20040803Vol II.pdf

ORIGINAL
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
SERVICE TO ELECTRIC AND NATURAL GAS)
CUSTOMERS IN THE -STATE OF IDAHO.
CASE NOS.
AVU-04-
AVU-04-1 '
Idaho Pu~lic Utilities Cqrnmission
Office of the Secr~aryRECEIVED
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 19/ 2004
VOLUME II - Pages 130 - 364
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
COURT REPORTING
J1eR't'.ff tk eQf/(/I((Q(lo/t &r.fU 1978
For the Staff:
For Avista:
For Potlatch:
For Coeur Silver Valley:
For Community Action:
SCOTT WOODBURY , Esq.
and LI SA NORDSTROM, Esq.
Deputy At torneys General
472 West Washington
Boise , Idaho 83702
DAVID J. MEYER , Esq.
Avista Corporation
Post Office Box 3727
1411 East Mission Avenue
Spokane, Washington 99220-3727
GIVENS PURSLEY LLP
by CONLEY E. WARD , Esq.
601 West Bannock StreetBoise, Idaho 83702
EVAN S, KEANE
by CHARLES L.
Post Office Box
111 Main Street
Kellogg, Idaho
COX , Esq.
659
83837
BRAD M. PURDY , Esq.
At torney at Law
2019 North Seventeenth StreetBoise, Idaho 83702
HEDRICK COURT REPORTINGP. O. BOX 578 , BOISE, ID
APPEARANCES
83701
WITNESS
I N D E X
EXAMINATION BY PAGE
Malyn K. Malquist
(Avista)
Don M. Falkner
(Avista)
Don F. Kopc zynski
(Avista)
William G. Johnson
(Avista)
Richard L. Storro
(Avista)
Clint Kalich
(Avista)
Tara Knox
(Avista)
Ms. Nordstrom (Cross)
Commissioner Smith
130
140
Mr. Meyer (Direct)
Prefiled Direct
Prefiled Rebuttal
Mr. Ward (Cross)
Ms. Nordstrom (Cross)
Commissioner Hansen
Commissioner Smi
143
145
192
221
222
234
236
Mr. Meyer (Direct)
Prefiled Direct
Prefiled Rebuttal
Ms. Nordstrom (Cross)
237
240
258
266
Mr. Meyer (Direct)
Prefiled Direct
Mr. Woodbury (Cross)
267
269
281
Mr. Meyer (Direct)
Prefiled Direct
Mr. Woodbury (Cross)
Commissioner Smith
283
285
295
300
Mr. Meyer (Direct)
Prefiled Direct
Mr. Woodbury (Cross)
302
304
314
Mr. Meyer (Direct)
Prefiled Direct
Prefiled Rebuttal
Mr. Cox (Cross)
Mr. Woodbury (Cross)Mr. Meyer (Redirect)
316
318
335
345
358
360
HEDRICK COURT REPORTING
O. BOX 578, BOISE, ID
INDEX
83701
NUMBER PAGE
For Avista:
Schedules 1-
(Confidential - Schedule
Premarked
Admi t t ed 295
remar ked
Admi t t ed 281
Premarked
Admitted 314
Premarked
Admitted 266
Premarked
Admitted 221
Premar ked
Admi t t ed 221
Premar ked
Admitted 345
Premarked
Admitted 345
Premarked
Admi t t ed 221
Premarked
Admitted 221
Premar ked
Admitted 345
Premar ked
Admitted 345
5 .
10.Schedules 1-
(Confidential - Schedule
(Conf ident ial)11.
12 .2003-2006 West of Hatwai Energization
Dates and Description
14 .Electric Resul ts of Operation
15.Gas Results of Operation
16 .Schedules 1-
17.Schedules 4 and
26.Idaho Pro Forma Results
27.Gas Results of Operation
28.Cost of Service General Summary
29.Electric Cost of Service Incremental
Changes
HEDRICK COURT REPORTING
O. BOX 578, BOISE, ID 83701
EXHIBITS
BOISE, IDAHO, MONDAY, JULY 19,2004,1:30 P.
MAL YN K. MALQUI S T ,
produced as a witness at the instance of Avista , being been
previously duly sworn , resumed the stand and was further
examined and testified as follows:
COMMISSIONER KJELLANDER:We're ready to go back
on the record, and when we left, Wi tness Malquist was on the
stand and we were led, I believe, to move to Mr. Woodbury for
cross.
MR . WOODBURY:I would defer to Ms. Nordstrom.
COMMISSIONER KJELLANDER:Or did I need to say,
"Ms. Nordstrom"?
MS. NORDSTROM:Thank you.Thank you.
CROS S - EXAMINA T I ON
BY MS.NORDSTROM:
Good afternoon.
Good afternoon.
Let'talk about
bit.Mr.Ward asked you about the consolidated investment
investment ratings for a little
rating for Avista.Which organizations does that investment
rating encompass?
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HEDRICK COURT REPORTING
O. BOX 578, BOISE, ID
MALQUIST (X)
Avista83701
The rating is really on the parent company,
Avista Corp., which also would have included Avista Utilities.
Wouldn't you agree that utility risk is a factor
in the investment rating?
Absolutely.
Why should regulated authorized return for
electric be the same as for gas?
Basically, I think the assessment should be
the risk roughly the same.I think that the risk is
approximately the same.It's the same group of shareholders
that are owning the consol ida ted company.They're not
distinguishing between gas and electric in terms of their
expected returns.And so I think it makes sense that,
generally speaking, unless you can significantly differentiate
between the two, that you wouldn t have two separate returns on
equity for the two departments unless they're set at different
points in time.
But isn't the risk associated with gas and
electric substantially different?
That's - - I guess that is the question:Is it
substantially different and can you really segregate those
risks based on a consolidated company.I think our investors
are investing in Avista Corp., knowing that it's a combination
company and not just an electric company and not just a gas
So I don't know how you split out their expectationscompany.
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HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
MALQUIST (X)
Avista
of what their returns would be based on the fact they're buying
a consolidated company.
Do you think that that should preclude , you know,
regulators from splitting out gas and electric for investment
rating purposes if that could be done reasonably?
I think it just adds another -- an extra level of
complexi ty that I don't know really needs to be there, but if
you can do that and still capture investors' expectations for
the total sum , which I think is what our investors are
procuring, I guess you could do that.I just don't know why
you would.
Okay.Mr. Ward had an exhibi t , it was
Exhibit 215, and it talked about -- one of the things
mentioned was liquidity position.Could you explain what that
is?
Basically, it's looking at the ability of the
Company to fund ongoing current operations.Do you have enough
liquid assets, do you have enough cash, do you have enough
short-term financing ability to finance your day-to-day
operations.
So included in that would be your capital budget,
what is your capital budget and your spending that is required
in the current year.Would also include the requirement to
post collateral for gas purchases, let's say, that where the
counterparty might be requlrlng some cash to be posted.Would
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HEDRI CK COURT REPORTING
O. BOX 578 , BOISE, ID
MALQUIST (X)
Avista83701
be those kinds of things
- -
letters of credit
- -
that are
needed on a day-to-day basis in between maJ or financings of
long-term debt or common equity.
Is it correct to say that the liquidity position
for Avista Utilities has improved?
Yes, it is correct to say that the liquidity
posi tion has improved.
Mr. Ward had you read a rating reVlew stating
that the Idaho Public Utilities Commission was historically
more favorable to the Company than other states.
Would you agree that the Idaho Public Utilities
Commission and its Staff continue to support Avista' s efforts
to fund obligations, including refinancing, to improve
liquidity and decrease current and future risks with
maturi ties?
Yes, I would say that that's true, and I guess
would make the same statement for all of our jurisdictions
the present time.
Mr. Morris suggested that Staff direct the
following question to you:
What method of rlng fencing is in place currently
to protect customers from affiliate bankruptcy?
I think that we have a very adequate set of
protections in place.The maj or one that I think the rating
agencies would be concerned about is Avista Energy.That's the
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HEDRI CK COURT REPORTING
P. O. BOX 578 , BOISE , ID
MALQUIST (X)Avista83701
one they talk about in the wri te -ups, because it's the most
significant and it does have the most risk associated with it.
