM programs, about
$250,000 for the Company s Idaho share of the Northwest
Energy Efficiency Alliance (NEEA) market transformation
efforts, and a small portion of the company s maximum
allocation of $210,000 annually for the Lewiston
Community Action Partnership (CAP) various low-income
programs, including weatherization.
Avista says that the $210,000 allocated to the
CAP is funded from a combination of Bonneville Power
Administration s Conservation and Renewable Discount (BPA
C&RD) funds and its own electricity and gas DSM funds.
Avista has also indicated that the CAP does not always
spend all of the $210,000 maximum allocation.
Given Avista s claim that its electricity DSM
programs have bought energy efficiency at an average
levelized utility cost of 1. 4 ~ per kWh, why is Staff
willing to accept Avista ' s proposed reduction in its DSM
surcharge?
As previously described, Avista has assured
Staff that the level of its DSM funding will not limi t
its pursuit of cost-effective energy efficiency measures.
Avista s DSM surcharge historically has been increased
and decreased in response to changing needs.Avista has
been willing to ramp up its DSM efforts when it is cost-
CASE NOS. AVU-04-1/AVU-04-
06/21/04
ANDERSON (Di)
STAFF
848
effective to do so regardless of its DSM balance.Staf f
believes that it is important for Avista to maintain
control of its DSM programs and funding levels especially
given its historically good stewardship of these programs
and funds.The reduction at this time better reflects
anticipated DSM expenditures and also provides some rate
relief as base rates will likely increase as a resul t of
this rate case.And, in comparison to the just completed
Idaho Power rate case, Avista ' s proposed DSM funding
level does not seem unreasonable.
How do Idaho Power s DSM funding levels compare
to Avista ' s proposal?
Idaho Power s DSM surcharge equates to about
5% of base revenues and collects about $2.7 million
annually, but that Company funds NEEA ($1.2 million for
Idaho) and LIWA ($1.2 million going forward) and some
its DSM general administrative costs ($0.3 million) from
other sources.In total , Idaho Power will likely spend
about $5.4 million annually for DSM or about 1.1% of
total base revenues.Even wi th Avista ' s proposed
reduction to 1.25%, its DSM revenue as a percent of base
revenues would still be higher than Idaho Power
Do you have a specific recommendation for
Avista s level of LIWA funding?
No.I am aware that Idaho Power s recently
CASE NOS. AVU-04-1/AVU-04-06/21/04 849
ANDERSON (Di)
STAFF
ordered increase to $1.2 million for LIWA for each of the
next three years (exclusive of any BPA C&RD funding)
equates to about $3 per Idaho Power customer ($1.
million/400,OOO total Idaho customers)
Are you suggesting that Avista increase its
electricity DSM funding for LIWA to $320,000 per year?
I am simply stating that amount is aboutNo.
equivalent, on a per customer basis, to the $1.2 million
recently approved by the Commission for Idaho Power.
In comparing northern and southern Idaho LIWA
funding levels, it should be noted that Avista also
contributes to LIWA from its gas DSM, whereas
Intermountain Gas does not contribute to LIWA.And, as
previously mentioned , the CAP apparently does not always
spend all of the maximum $210 000 that Avista authorizes
it to spend for weatherization and other programs.
I anticipate that the Communi ty Action
Partnership Association of Idaho (CAPAI) will recommend
and support an appropriate funding level based upon a
needs assessment specific to Avista ' s service area and
the ability of the CAP office based in Lewiston and its
satellite offices in Grangeville, Moscow, Coeur d' Alene
and Sandpoint to efficiently and prudently increase their
weatherization efforts for low-income households.
You mentioned that Avista also proposed that
CASE NOS. AVU-04-1/AVU-04-106/21/04 ANDERSON (Di)
STAFF
850
its DSM surcharge be set as a cents-per-kilowatt-hour
(kWh) rate rather than being set as a percent of base
revenue s Does the Staff support this change?
The current DSM surcharge rates, al thoughYes.
set as a uniform percent of base revenue, are also shown
in the tariff as varlOUS cents per kWh by class of
servlce.I believe it would be simpler for the tariff to
list just the cents per kWh.Doing so would al
eliminate the need to change the tariff language
coincident wi th general rate changes.Exhibi t No. 134
shows the current DSM surcharges and the proportional DSM
surcharges that result from a $1 million reduction.
Are you recommending or suggesting any changes
to Avista s natural gas DSM surcharges, programs or
contribution to CAP for LIWA?
No.
Advanced Meter Reading (AMR)
Briefly describe Avista s advanced meter
reading (AMR) proposal.
As described in more detail in Company wi tness
David Holmes ' pre-filed, direct testimony, Avista is
proposing to install advanced meter reading (AMR)
capability over a four-year period for all of its
electrici ty and gas customers in Idaho.Mr. Holmes says
AMR will result in reduced meter reading operating
CASE NOS. AVU-04-1/AVU-G-04-06/21/04 ANDERSON (Di)
STAFF
851
expenses, will provide other immediate system benefits
and will provide much of the infrastructure necessary for
critical peak and/or time-of-use (TOU) pricing in the
future.
Does Avista believe that the immediate savlngs
in operating expenses after completion of the AMR proj ect
will completely offset the capital costs?
Not qui te Mr. Holmes estimates the net gas
savlngs to be $63,000 per year or 0.12% of $51 million in
revenue (about a 7~ decrease to a $57 customer bill), but
that the electrici ty net cost would be an increase
$189,000 or 0.13% of $146 million in revenue (about a
lncrease to a $ 5 0 cus tomer bi 11) Mr. Holmes concludes
the estimated very small net revenue requirement increase
is more than offset by additional system benefits that
have not been monetarily quantified.
Does Staff support Avista ' s AMR proposal
principle?
We believe one of the most importantYes.
future system benefits of AMR will be the capability to
implement critical peak TOU pricing.Staff anticipates
that critical peak TOU pricing will become cost-effective
for Avista by about the time the AMR system is completed
and that the addi tional components necessary for such
pricing system should begin to be installed at that time.
CASE NOS. AVU-04-1/AVU-04-06/21/04 ANDERSON (Di)
STAFF
852
In other words , Staff believes it reasonable for Avista
to consider installing just the AMR facilities without
specific TOU pricing facilities at this time.
Is it Staff's position that Avista ' s proposal
should be deemed a reasonable and prudent capi tal
investment?
No, Staff does not have sufficient information
to make a final judgment and Avista is not requesting
such judgment from the Commission in this case.
What is Avista requesting of the Commission
regarding its four-year AMR proposal?
As explained by Avista wi tness Don Falkner on
page 46 of his pre-filed direct testimony, Avista wants
to be able to "treat AMR investment costs as a unlque
construction proj ect. As such, Avista proposes that its
AMR investment would be capitalized as construction work
In progress until after the entire metering proj ect
completed.At that time depreciation would begin and the
investment could be included in rate base should the
Company file an Application to do so.
Does the Staff agree with Avista s proposed
deferred accounting treatment for its four-year AMR
implementation?
Staff believes that Avista will begin to
benefit from automated meter reading before completion of
CASE NOS. AVU-E- 04 -l/AVU-G- 04-06/21/04 ANDERSON (Di)
STAFF
853
the entire four-year AMR installation.Howeve r,
promote Avista ' s implementation of AMR at this time,
Staff is not opposed to the deferred accounting treatment
proposed by Mr. Faulkner.
Does this complete your direct testimony?
Yes, it does.
CASE NOS. AVU-04-1/AVU-04-06/21/04 ANDERSON (Di)
STAFF
854
(The following proceedings were had in
open hearing.
(Staff Exhibit Nos. 132 through 134
having been premarked for identification , were admitted into
evidence.
MS. NORDSTROM:I tender this wi tness for
cross-examination.
COMMISSIONER KJELLANDER:Thank you.Let's start
wi th Mr. Meyer.
MR . MEYER:Just have four or five quick
questions.
CROSS - EXAMINATION
BY MR. MEYER:
Mr. Anderson , you've proposed a reduct ion in the
DSM tariff rider rate from 1. 95 percent of revenue to
approximately 1.25 percent of revenue.Is that correct?
Pretty much.I agreed to the Company's proposal.
Was the 1.95 percent rate established at a time
when the Company was carrying a negative tariff rider balance
resulting from its efforts to significantly increase DSM
resource acquisition in response to the energy crisis?
Yes.
Is it your understanding that the Company
855
HEDRI CK COURT REPORTING
O. BOX 578 , BOISE , ID 83701
ANDERSON (X)Staff
currently managing a positive electric DSM balance?
Yes, it just recently turned positive, I believe.
I assume , therefore, that you agree that a tariff
rider equal to the 1.25 percent of current base rates
suff icient to meet forecast and funding needs in the subsequent
year?
That's my understanding, that that's the
Company's projection; and it's also my understanding that if it
turns out to be insufficient, the Company will go ahead and
obtain the DSM that is cost-effective to obtain regardless.
So I assume you find that the Company
- -
find the
Company's proposal to be acceptable?
Yes.
MR . MEYER:Thank you.That's all I have.
COMMISSIONER KJELLANDER:Thank you.
Let's move to Mr. Purdy.
MR . PURDY:Yes, thank you.
CROSS -EXAMINATION
BY MR. PURDY:
Mr. Anderson , you have identified in your direct
testimony a funding level for the low income weatherization
program for Avista of $308 000 as a possible funding level.
that a fair statement?
856
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
ANDERSON (X)
Staf f
I think my testimony said 320,000.
Oh, 32 0 ., sorry.
Just to put this in the proper context, would you
characterize that as a rigid recommendation or more of just a
point of reference?
It was strictly a point of reference.It was not
a recommendation at all.
All right.And you're, of course , aware that the
Company and Community Action have reached an agreement to fund
the program at a level of 350,000 annually.Is that right?
Yes.
And in your opinion, is that, both in the context
of the program itself and from the point of view of ratepayers
is that a reasonable amount?
I think it's easily wi thin a reasonable range.
All right.You don't have any reason to bel ieve,
do you , that the Community Action Agencies will not be capable
of fully investing that amount of money in weatherization
measures?
I don't have any knowledge to that.
assumption is that since the CAP agency and Avista agreed to
this, that the CAP will be able to cost-effectively spend that
money.
Okay.So is it fair to say that you find the
agreement that CAP and Avista have reached to be, on the whole,
857
HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
ANDERSON (X)
Staff
reasonable?
Yes.
Now , I understand that you believe that
al though she has not testified yet, because you're leaving the
state apparently tomorrow , I have to ask you today
- -
you
believe that Ms. Ottens' testimony contains either a
calculational error or perhaps an assumption that', in your
opinion , not proper.Is that right?
Yes.
Could you explain what that is?
Ms. Ottens goes into some detail about number of
customers and households in the
- -
purportedly to be in the
Avista service area that isn't qui te accurate, and what she did
was included the customers or the households that are actually
customers of the various electric cooperatives and
municipali ties in Northern Idaho.So her numbers are
overstated by, I'm guessing, real close to 30 percent.
And have you made any calculation as to - - well
let me strike that.
That affects the calculated backlog of homes that
need weatherization.Correct?