What we've done wi th Avista Energy is try to make
sure that, first, it is adequately funded.So there is roughly
$200 million of equity on the books of Avista Energy.They
have been carrying cash balances of between 100 and $150
million.And so the large percentage of the equity is held in
cash , if you will , to make sure that they can make good on all
of their commi tments.
Secondly, we've really tried to downsize the
business, commensurate wi th what's happened in the energy
marketplace.Fewer trading partners, basically, less
volatility in the marketplace.And so we have paid out a
fairly significant amount of dividends from Energy to Capital
and on up to Corp. to basically right-size the Company and not
have it be as significant an issue for the rating agencies.
I think , third, is there is no parental guarantee
from Avista Corp. and Avista Utility to Avista Energy.The re
is from Avista Capi tal, but there's not from Avista Corp. and
Avista Utilities.
And I think we've tried to demonstrate in the
past that if a company has problems as we encountered with
Avista Communications, that we cut the cord.We basically
liquidated the position of the Company so that it would not
continue to be a drag on Avista Corp. and on Avista Utilities.
134
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
MALQUIST (X)
Avista83701
You know , I don't
- -
I think what we're talking
about is a very small percentage likelihood of happening
because of the liquid position that we've put in place, because
of a very disciplined risk management program that we have at
Avista Energy, and the track record of the business.So I
don't have a lot of fear about what you've said, but I think
we've tried to ring fence it as well as we possibly can, glven
the corporate structure that we have in place.
THE WITNESS:I s there anything we can do about
the feedback on the speaker?
COMMI S S IONER KJELLANDER:Well , we can continue
to try to work with that.I apologize for the inconvenience
presents.I think if it becomes extraordinarily annoying,
maybe the option is to turn it off and just speak loudly.
THE WITNESS:Could I do that?It's just a
little distracting to me when I talk.It's like I'm echoing
he re .
COMMISSIONER KJELLANDER:So why don't we do
that.
THE WITNESS:So let me talk really loud.Will
that work for everybody?
BY MS. NORDSTROM:Works for me.
Thank you.
Are the Utility assets secured in the event of
bankruptcy?
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID
MALQUIST (X)
Avista83701
In the event of bankruptcy of one of the
subsidiaries?
Yes.
The loss will be passed on on the parent's books,
and I think that's the issue that the rating agencies are
pointing out.The loss is passed on and consolidated onto the
parent's books.However , there is -- it lS a separate entity,
legal enti ty, such that we've done everything we can to isolate
it the same way a holding company structure would isolate it as
a separate entity with no guarantees of the liabilities of that
corporation.So I think the answer is, yes, it I S protected in
bankruptcy, but do understand that losses flow up to the top.
COMMISSIONER KJELLANDER:Mr. Woodbury, it might
be wise to apprise you that you re talking over a live mike
and your whispering may not be necessarily undetected.
MR. WOODBURY:Thank you.
BY MS. NORDSTROM:Well, is, in fact
- -
are, in
fact, the utilities separate, separate corporate entities?
Looking at your corporate diagram, it didn't appear that they
were.
Well, the Utility, Avista Corp., is an entity.
Avista Capital is a separate subsidiary underneath Avista
Utilities, Avista Corp.And Avista Energy is a subsidiary
under Avista Capital.
So are they separate entities?Yes, they are.
136
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID
MALQUIST (X)Avista83701
They're separate
- -
I mean, I'm not a lawyer , so I'm not the
one to testify to that, but we've tried to set it up so that
all of the liability exists at the subsidiary level and not
back to the parent.
Would you be willing to explore the concept of
ring fencing further with Staff and other parties to determine
if there are further protections that could be implemented?
Yes, we're always willing to work wi th the Staff
on those kinds of issues, you bet.
Over the last several years,approximately how
much money have Avista subsidiaries owed the parent company?
When you say,owed the parent company, in terms
of loans outstanding that might have to be repaid, what we'
been doing, our practice wi th the subsidiaries, has been
basically to write off the investment as the dollars are
consumed.So for example, at Avista
- -
Avista Labs, the burn
was essentially being taken to the bottom line on a continuing
basis by the parent.
Now there is, at Avista Advantage, I want to say
roughly $30 million of loan to the parent, and that's a result
of the fact that there are minori ty shareholders there where we
were not able to take that entire amount essentially without
taking their share, if you will , of the loss that was
generated.
So I'm not sure I'm really fully answerlng your
137
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID
MALQUIST (X)
Avista83701
question because I don't have in my mind the total loans that
were made, but what I can tell you is the financial reports
have reflected the write-offs associated with losses that have
occurred and there is very little debt that is owned to
- -
owed
to
- -
Avista Capital at the present time to either Avista
In fact, Avista Energy has no debt on its books.Ene rgy .
Sometimes it loans money the other direction to Avista Capital
when it has excess cash.And the only loan of significance
that I'm aware of is the $30 million at Avista Advantage.
There might be some small amounts in the other category, but
they re fairly small.
Does it seem reasonable that over the last
several years, approximately $137 million have been owed to the
parent company from Avista subsidiaries?
I'd have to check that figure.That seems like a
lot to me.And I think it may include some of the things that
have been written off over time so they're not currently on the
books.
Could you explain where this money comes from?
Is it retained earnings or the borrowings of the Utility?
Oh, it definitely comes from retained earnings.
It's dollars that could be returned to the shareholder, but the
management and the board of directors have determined to
reinvest it rather than returning it to the shareholders, and
they have reinvested it in some of the unregulated
138
HEDRI CK COURT REPORTING
O. BOX 578, BOISE, ID
MALQUIST (X)
Avista83701
subsidiaries.
And I will just reiterate what I said earlier
about Avista Energy actually contributing a lot of money back
the other direction over this time.I think if you looked at
the ins and the outs, the ins that have come from the Avista
Energy have probably exceeded the outs that have gone to the
other subsidiaries where there may have been losses or loans
outstanding.
Could this money have been used to pay off
deferral balances during that period?
I think there are a lot of uses for the
shareholders' money.It is possible that instead of putting
money into those subsidiaries, which I think were being done
with the good intention of generating more cash, that it could
have been used to lessen the amount of financing that we had to
do on the deferrals.But again, I would reiterate, I think
you look at the pluses and the minuses, the pluses that came in
from Avista Energy have far exceeded the minuses that went out
for the other subsidiaries.And that is, after all, retained
earnings that I think the Company has the ability to determine
how to spend.
MS. NORDSTROM:Thank you.I have no further
questions.
COMMISSIONER KJELLANDER:Are there questions
from members of the Commission?Commissioner Smi th.
139
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
MALQUIST (X)Avista83701
COMMISSIONER SMITH:Thank you.Just a few.
EXAMINATION
BY COMMISSIONER SMITH:
In looking at Exhibit 214 and the change
I guess do rating agencies do these on a set
schedule, like every spring, every fall?What's their
frequency?
We visit them quarterly, and if they believe
there is a significant event, then they will put out a rating
more often than that.Normally, a normal cycle would be every
six months that they would put out a revised rating on a
company.
Well , it looks to me
MR. WARD:Could we have Mr. Malquist speak a
little louder?
THE WITNESS:Sorry.
BY COMMISSIONER SMITH:Looks to me ike
something happened in '98 to cause these ratings in '99 to be
significantly lower.
Well, there was
- -
there is a clear change that
takes effect in 1999 - - am I speaking loud enough - - there's a
clear change that hits in 1999 with the downgrade that Mr. Ward
and I discussed earlier.
140
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID
MALQUI S T ( Com)
Avista83701
Right.And I was assuming that whatever caused
it happened earlier than ' 99 to show up in the ' 99 rating.
And I think that the discussion and the issues
that were read into the record, from the rating agencies' point
of view at that point in time, they were concerned about the
unregulated investments that were being made at the Company.
And, of course, I had the thought of perhaps that
had to do wi th the Company's leadership?
think that that might be a good conclusion on
your part.
And then I had the thought that maybe you should
look beyond that to the board,and which caused me to have the
question that I don't know if you can answer or maybe you'
not the right person , but are the board members that sit
your board today the same ones that were there in '98
and ' 99?
There has been a significant turnover of the
board membership since that point in time.
All right.On Exhibit 215, page 8, this is old,
but it noted that you were still expecting money from the
California independent system operator, and I wonder if you
ever got paid by them.