Yes.
Have you made any attempt to calculate what the
backlog would be or if there still would be a backlog
Ms. Ottens' calculations had been done properly?
858
HEDRICK COURT REPORTINGP. O. BOX 578, BOISE , ID 83701
ANDERSON (X)Staff
Yes, I did a rough estimate.I don't have all
the pieces to that puzzle, but instead of the 70-year backlog
that she states, I estimated it would be somewhere between
40- and 50-year backlog.
Okay.So is it fair to say then that you agree
that there's still a considerable discrepancy between the need
for weatherization for low income people and the availability
of resources?
Yes.
All right.Finally, I just want to ask you with
respect to Avista' s low income weatherization program , do you
see that program as having system-wide benefits?
Yes.
And what would those be?
Obviously, it would help reduce nonpayment
amounts, at least I would assume it would.
And any DSM program that reduces electrici
consumption , and especially those that coincide with peak
times , reduces the system overall costs.
Those are two of the biggies.
All right.
MR . PURDY:That's all I have.Thank you.
COMMISSIONER KJELLANDER:Thank you , Mr. Purdy.
Le t 's move to Mr. Cox.
MR . COX:Chairman Kj ellander , I have no
859
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
ANDERSON (X)Staff
questions for Mr. Anderson.
COMMISSIONER KJELLANDER:And, Mr. Ward.
MR . WARD:No questions, thank you.
COMM IS S IONER KJELLANDER:And, let's see, any
questions from members of the Commission?Commissioner Hansen.
EXAMINATION
BY COMMISSIONER HANSEN:
Just one question, Mr. Anderson:
What's your understanding of the weatherization
program?Is that mainly just for the low income customer?
That's specifically what I was discussing with
Mr. Purdy was the low income weatherization.It is my
understanding that Avista will also do weatherization for
households that are not low income using different criteria.
Okay.But it would be part of this fund , using
part of this fund, or is it?
Part of the overall DSM fund, yes.
Thank you.Just wanted to clarify.
COMMISSIONER KJELLANDER:Ready now f or any
redirect.
MS. NORDSTROM:Staff has none.
COMMISSIONER KJELLANDER:Thank you.
And thank you , Mr. Anderson.
860
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
ANDERSON (Com)
Staf f
(The wi tness left the stand.
MS. NORDSTROM:The Staff would call
Marilyn Parker as its next witness.
MARILYN PARKER
produced as a witness at the instance of the Staff , being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MS. NORDSTROM:
Good afternoon.
Good afternoon.
Please state your name and spell your last name
for the record.
My name is Marilyn Parker , P-A-R-
By whom are you employed and in what capaci ty?
The Idaho State - - excuse me
- -
the Idaho Public
Utilities Commission , and I am a utilities compliance
investigator.
Are you the same Marilyn Parker that filed direct
testimony on June 21, 2004 , and prepared Exhibit Nos. 149
through 152?
Yes.
Do you have any corrections or changes to your
861
HEDRICK COURT REPORTINGP. O. BOX 578 , BOISE , ID 83701
PARKER (Di)Staff
testimony or exhibits?
Yes , I do.
On page 16 , lines 23 , 24, and 25, we want to add
after "Washington " we want to add the word "and" and delete
and California.In other words, that should read:The
numbers cited above include abandoned calls from Avista' s four
call centers located in Idaho , Washington , and Oregon.
Do you have any other correct ions you'd ike to
make?
No.
If I were to ask you the questions set out in
your prefiled testimony, would your answers be the same
today?
Yes.Yes.
MS. NORDSTROM:I would move that the prefiled
direct testimony of Marilyn Parker be spread upon the record
if read , and Exhibits 149 through 152 be marked for
identification.
COMMISSIONER KJELLANDER:Wi thout obj ection
we'll spread the testimony across the record as if read , and
admit Exhibits 149 through 152.
(The following prefiled direct testimony
of Ms. Parker is spread upon the record.
862
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
PARKER (Di)
Staff
Please state your name and address for the
record.
My name is Marilyn Parker.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 Utilities Compliance Investigator.
accepted that posi tion wi th the Consumer Assistance Staff
in November 2002.
What is your educational and professional
background?
Prior to my employment with the Idaho Public
Utilities Commission, I had twenty years experience
working in private industry for three different utility
companles.In 1973 and 1974 , I was employed by Central
Alaska Utilities , a water company in Anchorage , Alaska, as
the Executive Secretary to the President of the company.
From 1982 until 1987 , I was employed as a Customer Service
Representative for Idaho Power Company in Salmon, Idaho.
From February 1989 until November 2002 , I was employed by
Intermountain Gas Company in Customer Services.Dur i ng
last six years at Intermountain Gas, I supervised
representatives at the Customer Service Center s Emergency
Answering Service.
I received a Bachelor of Arts Degree in
CASE NO. AVU-04-1/AVU-04-06/21/04 (Di)PARKER, M.
STAFF
863
Management and Organizational Leadership from George Fox
University in Boise, Idaho in June of 2002.
In June 2003, I attended the National Low
Income Energy Consortium Annual Conference in Sacramento
California.
Have you previously testified before the
Commission?
Yes, I have.
What is the purpose of your testimony in this
proceeding?
I will address issues related to: 1) customer
comments received by the Commission regarding this case;
2) proposed charges and rates; 3) Staff's proposed tariff
revisions; 4) low- income issues , payment options, and
special needs customers; 5) Company operations wi th regard
to customer service; 6) customer relations, and 7) out-of-
cycle meter readings.
Please summarize Staff's recommendations to
the Commission as discussed in your testimony.
Staff recommends that the Company be commended
for its Customer Assistance Referral Program (CARES) and
its "We Personally Care " program.
Staff also recommends that:
1 )the Company s proposed charges for
reconnection of seasonal gas customers
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 (Di)PARKER,
STAFF
864
2 )
3 )
4 )
5 )
6 )
CUSTOMER COMMENTS
and after hours connection charges for
both gas and electric customers be
approved.
the provision in the tariffs that allows
an additional $4.00 charge to connect a
second meter at the same location be
eliminated.
the Company resolve its computer
programmlng limitation issues whereby a
customer currently cannot receive the
benefits of the Winter Payment Plan
the customer has declared eligibility for
the Moratorium.
the Company improve communication wi
customers about the Winter Payment Plan
and the Moratorium.
the Company answer 80% of call s wi thin
seconds by January of 2005.
the Company significantly reduce the
number of abandoned call s per month.
Have you reviewed the written customer
comments that have been received by the Commission
regarding this case?
Yes.As of June 18, 2004 the Commission had
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER , M.
STAFF
(Di)
865
received comments well petitions from the
Sil ver Valley area with more than 500 signatures.
the comments,were from school districts,7. were from
business customers, with the remainder coming from
residential customers.All those commenting, as well
those that signed the peti tions , opposed any rate
lncreases
What are the concerns mentioned by customers?
The majority of those commenting (58%) said
that the economy in northern Idaho should be considered
before granting the Company any rate lncreases.The other
prlmary lssues commenters wanted the Commission to
consider were: the negative impacts higher rates have on
fixed income individual s, senior ci t i zens, and low income
customers; the concern that the Company may not have done
all it could to promote efficiencies from within , thereby
eliminating the need for a rate increase; and opposition
to an increase in the fixed monthly residential customer
charge.
What are the economlC condi tions in northern
Idaho and how does northern Idaho compare to other areas
of the State?
In reviewing recent data from the United
States Census Bureau, some counties served by Avista in
northern Idaho are clearly experiencing economic distress.
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 (Di)PARKER,
STAFF
866
However , the counties in northern Idaho cannot be singled
out as the only area of the state with poor economic
condi tions.Several counties wi thin the state suffer from
the same slow growth, high poverty rates, high
unemployment, and low wages.
As a whole, northern Idaho has a higher number
of individuals over the age of 65 (14.8%) compared to the
state average of 11.3%.Some northern Idaho counties have
nearly 20% of the population over 65 years of age.This
fact probably accounts for the number of comments from
Avista customers on fixed incomes concerned about being
able to afford higher utility rates.Staff Exhibi t No.
149 compares some of the economic indicators for northern
Idaho counties wi th state average percentages.
PROPOSED CHARGES AND RATES
Many comments, to the Commission in this rate
case convey customers ' opposi tion to the proposed increase
in the fixed monthly residential customer charge to $5.
for both gas and electric service.What is the primary
reason customers ci ted for opposing increased customer
charge s?
About one-third of those commenting stated
opposition to increases in fixed residential customer
charges.Customers are generally against these types
charges because ~he perception is they have no control
CASE NO. AVU-E- 04 -1/AVU-G- 04-
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(Di)PARKER, M.
STAFF
867
over them by ralslng or lowering the thermostat.One
customer from Mullen , Idaho wrote in his comments that he
felt basic customer charges should be abolished
altogether.
Does Staff support the Company s proposal to
ralse the gas customer charge to $5.00 from $3.28 and the
electric customer charge to $5.00 from $4. OO?
Uniform customer charges are certainly eaSler
for customers to understand and for the Company to
administer.A customer wi th both gas and electric serVlce
sees both customer charges itemized on one bill.It is
difficult to explain to customers why the two customer
charges vary, especially when purported to recover the
same basic costs for meter reading and billing.Although
Staff supports uniform customer charges, Staff does not
support the Company s proposed increase to $5.00.Staff
witness Schunke has addressed the Staff recommendation for
specific customer charges in his testimony.
Does Staff support the Company s proposed
changes for the cost of seasonal reconnect fees for gas
customers?
The Company has proposed to lower itsYes.
seasonal reconnect fee to $24.00 from $31.00 provided
satisfactory arrangements for payment of all proper
charges have been made during the hours of 8: 00 a.
CASE NO. AVU-E- 04 -1/AVU-G- 04-06/21/04 868
(Di)PARKER , M.
STAFF
through 4: 00 p. m. Monday through Friday, except hol idays
They have also proposed to increase the charge for
seasonal reconnect from $46 to $48 after hours (4: 00 p.
through 7: 00 p. m. Monday through Friday, except hol idays)
Staff supports both changes because it aligns the fees for
gas charges with the electric charges for the same
servlce.
What changes have been proposed to the
Company s charges for new customer connections?
Avista proposes to increase its gas and
electric charges for connecting new customers after hours
to $48 from $32.Staff supports these changes.Avista is
attempting to keep charges in line with the costs to
provide the serVlce.
Are Avista ' s proposed reconnection fees and
after hours connection charges reasonable and comparable
with other Idaho utilities?
Staff Exhibit No. 150 provides aYes.
comparlson of Idaho regulated energy company reconnection
fees and service establishment fees.In Staff's opinion,
Avista s proposed charges ,are not out of line.
STAFF'S PROPOSED TARIFF REVISIONS
In your review of Avista ' s tariffs, did you
find any areas of concern?
Of concern to Staff is the provision inYes.
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 (Di)PARKER,
STAFF
869
14
Avista s tariffs that allows for an additional $4.
charge for each addi tional service being reconn~cted the
same time at a premlse.Staff proposes that references to
this charge be eliminated from Electric Tariff No. 28,
Sheet 70-
g .