We have not received those funds.We still have
a receivable of roughly $40 million on the books which we have
fully reserved for such that it would be simply a plus if any
141
HEDRICK COURT REPORTING
O. BOX 578, BOISE , ID
MALQUI ST (Com)
Avista83701
of those dollars were to come back to us.
COMMISSIONER SMITH:Thank you.Those are all my
questions.
COMMI S S IONER KJELLANDER:Thank you.
Are there any further questions from members
the Commission?
If not, we're ready for redirect.
MR . MEYER:And I have no redi rect Thank you.
COMMI S S IONER KJELLANDER:Thank you.
Mr. Malquist, we appreciate your testimony today,
and we apologize for the difficulty with the sound system.
THE WITNESS:I didn't mean to appear irritated
by that.I simply was having a little bit of a hard time
concentrating there and wanted to be at my best for you.
COMMISSIONER KJELLANDER:It's fair enough.
Being on the witness stand is difficult enough , so thank you.
(The wi tness left the stand.
COMMI S S IONER KJELLANDER:I guess we're ready for
the next wi tness
MR. MEYER:Next wi tness would be Mr. Falkner.
(Discussion off the record.
COMMI S S IONER KJELLANDER:Weill go back on the
record.
142
HEDRI CK COURT REPORTING
O. BOX 578, BOISE, ID
MALQUI ST (Com)
Avista83701
DON M. FALKNER
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 record, please state your name and your
employer.
My name is Don Falkner , and I work for Avista
Corpora t ion.
And in what capacity?
Manager of revenue requirements in the rates
department.
In that capacity, have you prepared and prefiled
both direct and rebuttal testimony?
Yes,have.
Do you have any changes to make ei ther?
No,do not.
were ask the questions that appear
that direct and rebuttal , would your answers be the same?
Yes, they would.
Are you also sponsoring what have been marked as
143
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
FALKNER (Di)Avista83701
Exhibits 14 and 15 to your direct testimony, and Exhibit 26 and
27 to your rebut tal test imony?
Yes, I am.
And is the information in that material true and
correct, to the best of your knowledge?
Yes, it is.
MR . MEYER:Wi th that, I ask that Mr. Falkner'
direct and rebuttal testimony be spread as if read, and move
the admission of Exhibits 14 15,26, and 27.
COMMISSIONER KJELLANDER:And without obj ection,
we'll make that happen.
MR. MEYER:Thank you.
(The following prefiled direct and
rebuttal testimony of Mr. Falkner is spread upon the record.
144
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
FALKNER (Di)
Avista83701
INTRODUCTION
Please state your name, business address, and present position with
A vista Corp.
My name is Don M. Falkner. My business address is 1411 East Mission
Avenue, Spokane, Washington. I am employed by Avista Corp., doing business as Avista
Utilities vista" or "Company ) and my current position is Manager of Revenue
Requirements in the Department of State and Federal Regulation.
Would you please describe your education and business experience?
I graduated from Washington State University in February of 1981 with a
Bachelor of Arts Degree in Business Administration, majoring in Accounting. That same
year, I sat for and passed the May Certified Public Accountant exam. I joined the Company
in June of 1981. I have served in various positions within the sections of the Finance
Department, including Power Supply Accounting, Subsidiary Accounting, Budget and
Forecasting, Plant Accounting and Corporate Accounting. For the past 12 years, I have
served in the Department of State and Federal Regulation. I have also attended several utility
accounting and ratemaking courses.
As Manager of Revenue Requirements, what are your responsibilities?
As Manager of Revenue Requirements, aside from special projects, I
responsible for preparation of normalized revenue requirement and pro forma studies in the
various jurisdictions in which the Company provides utility services.My other main
responsibilities over the last 5 to 6 years has been acting as the lead rate analyst in the
145 Falkner, Di
A vista Corporation
Company s most recent electric and natural gas general rate filings in Washington, Idaho and
Oregon.
Have you previously testified before this Commission?
Yes. I testified before this Commission in 1993 in Case No(s). WWP-92-
and WWP-92-2 and was the main revenue requirement witness in the Company s 1998
electric general case, WWP-98-ll.
What is the scope of your testimony in this proceeding?
My testimony and exhibits in this proceeding will generally cover accounting
and financial data in support of the Company s need for the proposed increase in rates. I will
explain pro formed operating results including expense and rate base adjustments made to
actual operating results and rate base. Messrs. Hirschkom and Johnson were responsible for
the preparation of the pro forma revenue adjustment and the pro forma power supply
adjustment, respectively.I will cover each of those adjustments briefly while their
testimonies will provide more in-depth discussions. While I provided the numerical revenue
requirement impact of the pro forma vegetation management and pro forma transmission
project adjustment, Mr. Kopczynski will provide additional operational detail and support
regarding those adjustments.
Are you sponsoring any exhibits to be introduced in this proceeding?
Yes. I am sponsoring Exhibit Nos. 14 and 15, which were prepared under
supervision and direction.
146
Falkner, Di
A vista Corporation
II.COMBINED REVENUE REQUIREMENT SUMMARY
Could you please summarize the results of the Company s pro forma
studies for both the electric and natural gas operating systems for the Idaho
jurisdiction?
Yes. After taking into account all standard Commission Basis adjustments, as
well as additional pro fonna and nonnalizing adjustments, the pro fonna electric and natural
gas rate of return ("ROR") for the Company s Idaho jurisdictional operations are 4.71 % and
00%, respectively. Both return levels are substantially below the Company s requested rate
of return of 9.82%. The incremental revenue requirements necessary to give the Company an
opportunity to earn its requested ROR is $35,222,000 for the electric operations and
$4,754 000 for the natural gas operations. By itself, the overall electric percentage request is
24.08%, but after taking into account the Company s proposed reduction to the power cost
surcharge currently in effect, the overall electric increase is 11.0%, while the overall natural
gas increase is 9.2%.
III.ELECTRI C SECTI ON
CHANGES SINCE 1997 TEST PERIOD
On what test period is the Company basing its needs for additional
revenue?
The test period being used by the Company is the twelve-month period ending
December 31,2002 presented on a pro fonna basis.
147
Falkner, Di
A vista Corporation
What is the Company s Rate of Return that was last authorized by this
Commission for its electric operations in Idaho?
The Company s currently authorized Rate of Return for its Idaho electric
operations is 8.98%. That rate comes from Case No. WWP-98-ll, which became effective
August 1 , 1999, and utilized a 1997 test year.
Have there been any changes to base electric rates in the Idaho
jurisdiction since August 1, 1999?
Yes. As part of the Commission s order in Case No. WWP-98-11, a
revenue neutral cost of service rate shift was implemented one year later at August 1 , 2000
with some classes receiving an increase and others receiving a decrease. In October 1989, the
Company implemented a Power Cost Adjustment ("PCA") mechanism. There have been
several temporary adjustments to overall Idaho electric rates, both increases and decreases,
over the years associated with that mechanism. A surcharge is currently in place.
Does the PCA mechanism have any impact on the normalized level of
Company earnings for its Idaho jurisdiction?
No. The PCA mechanism only impacts actual, unadjusted earnings, and those
impacts are normalized out, or removed from the pro forma results of operations for the
Company s Idaho jurisdiction.
What has been the Company s experienced earnings levels since the rate
change associated with Case No. WWP-98-11?
Outside of one year, the Company has consistently earned below its last
authorized level of 8.98%. One of my main responsibilities has been preparation of a
148
Falkner, Di
Avista Corporation
jurisdictional electric report that is required in Washington. The Company provides a copy of
this report based on its Idaho jurisdiction results to the Idaho Commission Staff. These
reports are prepared on a "Commission Basis.Commission Basis means that rate base
includes standard rate base components that have historically been accepted by the
Commission for ratemaking. Additionally, the Company s booked results of operations are
adjusted to a ratemaking basis by normalizing weather impacts on revenues and power supply
and eliminating out-of-period items, nonrecurring items or any other item that would
materially distort the test period's results. The final result is a restated rate of return for the
reporting period. A historical review of the Company s filings with the Commission Staff
show that the Company s Idaho electric operations have been earning less than its last
authorized rate of for 4 out of the last 5 years.
What are the primary factors driving the Company s need for an electric
increase?