, Rule 14.3, and Gas Tariff, No. 27 , Sheet
170-2, Rule 15.
Avista s usual practice is to disconnect only
the electric service of a customer wi th both electric and
gas serVlce.As a resul t, the Company rarely needs to
reconnect more than one meter at a premise, and the
Company seldom bills an additional $4.00.I f this
proVlslon were eliminated, the revenue impact would be
negligible.Avista collected a total of $96.00 from 24
customers in 2003 for reconnecting additional meters.
Staff questions whether this charge is necessary if it is
rarely assessed, produces little revenue, and is not
designed to influence customers ' behavior.
LOW INCOME ISSUES, PAYMENT OPTIONS, AND SPECIAL NEEDS
CUSTOMERS
Does Staff believe Avista is doing an adequate
job of supporting community-based agencies with funds for
the purpose of helping low income customers meet energy
needs?
In the past four years, AvistaYes.
shareholders have given 515, 000 to proj ect Share, all of
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 (Di)PARKER,
STAFF870
which went back to northern Idaho residents for the
purpose of helping low income individuals meet energy
needs.Since Project Share is a fuel-blind fund, some
monles went to other energy sources such as wood, propane,
or oil but , since the year 2000, Avista customers have
received $563,340 from Project Share.In the past four
heating seasons, 2 574 Avista customers have received an
average of $217 from Project Share to help with heating
costs.
What options do Avista customers have if they
are not able to pay their bills in full?
Avista customers can make payment arrangements
by placing a call to the Company and asking for an
extension on a bill's due date or asking to set up a
mutually satisfactory payment plan.Avista also offers a
program called ~Comfort Level Billing U that allows
customers to pay an average amount which is determined by
di vi ding the customer s proj ected yearly energy billings
by twelve months.These estimated average amounts are
reviewed every three months by Avista to determine if the
amount the customer was asked to pay each month has kept
in line with the proj ected usage.This proactive
procedure to review the Comfort Level Billing amount every
three months minimizes any surprises to customers that can
resul t from a miscalculated monthly average.
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04
(Di)PARKER,
STAFF
871
Customer service representatives are also
trained to determine if a customer might qualify to
recel ve help from the Low Income Home Energy Assistance
Program (LIHEAP)During the heating season of 2002-2003
Avista s Idaho customers received a total of $1 134 611.
Another program that can benefit some low-
income customers during the winter months is the Winter
Payment Plan.During the months of December, January and
February, customers who declare that they are unable to
pay their Avista utility bills in full and also have
children, elderly, or infirm in the household are exempt
from disconnection for nonpayment.When a customer makes
the declaration of his or her inability to pay the bill in
full , the utility is required to offer the Winter Payment
Plan to the customer.If the customer agrees to
participate in the Winter Payment Plan , the protection
from disconnection is extended to the shoulder months of
November and March.Customers who agree to participate in
th~. Winter Payment Plan must pay by the due date each
month an amount equal to one-half of what the customer
Comfort Level Billing would be.
Avista takes a customer s inability to pay one
step further with its Customer Assistance Referral and
Evaluation Service (CARES) program.The CARES program
discussed in greater length below.
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER,
STAFF
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872
Does Avista offer the Winter Payment Plan to
customers as required by the Utility Customer Relations
Rule 306.03?
Staff was concerned that no Avista customers
in Idaho participated in the Winter Payment Plan during
the last two heating seasons.One of the reasons may be
due to the Company not making available to its customers
any written material regarding protection from
disconnection during the winter months if there are
children , infirm, or elderly in the household and the
customer declares that he or she cannot pay the bill in
full.The Company stated that customer service
representatives are expected to apprise customers of the
program s availabili ty if the representative determines
the customer is eligible.CARES representatives work
closely with agencies to help identify those who are
eligible.
An addi tional problem is caused by the fact
that Avista has a computer programming limitation that
prohibi ts a customer from being placed on the Winter
Payment Plan and receive Moratorium protection from
disconnection simultaneously.The Company prefers to
classify an eligible customer as being a Moratorium
participant as opposed to placing the customer on the
Winter Payment Plan because the Moratorium classification
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER , M.
STAFF
(Di) 11
873
takes the customer out of the normal credi t and collection
work cycle and avoids the possibility that the customer
would be inadvertently turned off for nonpayment during
the winter months.
It is Staff's position that Avista needs
resolve its computer programming problem so that customers
can have the opportunity to participate in the Winter
Payment Plan while simul taneously receiving protection
from disconnection afforded by declaring eligibili ty for
the Moratorium.This will also allow the Company to be in
compliance with the Utility Customer Relations Rules
(UCRR) regarding both the Moratorium and Winter Payment
Plan.
In June of this year , a task force comprised
of representatives from Avista, Idaho Power Company,
Intermountain Gas Company, Utah Power , the IPUC, Communi
Action Partnership Association of Idaho (CAPAI) , Salvation
Army, and Idaho Community Action Network (ICAN) , met
determine the best practices for informing customers about
the Moratorium and the Winter Payment Plan.Before this
comlng heating season begins , the task force intends to
have a preferred methodology in place concerning how
utilities communicate with customers regarding the Winter
Payment Plan and the Moratorium.
Does Avista provide any additional serVlces
CASE NO. AVU-E- 04 -l/AVU-G- 04-
06/21/04 PARKER,
STAFF
(Di) 12
874
for customers that have special needs, such as, but not
limited to, those with severe disabilities or diminished
mental capaci ty?
Avista has a program entitled ~Customer
Assistance Referral and Evaluation Service " (CARES)For
Idaho customers, Avista employees two specially trained
customer service representatives , called CARES
representatives.These representatives specialize in
helping customers who are facing hardships obtain access
to a wide variety of programs , incl uding special payments
arrangements, and referral to agencies for the purpose of
assisting with more than energy bills.
CARES representatives in Idaho recently
organized an effort to collect personal care items for
low- income customers.Personal care items include items
that cannot be purchased wi th food stamps such as shampoo,
soap, toiletries, and/or paper products.Avista s program
is called ~We Personally Care.Last year , the Avista
CARES representatives not only organi zed the drive to
collect the personal care items , they also located
churches and other facilities such as the local Community
Action Agencies to store and assist in the distribution of
the collected items.More than 6, 000 pounds of personal
care items were collected and distributed last year.
Avista s worthwhile effort to reach out into the communi ty
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER , M.
STAFF
(Di) 13
875
deserves high marks for exceptional communi ty serVlce.
Avista Utilities also offers free consumer
credi t counsel ing through a partnership wi th Consumer
Credit Counseling Service of the Inland Empire.
COMPANY OPERATIONS WITH REGARD TO CUSTOMER SERVICE
How does Avista compare to other energy
companles regarding its abili ty to answer incoming
customer service calls in a timely manner?
According to the Edison Electric
Institute/American Gas Association (EEI/AGA) in its 2002
annual data source survey, the average service level (the
percentage of calls answered within a defined number of
seconds) among the 62 reporting utility companies was
73 .8% of calls answered in 32.3 seconds.Avista recently
set its internal service level goal at answering 70% of
incoming customer calls within 60 seconds, somewhat lower
than the average serVlce levels reported by the companies
In the EEI/AGA survey.
In the past four years, has the Company met
its goal?
In 2003, there were only three months in which
the Company was able to meet its goal.In 2002 , the
Company met its goal in nlne of the twelve months, and in
2001, the Company was able to meet its goal in three of
the months.The Company met its goal every month in 2000.
CASE NO. AVU-E- 04 -l/AVU-G- 04-
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STAFF
(Di) 14
876
Is Avista s serVlce level acceptable to Staff?
The fact that the Company has been unableNo.
to consistently meet its own lowered service level goal,
especially in recent months , is of concern to Staff.
Why did the Company choose to lower its
service level from 80% of calls answered wi thin 20 seconds
to answering 70% of calls within one minute?
The Company s customer service managers stated
that this lowered goal is not a permanent service level
goal.The plan is to return to a more desirable serVlce
level as soon as the full complement of Customer Service
Representatives (CSRs) is reached.One of the primary
reasons to temporarily change the service level standard a
few years ago was to raise employee morale within the call
center.Before the change , managers saw CSRs leaving at
the end of their shifts exhausted and frustrated because
they were not able to meet expected goals.Managers al so
were concerned that providing good customer serVlce was In
jeopardy.That is because CSRs sometimes cut calls short
in an effort to process as many phone calls per day
possible.By slightly lowering the standard , the CSRs
were glven permission to concentrate on the quality of the
phone call rather than just the quantity of phone calls
, answered per day.
Company call center managers state they are
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/0 PARKER , M.
STAFF
(Di) 15
877
still recoverlng from staffing issues related to past
financial constraints.They were unable to say
specifically when service levels would be raised to higher
levels.
Does Staff believe that Avista s step to
improve employee morale in the Call Center had an effect
on the customer service provided to customers?
Staff's opinion is that customer service was,
In fact , compromi sed.This is evident in the number of
calls that were abandoned in the past few years.In 2003,
the average number of abandoned calls per month was 3,292
in 2002 , an average of 2,998 calls were abandonedi in
2001, the number was 3,243 and in 2000, the average
number of call s abandoned was 2 , 148 per month.(Abandoned
telephone calls are the number of customers that reach the
Company, wai t on hold, and then hang up before speaking to
a live representative) The Company posted its worst year
for service levels in 2003 with an average of answering
only 62% of its calls within one minute.Because Avista ' s
call center operates in a virtual environment, the numbers
of abandoned calls cannot be isolated to identify the
number of calls abandoned specifically by Idaho customers.
The numbers cited above include abandoned calls from
Avista s four call centers located in Idaho, Washington
Oregon, and California.
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER,
STAFF
(Di) 16
878
The Company s overall abandoned call rate points to
an imbalance between customer accessibility and Company
responsl veness.When the Company is able to decrease its
customers ' wai ting-on-hold times, the number of abandoned
calls will decrease.
Regarding the Company s accessibility, did
Staff find any other areas of concern?
UCRR 304.02 requires utilities toYes.
diligently attempt to contact a customer in jeopardy of
losing service due to nonpayment at least 24 hours before
the proposed action.Avista s current practice is to
provide a recorded message to meet this requirement.If a
live person answers the telephone, a recorded message
left wi th whoever answers the telephone.
Of particular concern to Staff is that a
customer on the cusp of being disconnected may actually
answer the telephone only to hear a recorded message
telling him or her to ~call the Company for an important
message. "If the customer attempts to call back to the
Company he or she, in all likelihood, would be placed in
the telephone queue awaiting the next available
representative.This practice compounds the Company
problems with respect to service levels and abandoned
calls by directing calls into the Call Center.It also
represents a missed opportunity to negotiate a payment
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04
PARKER, M.
STAFF
(Di) 17
879
arrangement wi th the customer.
Staff does not believe this practice complies
wi th the spiri t of the rule.However , the Best Practices
Task Force plans to address the is~ue soon of how to
improve the disconnection notification process.Both
Avista and Staff will be participating in the discussions.