There are numerous operational factors that have impacted the Company
electric results of operations since the 1997 test year. On page 10 of my Exhibit No. 14, I
have made a side-by-side comparison of the Company s authorized test year net operating
income and rate base and our 2002 pro forma levels. As you can see on line 27, column (d),
Net Operating Income ("NO!") has declined $11.7 million, or 36%, and Total Rate Base has
increased $79.7 million, or 22%. During this same time period, average customers have
increased 8.4%. At a high summary level, the Company s electric request is made up of the
impacts of changes in net operating income components, rate base growth and cost of capital.
Respectively, those items represent $18.2 million, $11.2 million and $5.8 million of the
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requested $35.2 million of additional general business revenues. The primary component of
the reduction in net operating income is increased Net Power Supply costs. I will provide
additional detail regarding these items later, but the chart below shows this initial
companson:
A vista Corp.
Eectric Revenue Requirement
Components
$13.
I!!J Net Power Supply. Other-Net
0 Rate Base (Jowth 0 Cost of Capital
The decline in net operating income, represented above by Net Power
Supply and Other, makes up slightly more than half of the Company s request. What
are the main components of the Other segment?
Due to the Company multi-service and multi-state utility operations,
breaking out individual components is initially difficult, however, additional analysis shows
that other changes contributing to the decline in Idaho electric net operating income, and the
need for additional revenues are increases in depreciation expense, production and
transmission O&M, pension costs, insurance costs, and to lesser degree, increases in
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customer accounting/service/sales costs and administrative and general expense. Also, a
decline in customer usage has impacted the level of the Company s request.
You mentioned a decline in use per customer. How has the Company
customer base changed since the 1997 test year?
Average customer count for the Company s Idaho electric jurisdiction has
increased from approximately 98,260 to 106,535 at the end of 2002, or an 8.42% increase.
Page 10, columns (f) through (i) of Exhibit No. 14 show the same 2002 versus 1997
comparisons on a per customer basis.
Was this increase in customer base accompanied by an associated
increase in total revenues?
Actually, no. Still looking at that page of Exhibit 14, despite a customer
increase of over 8%, line 1 percentage difference column (e), for total general business
revenues, excluding the large impact of special contract and a different presentation of the
Demand Side Revenue tracker, shows that total revenues have actually declined slightly.
After taking into account the addition of 8,275 new customers, general business revenues per
customer have declined by almost 9%, on a normalized basis.Since base rates have
remained constant, this indicates energy usage has declined. Assuming the incremental
power supply cost being utilized in this filing, and the current overall revenue per customer at
current rates, the lost margin impact of this decline is approximately $2.7 million. This
analysis was done on a total customer basis. Mr. Hirschkom will discuss the decline in use
per customer by schedule in more detail.
Please describe the impact of increased net power supply costs?
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Net power supply costs is the sum of fuel expense and purchased power costs
less wholesale revenues, or sales for resale. For this comparison, I've again excluded the
impact of the special contract impact. Referring back to Exhibit 14, page 10, and focusing on
Difference" column (d), line 7a, the combination of fuel expense for the Company s steam
plants and combustion turbine units, shows an increase of $4.9 million, line 8, Purchased
Power, shows a decrease of $22.3 million, while line 3, Sales for Resale, declined $30.
million. The result is a $13.3 million increase in net power supply costs. In other words, a
$17.4 million net reduction in fuel and purchased power expense was being completely offset
by a $30.7 million reduction in wholesale revenues. The decline in sales for resale is largely
driven by the "monetization," or cash discounting of a capacity contract with Portland
General Electric. The benefits of that transaction have been returned to Idaho customers
through reductions to the Company s Idaho PCA deferral balance. Mr. Johnson will discuss
all the components of the Pro Forma Power Supply adjustment in detail
Could you please identify some of the other categories that have
contributed to the Company s filed revenue requirement?
Certainly. Depreciation expense, which has largely followed the 25% growth
in gross plant-in-service, has increased $4.2 million. Production and Transmission O&M has
increased $3.4 million and has been impacted primarily by maintenance contracts associated
with the operation of the Coyote Springs 2 ("CS 2") plant, and wheeling cost changes.
We are utilizing a 2002 test year since that is the most recent normalized financial
infonnation the Company has provided the Commission, however, new general electric rates
resulting from this filing will not go into affect until later in 2004. Accordingly, the
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Company included a number of pro fonna, or forward looking cost adjustments, to capture
some of the measurable cost increases that the Company has experienced since the 2002 test
Two of those adjustments are cost increases associated with pension costs andyear.
insurance costs. Increases in these categories are not unique to A vista. In fact, pension and
insurance cost increases are impacting many regulated utilities. I will provide additional
detail for each adjustment later in my testimony. However, as it relates to the Idaho electric
analysis, pension costs impacted both operation and maintenance ("O&M"and
administrative and general ("A&G") expenses by a total of approximately $1.7 million, while
liability and insurance costs increased A&G costs by approximately $1.0. Benefit costs are
allocated to follow employee labor costs and ultimately impact all functional areas of the
Company s operations, whereas insurance costs are accounted for as A&G expense.
Portions of the pension increase is included in the Production and Transmission O&M
increase noted earlier, as well as the Distribution O&M increase of $891 000 and the net
Customer Accounting/Service/Sales increase of $673,000.Both pension and insurance
increases impacted the overall $2.0 increase in A&G operating expenses, half of that being
associated with insurance cost changes. Without an adjustment to update tree trimming costs
to a sustainable level, Distribution O&M would have actually shown a decrease. Mr.
Kopczynski has provided the operational details supporting that adjustment.
Did you perform any analysis on changes on a cost-per-customer basis?
Yes. Referring to Exhibit No. 14, page 10, columns (f) through (i) reflect that
analysis, with cost-per-customer changes between the 2002 and 1997 test years in dollars per
customer (column (h)) and the percentage change in column (i).
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What does that analysis show?
A verage customers increased 8.42% between 1997 and 2002. Virtually all
increases in operating expense groups generally considered to be the most controllable by
individual utilities, O&M, customer support costs and A&G, were lower than the 8.42%
customer increase level. After taking out the impact of the Coyote Springs 2 pro forma
adjustment, production/transmission O&M increased 4.55%, while distribution O&M
increased 6.91%, net customer support costs increased 3.47% and A&G operational costs
went up 3.47%, all on a cost per customer basis, and all lower than the 8.42% increase in
During this time period, the Consumer Price Index rose 12.1%.average customers.
Reflecting the impacts of needed new generation and transmission plant investments
depreciation costs for production/transmission and distribution categories increased 13.53%
and 11.32%, respectively.
How did you determine the revenue requirement associated with the
increase in rate base?
Again referring to my Exhibit No. 14, page 10, and looking at line 39, column
(d), you can see that Total Rate Base increased $79 661,000 between the two test periods.
This net figure is the gross plant increase less the increase in accumulated depreciation and
deferred income taxes. By reducing the rate base used in the overall revenue requirement
calculation by $79,661,000, and utilizing the currently authorized 8.98% ROR, it showed that
the overall revenue requirement was higher by $11.2 million due to the rate base growth.
Why did you use the currently authorized ROR?
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By using the currently authorized ROR of 8.98%, I eliminated the impact of
the Company s requested ROR level on the rate base related revenue requirement increase.
What were the major components of the $79.7 million increase in Total
Rate Base?
To continue to meet the energy and reliability needs of our customers, the
Company has invested additional amounts in thermal and hydro generating facilities, as well
as additional transmission investment, which in total make up approximately $61 million, or
77%, of the increase. Specifically, investments in CS 2 and the two small generation
projects, Boulder Park and Kettle Falls Combustion Turbine ("CT"), added approximately
$50 million. Necessary upgrades to the Company s Cabinet Gorge hydroelectric project
added $2.2 million.All of these figures are on an Idaho s jurisdictional basis. The
generating capacity from these projects was included in the Company s pro forma power
supply calculation. Transmission upgrades added another $8.8 million to Idaho electric plant.
Mr. Robert Lafferty discusses the need and reasonableness of the new generation, while Mr.
Kopczynski addresses the transmission upgrades. Later in my testimony, I will address the
detail behind the normalizing and pro forma net operating income and rate base impact of
these adjustments.
RE VENUE REO UIREMEN,I
Would you please explain what is shown in Exhibit No.14?
Exhibit No. 14 shows actual and pro forma electric operating results and rate
base for the test period for the State of Idaho. Column (b), page 1 of this Exhibit shows 12-
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months ended December 2002 operating results and components of the average-of-monthly-
average rate base as recorded; column (c) is the total of all adjustments to net operating
income and rate base; and column (d) is pro forma results of operations, all under existing
rates. Column (e) shows the revenue increase required which would allow the Company an
opportunity to earn a 9.82% rate of return. Column (f) reflects pro forma electric operating
results with the requested increase of $35,222,000.
Would you please explain page 2 of Exhibit No.14?
Yes. Page 2 shows the calculation of the $35,222,000 revenue requirement at
the requested 9.82% rate of return.
Would you now please explain page 3 of Exhibit No.14?
Yes. Page 3 shows the derivation of the net operating income to gross revenue
conversIon factor.The conversion factor takes into account uncollectible accounts
receivable, Commission fees and Idaho State income taxes. Federal income taxes are
reflected at 35%.
Now turning to pages 4 through 9 of your Exhibit No. 14, would you
please explain what those pages show?
Yes. Page 4 begins with actual operating results and rate base for the test
period in column (b). Individual normalizing adjustments that are standard components of
our annual reporting to the Commissions begin in column (c) on page 4 and continue through
column (x) on page 7. Individual pro forma and additional normalizing adjustments begin in
column (y) on page 7 and continue through column (ai) on page 9. These adjustments are
either refined calculations of adjustments that are usually included as components of our
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annual reporting, e.g. the Power Supply adjustment, or adjustments that are unique to this
general rate filing, e.g. the Pro Forma Insurance or Pro Forma Vegetation Management
adjustment. Column (aj) is the final pro forma operating results and rate base for the test
period.
STANDARD COMMISSION BASIS AD.JUSTME~
Would you please explain each of these adjustments, the reason for the
adjustment and its effect on test period State of Idaho net operating income and/or rate
base?
Yes. The first adjustment, column (c) on page 4, entitled Deferred FIT Rate
Base, reflects the rate base reduction for Idaho s portion of deferred taxes. The adjustment
reflects the deferred tax balances arising from accelerated tax depreciation (Accelerated Cost
Recovery System, or ACRS, and Modified Accelerated Cost Recovery, or MACRS), bond
refinancing premiums, and contributions in aid of construction. The effect on Idaho rate base
is a reduction of $60,998,000.
Column (d), Deferred Gain on Office Building, reflects the rate base
reduction for Idaho s portion of the net of tax, unamortized gain on the sale of the Company
general office facility. The facility was sold in December 1986 and leased back by the
Company. The effect on Idaho rate base is a reduction of $406,000.
Column (e), Colstrip 3 AFUDC Elimination, is a reallocation of rate base
and depreciation expense between jurisdictions. In Cause Nos. U-81-15 and U-82-10, the
Washington Utilities and Transportation Commission ("WUTC") allowed the Company a
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return on a portion of Colstrip Unit 3 construction work in progress ("CWIP"
).
A much
smaller amount of Colstrip Unit 3 CWIP was allowed in rate base in Case U-I008-144 by
this Commission. The Company eliminated the AFUDC associated with the portion of
CWIP allowed in rate base in each jurisdiction. Since production facilities are allocated on
the Production!rransmission formula, the allocation of AFUDC is reversed and a direct
assignment is made. These amounts are a component of actual results of operations. The
effect on Idaho net operating income is a decrease of $218,000. The effect of the reallocation
on Idaho rate base is an increase of $3,143,000.
The adjustment in column (0, Colstrip Common AFUDC, is also associated
with the Colstrip plants in Montana, and increases rate base. Differing amounts of Colstrip
common facilities were excluded from rate base by the WUTC and this Commission until
Colstrip Unit 4 was placed in service. The Company was allowed to accrue AFUDC on the
Colstrip common facilities during the time that they were excluded from rate base. It is
necessary to directly assign the AFUDC because of the differing amounts of common
facilities excluded from rate base by the WUTC and this Commission. In September 1988,
an entry was made to comply with a Federal Energy Regulatory Commission ("FERC") Audit
Exception, which transferred Colstrip common AFUDC from the plant accounts to account
186. These amounts reflect a direct assignment of rate base for the appropriate average of
monthly averages amounts of Colstrip common AFUDC to the Washington and Idaho
jurisdictions.Amortization expense associated with the Colstrip common AFUDC is
charged directly to the Washington and Idaho jurisdictions through Account 406. These
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amounts are a component of the actual results of operations. The effect on Idaho rate base
an increase of $1 313,000.
The adjustment in column (g), Kettle Falls Disallowance, decreases rate base.
The amounts reflect the Kettle Falls generating plant disallowance ordered by this
Commission in Case No. U-I008-185. This Commission disallowed a rate of return on
$3,009,445 of investment in Kettle Falls.The disallowed investment and related
accumulated depreciation are removed. These amounts are a component of actual results of
operations. The effect on Idaho rate base in a decrease of $1,435,000.
Please turn to page 5 and explain the adjustments shown there.
Column (h), entitled MOPS Deferred Costs increases net operating income.
MOPS (More Options for Power Supply) pilot program incremental costs were deferred until
the July 1, 2001 where a three-year amortization of the Idaho balance commenced. The
balance will be fully amortized in June 2004, so this adjustment removes the impact of the
amortization included in actual results of operations. The effect on Idaho net operating
income is an increase of $38,000.
Column (i), Weatherization and DSM Investment, includes in rate base
balances (net of amortization) of weatherization grants, the model conservation program
costs and electric demand side management (DSM) program costs upon which AFUCE is no
longer being accrued and full amortization was implemented beginning August 1994. These
amounts are a component of actual results of operations. The effect on Idaho rate base is an
increase of $9,110,000.
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Would you please explain how energy efficiency-related expenditures
impact the revenue requirement in this case?
Yes. The unamortized balance of energy efficiency management investment
incurred prior to 1995 is included in the results of operations and becomes a rate base item in
the column (i) adjustment just described. DSM expenditures incurred after March 13, 1995
have been and will continue to be offset by revenues from the Company s energy efficiency
tariff rider, Schedule 91, and are not included in the revenue requirement.
As the Commission is aware, the Company s tariff rider under Schedule 91
was the first non-bypassable distribution charge in the United States to fund energy
efficiency. Approved in Case No. WWP-94-, the tariff rider is a 1.5% surcharge to all
rate classes, with the exception of pre-existing special contracts. Mr. Hirschkom provides
additional detail and addresses the prudence of the expenditures under this tariff.
Please continue with your explanation of the adjustments on page
The adjustment in column G), entitled Customer Advances, decreases rate
base for moneys advanced by customers for line extensions as they will most likely be
recorded as contributions in aid of construction at some future time. The effect on Idaho rate
base is a decrease of $478,000.
The column marked by a dash, and immediately following column G),
subtotals columns (b) through G) and represents actual operating results and rate base plus the
standard rate base adjustments that are included in Commission Basis reporting, but not
generally calculated in the Company s monthly jurisdictional Results of Operations reports.
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Column (k), Revenue Adjustment, is a 4-fold adjustment taking into account
known and measurable changes that include revenue normalization, weather normalization,
an unbilled revenue calculation and the pro forma impact of a large special contract. It
encompasses correction of rate schedule shifts, repricing for approved tariff changes that will
be in place in the pro forma test period that were not in place in the historical test period. In
this case the weather normalization led to a minimal increase in weather sensitive electric
kWh sales and revenues. Mr. Hirschkom is sponsoring this adjustment. The effect of this
particular adjustment is to increase Idaho net operating income by $10,195,000.
The adjustment in column (1), Hydro Relicensing Adjustment, decreases net
operating income. This adjustment directly assigns the appropriate protection, mitigation and
enhancement expenses to the Washington and Idaho jurisdictions. This is necessary due to
differing regulatory treatment in Case No. WWP-98-11 and Docket No. UE-991606/UG-
991607. These amounts are a component of actual results of operations. The effect on Idaho
net operating income is a decrease of $165 000.
Column (m), Eliminate Franchise Fees, eliminates the revenues and
expenses associated with local franchise fees, which the Company is allowed to pass through
to its Idaho customers. The adjustment eliminates any timing mismatch that exists between
the revenues and expenses by eliminating the revenues and expenses in their entirety.