Does Staff have any recommendations regarding
Avista s serVlce levels goals?
Staff suggests that Avista return to Yes.
goal of answering 80% of calls within 30 seconds by
January of 2005.As an interim step, Avista can aim to
meet or exceed its current service level goal of answerlng
70% of calls within one minute.Staff also recommends
that the Company significantly reduce the number of
abandoned calls per month.
CUSTOMER RELATIONS
Please describe how many and what type
complaints and inquiries the Commission has received
regarding Avista.
The Commission received more complaints and
i nqu i r i e s in 2 0 Ol and 2 0 02 than in 2 0 0 0 and 2 0 03 .Higher
rates no doubt contributed to the increase in the number
of complaints during 2001 and 2002.During each of the
last four years , complaints fell into three maln
categories: credit and collections , billing, and rates and
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04
PARKER,
STAFF
(Di) 18
880
policies.Staff Exhibit No. 151 provides a breakdown of
the individual complaint and inquiry categories for each
of the past four years.
What did your analysis reveal regarding
complaints and inquiries received by the Commission in
2003?
The maj ori ty fell wi thin the category of
credi t and collections.Of the total number of complaints
and inquiries in 2003, 65% concerned credit and collection
lssues.Most of those were regarding a threat of or
actual disconnection of service due to nonpayment of an
account, a clear indication that some customers continue
to have difficul ty paying their energy bills.
How does Avista compare with other maJor Idaho
energy companles wi th regard to the number of complaints
and inquiries to the Commission?
In three of the last four years, Avista had
fewer complaints and inquiries per 1,000 customers than
Idaho Power Company.In each of the last four years
Avista had more complaints and inquiries per 1,000
customers than Intermountain Gas Company or Utah Power.
The number of complaints and inquiries per 1 000 Avista
customers in 2003 was 1.These numbers are not
indicative of a particular problem wi th Avista ' s customer
relations; however , they do reveal an obvious correlation
CASE NO. AVU-E- 04 -l/AVU-G- 04-
06/21/04
PARKER,
STAFF
(Di) 19
881
between higher rates and customers ' inabili ty to pay bills
in full.Staff Exhibit No. 152 shows in graph form how
Avista s number of complaints and inquiries per 1,000
customers compares to other maj or Idaho regulated energy
companies.
Is Avista responsive to the Commission
Utility Compliance Investigators during Icomplaint
investigations?
Yes, Company representatives are responsive to
lssues raised by customers and -Staff and they respond in a
timely manner.The average length of time in which Staff
was able to resolve Avista s complaints in 2003 was 3.
business days for electric related complaints and 3.38 for
natural gas related complaints.The average length of
time among all Idaho regulated electric customers was 3.
days and 2.81 for natural gas customers.
What observations do you have about the
Company s Websi te?
Many functions are available on Avista ' s
customer- friendly Websi te.Customers can sign up for
service, disconnect service , or transfer service using the
Company s Websi te.Bills can be received and paid online.
Currently, Avista does not have the abili ty for customers
to make payment arrangements online; however, this feature
lS on Avista s project list although no definite date for
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER,
STAFF
(Di) 20
882
implementation has been determined.
How many Avista customers in Idaho recel ve
their bills online?
Nearly 3,000 Idaho customers have signed up to
receive their bills online, saving the Company printing
and postage costs.
Do you believe Avista provides adequate
customer serVlce for non-English speaking customers?
The Company has indicated to Staff thatYes.
it usually has one Spanish-speaking representative on
shift during weekday business hours.They also offer a
translation service through a contracted service called
Language Line that is available 24 hours a day, 7 days a
week.At this time , the low number of Hispanic and non-
English speaking residents in the Idaho counties served by
Avista does not justify requiring the Company to provide
bills, notices, and/or brochures in any languages other
than Engl ish.It is not clear how customers in need
translation services are made aware of the availability of
the Language Line service since those in need do not speak
or read English.However , the question of how best to
meet the needs of non-English speaking customers will be
addressed by the recently formed Best Practices Task
Force.As mentioned previously, both Avista and the Staff
are members of the task force.
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER , M.
STAFF
(Di) 21
883
Did you reVlew the Company s bills, notices,
forms , and other documents to ascertain compliance wi
the Utility Customer Relations Rules (UCRR)?
Staff suggested many changes be made toYes.
Avista s Rules Summary as required by Rule 701.In a
meeting held in June of this year, Avista and other
regulated energy companies asked Staff to develop a model
Rules Summary that could be used as a guideline by the
companies.Consumer Staff is currently working on a model
Rules Summary that should be completed and available by
August 2004.
Staff also reviewed the Company s bills,
notices, and forms and identified ones that were not in
compl iance wi th the UCRR.The areas of non-compliance
were discussed with Avista and the Company agreed to
revise the non-compliant forms.The Company will provide
coples to Staff for review prior to final printing of the
revised forms.
OUT - OF - CYCLE METER READINGS
In your review of Company procedures regarding
out-of-cycle meter reading and billing, did you find
anything of concern?
Yes. Avista does not physically disconnect
service after a customer moves and discontinues service.
Unless another customer moves in immediately after the
CASE NO. AVU-E- 04 -l/AVU-G- 04-06/21/04 PARKER , M.
STAFF
(Di) 22
884
former customer discontinues serVlce , this resul ts in
unbilled usage not attributable to any customer.The
Company has also established a policy of not routinely
reading meters outside of regular monthly meter reading
cycles.A customer who establishes or discontinues
serVlce on a date that does not coincide wi th the
Company s regularly scheduled meter reading will recei ve
bill based on estimated rather than actual usage.
Property owners who have landlord-tenant agreements wi
Avista and customers who move or discontinue service
seasonally are affected by this policy.Staff's primary
concern lS that these customers are not receiving accurate
bills based on their actual usage.
Is the Staff prepared to recommend a solution
to this perceived problem?
Not at this time.Due to time constraints,
Staff has been unable to complete its investigation or
explore solutions wi th the Company.Staff intends to
pursue this matter informally and, if necessary, ask the
Commission to address the issue formally in a separate
proceeding at a later date.
Does this conclude your direct testimony?
Yes it does.
CAS E NO. A VU - E - 04 - 1/ A VU - G - 04 - 106/21/04 885
PARKER,
STAFF
(Di) 23
(The following proceedings were had in
open hearing.
(Staff Exhibit Nos. 149 through 152,
having been premarked for identification , were admitted into
evidence.
MS. NORDSTROM:With the Commission's permission
I'd like to ask Ms. Parker to clarify Staff's position in light
of Avista' s rebuttal testimony.
COMMISSIONER KJELLANDER:Please proceed.
BY MS. NORDSTROM:Ms. Parker, in his rebuttal
testimony, Company witness Kopczynski states that improving
service levels as proposed by Staff increase the Company'
Idaho revenue requirement by $162 735.Does Staff support the
Company's request for additional revenue?
No, and that's because expenses associated wi
improving service levels are not yet known and measurable, so
it would be premature for the Commission to approve a specific
level of funding at this time.Neither the Staff nor the
Commission has sufficient information at this time to judge the
reasonableness of the Company's estimated costs.Staff was
concerned that the Company didn't look at any other ways to
improve their service levels other than creating and filling
some positions in customer service , so we just would like them
to look at some other things.
Do you believe that there are other , more cost
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PARKER (Di)Staff
effective, al ternati ves out there?
There could be , yes.
I assume that's what Staff wants to
investigate?
Yes.Yes.
In light of Company witness Kopczynski's rebuttal
testimony, do you wish to make any changes to your
recommendation that the Company return to a goal of answering
80 percent of its incoming calls within 30 seconds by January
of 2005?
Yes.Although the Staff does believe that
answering 80 percent of calls within 30 seconds is an
appropriate goal, we are willing to give the Company time to
explore some technology-based solutions that are designed to
help improve service levels.
Recently, the Company did indicate to us also
that they have five full-time equivalent positions in customer
service that are currently vacant , and addi tionally, they have
four full-time equivalent positions that are where the people
have been reassigned.And also in the last year or so, the
Company has filled 6.5 full-time equivalent positions.And so
to the extent that they have had all these positions vacant
it's not surprising to us that with the call volumes
increasing, that service levels and employee morale declined.
We also understand that even if the Company were
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
PARKER (Di)
Staff
to fill these positions immediately, it's going to take some
time for people to get up to speed and we want to give the
Company time to do that.
And so right now , what Staff is recommending
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID 83701
that the Company come back to us in July of 2005 and report on
the prior 12 months at that time , what the service levels have
been , and then tell us what they have done to improve service
levels at that time.And at that point , we'll re-examine to
see if further steps are warranted.
MS. NORDSTROM:That concludes my questions, and
Thank you very much.
Why don't we move now to Mr. Meyer.
MR . MEYER:Thank you for that clarification.
Mr. Ward.
Thank you.
Mr. Cox.
m sorry?
No questions.Okay.
Thank you.
Thank you.
Are there any questions
I tender Ms. Parker for cross-examination.
COMMISSIONER KJELLANDER:
Wi th that , we have no questions.
COMMISSIONER KJELLANDER:
MR . WARD:No questions.
COMMI S S IONER KJELLANDER:
MR . COX:No questions.
COMMISSIONER KJELLANDER:
MR . COX:No questions.
COMMISSIONER KJELLANDER:
MR . PURDY:I have none.
COMMISSIONER KJELLANDER:
888
PARKER (Di)Staff
from members of the Commission?
So no opportunity for redirect.
And, Ms. Parker , we appreciate your presence,
your testimony, and thank you very much.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:Do you have another
wi tness we could squeak in?
MS. NORDSTROM:Well , we
- -
Staff would really
rather wai t and keep all of our accounting testimony together
at one time.We'll put a witness on if you'd really prefer
but our preference would be to wait.
COMMISSIONER KJELLANDER:Okay.Well, then
we'll go ahead and give you that freedom of flexibility only
because it's your turn to have that freedom of flexibility, so
we'll allow that then.
And before we get out of here, is there anyone
who has a witness they can put on?I mean, I hate to squander
30 minutes.
COMMISSIONER SMITH:ince we al ready squandered
that long.
COMM IS S IONER KJELLANDER:Well , that was only a
ten-minute break that lasted 40 minutes.
No one?No one willing to offer anyone up?
Well then , tomorrow morning, 9: 00 a. m. ?Okay,
9:00 a.And I won't dare use the word "prompt," but
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HEDRI CK COURT REPORTING
O. BOX 578, BOISE, ID
COLLOQUY
83701
9: 00 a. m. tomorrow morning is when we hope to start.We'll be
moving with Staff's accounting witnesses and we'll see how far
we get through the day, and perhaps we'll get done.
COMMISSIONER HANSEN:So was that nine or ten
after?
COMMISSIONER KJELLANDER:Nine 0' clock.
So with that then , we'll be adjourned for the
day, and appreciate everybody's patience and indulgence for
some of the delays we've had today.I do believe we've got the
microphone system resolved at least temporarily, so hopefully
that won't be a problem going forward.So, thank you again.
We'll see you tomorrow.
(The hearing adj ourned.
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HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID
COLLOQUY
83701