Franchise fees are passed through on separate schedule, which is not part of this
proceeding. The effect of this adjustment is to decrease Idaho net operating income by
$14 000.
Please turn to page 6 and explain the adjustments shown there.
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Column (n), entitled Property Tax, restates the 2002 test period accrued
levels of property taxes to the actual amounts. The effect of this particular adjustment is to
decrease Idaho net operating income by $23,000.
Column (0), Uncollectible Expense, restates the accrued expense to the actual
level of net write-offs for the test period. The effect of this adjustment is to increase Idaho
net operating income by $42,000.
Column (p), Regulatory Expense, restates booked 2002 regulatory expense to
reflect the IPUC assessment rates applied to revenues for the test period and the actual levels
of FERC fees paid during the test period. The effect of this adjustment is to decrease Idaho
net operating income by $10,000.
Column (q), Injuries and Damages, is a restating adjustment that replaces the
accrual with the six-year rolling average of actual injuries and damages payments not covered
by insurance. A six-year rolling average and the reserve method of accounting for injuries
and damages, net of insurance proceeds, is a practical methodology to deal with these normal
utility operating expenses that happen to occur on an irregular basis and differ markedly in
materiality. As a result of the WUTC's Order in Docket No. U-88-2380-, the Company
changed to the reserve method of accounting for injuries and damages not covered by
insurance for both its electric and gas systems. This methodology was accepted by the Idaho
Commission in Case No. WWP-98-11. The effect of this adjustment is to increase Idaho
net operating income by $33,000.
Column (r), FIT, is required to reflect the appropriate level of federal income
tax expense for the test period. This adjustment removes the effect of certain Schedule M
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items, matches the jurisdictional allocation of other Schedule M items to related Results of
Operations allocations and eliminates any prior period income tax expense. This adjustment
also reflects the proper level of deferred tax expense for the test period. The effect of this
adjustment, all based upon a Federal tax rate of 35%, is to increase Idaho net operating
income by $1 551,000.
Column (s), Restate Debt Interest, restates debt interest using the Company
pro forma weighted average cost of debt, as outlined in the testimony and exhibits of Mr.
Malquist, and applied to Idaho s pro forma level of rate base, produces a pro forma level of
tax deductible interest expense. The Federal income tax effect of the restated level of interest
for the test period decreases Idaho net operating income by $3,184,000.
Column (t), Idaho PCA, removes the effects of the financial accounting for
the PCA. The PCA normalizes and defers certain power supply costs on an ongoing basis
between general rate filings. When the deferral balance reaches a certain trigger level, the
balance is either returned (refunded) or charged (surcharged) to customers through a special
temporary tariff. Revenue adjustments due to the special tariff and the power cost deferrals
affect actual results of operations and need to be eliminated to produce a normal period.
Actual revenues and power supply costs are normalized in adjustments in column (k) and
column (ab), respectively. The effect of this adjustment is to decrease Idaho net operating
income by $8 580,000.
Please turn to the next page and continue with your explanation of the
adjustments on page 7.
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Column (u), entitled Nez Perce Settlement Adjustment, reflects a decrease in
Production operating expenses. An agreement was entered into between the Company and
the Nez Perce Tribe to settle certain issues regarding earlier owned and operated
hydroelectric generating facilities of the Company. This adjustment directly assigns the Nez
Perce Settlement expenses to the Washington and Idaho jurisdictions. This is necessary due
to differing regulatory treatment in Idaho Case No. WWP-98-11 and Washington Docket
No. UE-991606/UG-991607. The effect of this adjustment is to increase Idaho net operating
income by $16,000.
Column (v), Remove Mise Tariffs Adjustments, eliminates the revenues and
expenses associated with three miscellaneous tariffs where the Company is allowed to pass
through to its Idaho customers certain regulatory credits and charges. Specifically, Schedule
65-Centralia Oain, Schedule 59-Residential Exchange and Schedule 91-DSM Tariff Rider.
The adjustment eliminates any timing mismatch that exists between the revenues and
expenses by eliminating the revenues and expenses in their entirety.These separate
schedules are not part of this proceeding. The effect of this adjustment is to increase Idaho
net operating income by $412,000.
Column (w), PGE Monetization Amortization eliminates the POE
monetization amortization recorded during the test period.The benefits of the POE
Monetization, both the normal amortization, as well as the accelerated amortization credited
to the Idaho PCA Deferrals, were completely returned to customers as of December 31, 2002.
The effect of this adjustment is to decrease Idaho net operating income by $1,877,000.
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Column (x), Payroll Clearing, adjusts the payroll loading costs (benefits,
payroll taxes and paid time off) expensed through a clearing account during the test period
2002, to the actual payroll loading costs for the test period. The amounts loaded onto labor
charges through the estimated payroll loading rates during the 2002 test period produced an
expense level lower than the actual amount of employee benefits incurred for the test period.
The impact of this true-up to actual decreased Idaho net operating income by $281,000.
PRO FORMA ADJUSTMENTS
Please explain the significance of the 11 columns subsequent to column
(x) that begin on page 7 in your Exhibit No. 14.
Certainly.The adjustments subsequent to column (x) are pro forma
adjustments that recognize the jurisdictional impacts of material items that will impact the
pro forma operating period levels for known and measurable changes. They encompass both
expense items as well as significant capital projects. These adjustments bring the operating
results and rate base to the final pro forma level for the test year.
Please continue with your explanation of the adjustments on page 7.
Column (y), entitled Coyote Springs 2, pro forms in the capital costs and
operating costs of the Company s new combustion turbine plant at Boardman, Oregon. Mr.
Lafferty explains those costs.
The Coyote Springs 2 combustion turbine became commercially operational on July
, 2003, and was transferred to plant-in-service at that time. The benefits of the additional
generating capacity were incorporated into the pro forma power supply adjustment for a full
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year. This adjustment pro forms in the impacts of expenses associated with operational and
maintenance agreements with the plant operators, as well as the accompanying depreciation
expense and property tax increases. The plant-in-service and net rate base amounts reflect a
full year of operation. The effect of this adjustment decreases Idaho net operating income by
$1,896,000. The effect of the adjustment on Idaho rate base is an increase of $36,965,000.
Column (z), Small Generation, pro forms in the capital costs and associated
expense of two smaller gas-fired generating plants. Mr. Lafferty provides additional detail
regarding those plants. The effect of this adjustment decreases Idaho net operating income by
$185,000. The effect of the adjustment on Idaho rate base is an increase of $5,343,000.
The two smaller generation projects, Boulder Park and Kettle Falls CT, became
commercially operational in May 2002, and were transferred to plant-in-service at that time.
The additional generating capacity from these projects was incorporated into the pro forma
power supply adjustment. This adjustment annualizes the impacts of expenses associated
with accompanying depreciation expense and property tax increases. The plant-in-service
and net rate base amounts reflect a full year of operation. The benefits of the additional
generating capacity have been included in the pro forma power supply adjustment for a full
year as well.
Please turn to page 8 and explain the adjustments shown there.
Column (aa), entitled Capital Costs Small Gen Options, pro forms in the
impact of certain capital costs associated with leased turbines that the Commission Staff had
recommended to be removed from the PCA deferral balance for the period ending June 30,
2002. The capital costs were removed from the PCA deferral balance and recorded in a
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separate regulatory asset. These transactions were authorized in Order No. 29130 in Case
No. A VU-02-06. This case was the Company s submission of a status report and a request
for continuation of the current PCA surcharge. Staff later agreed with the Company
recommendation to begin a 5-year amortization period wherein the rate base treatment and
recovery of amortization from customers would be addressed in a future regulatory
proceeding.
The capital costs required for turbine installation were associated with the Kettle Falls
Bi-Fuel lease, the Devil's Gap lease and the Othello turbine lease, and totaled $898,000.
These amounts were outlined in Attachment A to the above Order. The lease payments
themselves for those three leases were authorized for recovery through the PCA mechanism.
As outlined in Mr. Lafferty s testimony discussing the impacts of the 2000/2001 energy
crisis, these leased turbines were part of a portfolio of transactions that allowed the Company
to avoid entering into very high-cost purchased power arrangements to meet customer loads.
The Company submits that the same rationale that supported the prudence of the lease
payments should be extended to the associated capital costs of installing the leased turbines.
The effect of this adjustment is to decrease Idaho net operating income by $120,000 and to
increase Idaho rate base by $539,000.
Column (ab), Pro Forma Power Supply, was made under the direction of
Mr. Johnson and is explained in detail in his testimony. This adjustment normalizes power
supply related revenue and expenses to reflect the twelve-month period September 1, 2004
through August 31, 2005. The effect of the power supply adjustments as outlined in Mr.
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Johnson s testimony, which is presented on a system basis, decreases Idaho net operating
income by $7,832,000.
Column (ac), Pro Forma Pension, updates the 2002 pension expense to the
expense being recorded for 2004. Pension expense, on a system basis, was $9.4 million
during the 2002 test year and has increased to $14 million for the year 2004. To be
conservative and reduce complexity, this adjustment only pro forms in the impact of
increased pension costs on labor charged to operating expense accounts, and ignores
capitalized labor s impact on rate base. Pension costs that are properly charged to non-utility
labor costs have also been excluded from this adjustment. The effect of this adjustment
decreases Idaho net operating income by $445,000.
Please describe the Company pension expense?
The Company s pension expense, which is determined in accordance with
Financial Accounting Standard 87 ("F AS-87"), has increased on a system basis from $2.
million in 1997 to $14 million in 2004, beginning primarily in 2002. Pension costs during
the actual 2002 test year were $9.3 million. The 2004 level of pension expense is actually
down somewhat from the 2003 expense of $14.9 million. However, Company projections
show the 2004 level of pension expense to continue into the foreseeable future. Pension
expense is determined by an outside actuarial firm, in accordance with F AS-87, and the
calculation and assumptions are reviewed by the Company s outside accounting firm for
reasonableness and comparability to other companies.
As is being experienced by many companies with funded pension plans, the increases
are due primarily to the investment performance of plan assets during the major downturn in
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the equity markets experienced in the last few years. The pension levels noted above are for
the Company as a whole. Pension expense, as with other employee benefits, is "loaded" onto
actual labor costs, which are then assigned to various functional expense categories and
accounts through the payroll process. Historically, approximately 70% of labor goes to O&M
expense and 30% to capital. In our adjustment, a detailed analysis of 2002 labor charges was
performed to more accurately determine the Idaho O&M percentage of overall labor.
Please describe the Pro Forma Insurance Adjustment also found on page
Column (ad), entitled Pro Forma Insurance, updates the 2002 insurance
expense for general liability, directors and officer ("D&O") liability, property and other
policies, to the actual cost of insurance policies that are in effect for 2004. Here again,
insurance cost increases is another category that is impacting virtually all utilities in just the
past few years. Insurance costs that are properly charged to non-utility operations have been
excluded from this adjustment. The effect of this adjustment decreases Idaho net operating
income by $649,000.
Please describe some of the causes for the increases in insurance costs?
Insurance costs are up significantly as a result of terrorism threats, higher
claims, and low investment returns that had previously offset current premiums, as well as
the poor financial performance of utility companies since the energy crisis of 2000-2001.
Despite these issues, the Company has been able to maintain adequate coverage to protect the
Company, its property, employees and customers from adverse financial impact in case
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adverse circumstances were to occur. A summary of our coverage, limits, and deductibles for
major insurance categories follows.
Directors and Officers Liability
D&O coverage is the most significantly changed part of Avista s insurance package.
Instead of two layers to provide coverage up to certain historical limits, we have five layers in
2004 for the same limits. The net price is up about 75% overall and the deductible has
doubled to $5 million per claim. The prevalence of shareholder claims in the energy industry
has hit the industry s two biggest insurers very hard. Their response has been to implement
much stricter terms and higher prices. Avista s D&O insurance covers individual directors
and officers and extends to the corporation also.
Property
A vista has insured its property with the same firm for several years. This property
coverage applies to potential damages to A vista property except joint projects (insured
separately along with the other project co-owners) and the utility transmission and
distribution assets. Our property insurance was renewed in November 2003 at a lower cost
than the expiring policy. We paid significantly higher premiums in each of the two prior
years. Avista s historically low claims record helped attract competitive coverage.
General Liability
A vista has two layers of general liability insurance. A vista has not had a general
liability claim reimbursed by insurers since the 1990 Firestorm claims. The first layer of
coverage was renewed using the same terms as those expiring, but at a much higher premium.
The policy was last underwritten and priced in 1998 during very favorable market conditions.
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The insurance market has increased significantly since that time. Excess insurance for claims
above a certain threshold is the second layer. The overall cost for 2004 coverage is 2.5 times
the 2003 premiums, even with the reduced limits.
Please describe the last adjustment found on page 8?
Column (ae), entitled Pro Forma Labor-Non-Exec, reflects known and
measurable changes to test period union and non-union wages and salaries, and excludes
executive salaries, which are handled separately in the next adjustment. Test period wages
and salaries are restated as if the wage and salary increases for 2002, 2003 and 2004 were in
place during the entire pro forma test period. The methodology behind this adjustment is
similar to that used in the last Idaho general case, Case No. WWP-98-11, except for the
separate treatment of executive salaries. The effect of this adjustment on Idaho net operating
income is a decrease of $705,000.
Please turn to the final page of Exhibit No. 14, page 9, and continue with
your explanation of the adjustments.
Column (af), entitled Pro Forma Labor-Executive, reflects known and
measurable changes to executive compensation. During 2002 and 2003 several executives
retired, a new chief financial executive was hired and responsibilities were re-assigned
among the executive group. This adjustment sets the current executive group s compensation
at pro forma test period levels. Compensation for any member of the 2002 officer group who
has since left the Company has been removed from the test year. Compensation costs
allocated to non-utility operations are excluded as executives routinely charge a portion of
their time to non-utility operations, commensurate with the amount of time spent on such
1 71 Falkner, Di
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activities. The current executive group s salary allocations are set at their expected pro forma
test period utility/non-utility percentage splits. The impact of this adjustment on Idaho net
operating income is a decrease of $15,000.
Column (ag), Pro Forma Vegetation Management, updates the 2002 tree
trimming expenditures to a level Company operational personnel have determined is
necessary for the proper management of vegetation around both transmission and distribution
lines to most effectively ensure reliability levels. Mr. Kopczynski is sponsoring testimony
that details the Company s vegetation management plans and the planned expenditure levels.
The effect of this adjustment decreases Idaho net operating income by $785,000.
Column (ah), Pro Forma Transmission Projects, pro forms in a portion of
the capital cost and expenses associated with the West of Hatwai transmission project. West
of Hatwai is a multi-year $100 million project being undertaken by the Company to improve
reliability across our transmission system. Again, Mr. Kopczynski is sponsoring testimony
that details the overall project. The entire project is actually broken down into a number of
sub-projects that become used and useful at different times. In this adjustment, three specific
projects with estimated system costs and completion dates have been included and are shown
in the table below:
Pine Creek 203 kV substation .............. $6,500,000...................December 2003
Beacon - Rathdrum 203 kV line ........ $18,500 000............................ May 2004
Beacon - Bell #4230 kV line .............. $1,300,000...................December 2004
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The Pine Creek substation work is actually complete, and because of their near-term
completion dates, the other two are projects that the Company submits fall under the
definition of "short-term construction work in progress" as outlined in Idaho statute ~61-
502A. The capital costs have been averaged for a full 12-month pro forma period with the
associated depreciation expense and property tax, as well as the appropriate accumulated
depreciation and deferred income tax rate base offsets. The effect of this adjustment
decreases Idaho net operating income by $249,000 and increases rate base by $8,849,000.
Column (ai), Pro Forma Cabinet Gorge Project, pro forms the capital cost and
expenses associated with material upgrades to the Company s Cabinet Gorge hydroelectric
generating facility. This $6.5 million project is scheduled to be completed and in-service in
March 2004. Here again, the Company submits that this project falls under the definition of
short-term construction work in progress. The adjustment was prepared consistent with the
methodology used in the previous adjustment. Additionally, the benefit from the increased
generating capacity has been incorporated into the pro forma power supply calculation for a
full year. Mr. Storro provides additional detail regarding the power supply benefits. The
effect of this adjustment decreases Idaho net operating income by $17,000. The effect of the
adjustment on Idaho rate base is an increase of $2 232,000.
The last column, Pro Forma Total, reflects total 2002 pro forma results of
operations and rate base consisting of 2002 actual results and the total of all adjustments.
Referring back to page 1, line 40, of Exhibit No.. 14, for identification,
what was the actual and pro forma electric rates of return realized by the Company
during the test period?
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For the State of Idaho, the actual test period rate of return was 8.18%,
somewhat below the last authorized rate of return of 8.98%. The test period pro forma rate of
return is 4.71 % under present rates. Thus, the Company does not, on a pro forma basis for
the test period, realize the 9.82% rate of return requested by the Company in this case.
By way of summary, could you please review the different rates of return
that you have presented in your testimony?
Yes. Basically, there are three different rates of return discussed previously.
The actual ROR earned by the Company during the test period, the Pro Forma ROR
determined in my Exhibit No. 14 and the requested ROR. For convenience of comparison,
please refer to the following graph:
Avista COIp
Rates of Return
12.00%
10.00%18%
00%
00%
00%
00%
00%
Actual
82%
Pro Fonna Request
How much additional net operating income would be required for the
State of Idaho electric operations to allow the Company an opportunity to earn its
proposed 9.82 % rate of return on a pro forma basis?
The net operating income deficiency amounts to $22,516,000, as shown on
line 4 of page 2 of Exhibit No. 14. The resulting revenue requirement is shown on line 6 and
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amounts to $35,222,000, or an increase of 24.08% over pro forma general business revenues,
which excludes the PCA surcharge.
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IV.NA TURAL GAS SECTION
On what test period is the Company basing its needs for additional
revenue?
The test period being used by the Company is the twelve-month period ending
December 31 , 2002 presented on a pro forma basis.
What is the Company s Rate of Return that was last authorized by this
Commission for its gas operations in Idaho?
The Company currently authorized Rate of Return for its Idaho gas
operations is 11.02%.That rate comes from Case No. WWP-88-5, which became
effective October 1, 1989. The filing was based upon a 1987 test year.
Have there been any changes to base gas rates in the Idaho jurisdiction
since October 1, 1989?
Yes. Reconsideration of the 1988 case resulted in a minor rate adjustment on
February 17, 1990 in Case No. WWP-89-3. Additionally, a Demand Side Management
Tariff Rider ("Tariff Rider ) was implemented 1995 through 1997 in which a small surcharge
was used to fund energy efficiency improvements. It was reimplemented in 2001. The
Company does have Purchased Gas Adjustments ("PGA") in all of its jurisdictions, including
Idaho, that periodically adjust customer rates for the commodity and transportation cost
associated with procuring natural gas. The PGA rate changes do not impact earnings or
general base rates.
Earlier, in the Electric Section, you performed an analysis of the changes
to Idaho electric net operating income and rate base between the last authorized test
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year and the Company s current filing. Did you perform a similar analysis for A vista'
Idaho natural gas operations?
No. As previously noted, current general gas rates are based upon a 1987 test
year, 15 years prior to the 2002 test year being utilized in this filing. Test periods so far apart
make comparisons difficult and less meaningful. Ultimately, I did perform a similar analysis,
but I based it on changes over the last five years, utilizing the Company s 1998 Commission
Basis, or normalized, natural gas information, and comparing those results to the 2002 pro
forma test year results. The Company provides a copy of the Commission Basis report based
on its Idaho jurisdiction results annually to the Commission Staff.
and 2002?
What have been the Company s experienced earnings levels between 1998
The ROR for 1998 was 7.69%. In 1999 it rose to 9.62% and then has steadily
declined through 2002. For comparison purposes, our official authorized ROR for natural
gas operations in Idaho was 11.02%, but it should be noted that our electric authorized ROR
was updated to 8.98% in 1999. Below is a graph showing the normalized ROR for each year.
12.00%
10.00%
00%
00%
00%
00%
00%
Avista Corp
Rates of Return
Idaho Natural Gis
1998 1999 2000 2001 2002
1 77 Falkner, Di
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Is there one main issue that contributed to the increase being requested?
No. There isn t one single item driving the requested increase. Here again, we
need to be reminded that the last test year was 1987, and virtually everything has changed
since that time period. As it turns out, there are numerous operational factors that have
impacted the Company s natural gas results of operations, even when comparing the current
pro forma analysis to 1998 information.When looking at the results of the analysis
contained in Exhibit No. 15, page 8, it should be noted that our Idaho natural gas operations
is the second smallest operational jurisdiction we operate. Only our 18,OOO-customer gas
system in California is smaller. As a result, many revenue, expense and rate base detail
amounts are small, in the hundreds of thousands, making some percentage changes less
meaningful due to their sensitivity to dollar changes.
On page 8 of my Exhibit No. 15, I've set up a side-by-side comparison of the
Company s 1998 normalized net operating income and rate base with our pro forma levels.
As you can see on line 30, column (d), Net Operating Income has declined $1.2 million or
28% and line 42, shows Total Rate Base has increased $6.4 million, or 11
%.
During this
same time period, average customers have increased 18.18%. The $1.2 million reduction in
net operating income translates into approximately $1.9 million of additional revenue
requirement and the $6.4 million increase in rate base adds an additional $1 million. These
are both factors contributing to the requested $4.8 million of additional general business
revenues.
What are some of the other components of the Company s request?
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Many of the same revenue and expense items that impacted electric operations
also impact the natural gas operations, such as depreciation expense, pension costs, insurance
costs, and to a lesser degree, increases in customer accounting/service/sales costs and
administrative and general expense. A decline in customer usage has also contributed to the
level of the Company s request.
How has the Company s customer base changed since the 1998?
A verage customer count for the Company s Idaho natural gas jurisdiction has
increased from approximately 49 712 to 58,752 at the end of 2002, or an 18.18% increase.
Columns (f) through (i) on page 8 of my Exhibit No. 15 show the same 2002 versus 1998
comparisons on a per customer basis.
Was this increase in customer base accompanied by an associated
increase in total revenues?
As can be seen on line 4, total gas revenues increased $13.9 million, but this
was mostly due to PGA gas cost increases. Line 4a nets total purchased gas costs against
total revenues to estimate gross margin. That figure only increased $585,000 in 5 years,
despite an 18.18% increase in customers. More telling is the gross margin per customer
decline of $40.07 found by moving over to column (h). Since base rates have remained
constant, this indicates energy usage has declined. Mr. Hirschkom has estimated the impact
of the decline in usage by the Company s Schedule 101 customers, residential and small
commercial, to be approximately $1.3 million.
Did you perform any analysis on changes on a cost-per-customer basis?
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Yes I did. Again, referring to page 8 of my Exhibit No. 15, columns (f)
through (i) reflect that analysis, with cost-per-customer changes between the 2002 and 1998
years in dollars per customer (column (h)) and the percentage change in column (i).
What does that analysis show?
Average customers increased 18.18% between 1998 and 2002. Total expenses
by category are relatively small, but lines 25a, Total Operating Expense excluding Gas
Purchased Cost, shows that during the last five years that overall cost-per-customer increased
13%. During this same time period, the Consumer Price Index rose 10.4%. Line 25b goes
a step further and eliminates depreciation and taxes producing just straight operation and
maintenance and administrative and general costs. That shows an increase of 5.3%. Line 42
Total Rate Base, actually declined by approximately 6% on a cost-per-customer basis.
REVENUE REQUIREMENt
Would you please explain what is shown in Exhibit No. IS?
Exhibit No. 15 shows actual and pro forma gas operating results and rate base
for the test period for the State of Idaho. Column (b) of page 1 of Exhibit No. 15 shows 2002
operating results and components of the average-of-monthly-average rate base as recorded;
column (c) is the total of all adjustments to net operating income and rate base; and column
(d) is pro forma results of operations, all under existing rates. Column (e) shows the revenue
increase required which would allow the Company to earn a 9.82% rate of return. Column (0
reflects pro forma gas operating results with the requested increase of $4 754,000.
Would you please explain page 2 of Exhibit No. IS?
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Yes. Page 2 shows the calculation of the $4,754 000 revenue requirement at
the requested 9.82% rate of return.
Would you now please explain page 3 of Exhibit No. 15?
Yes. Page 3 shows the derivation of the net operating income to gross revenue
conversIon factor.The conversion factor takes into account uncollectible accounts
receivable, Commission fees and Idaho State income taxes. Federal income taxes are
reflected at 35%.
Now turning to pages 4 through 7 of your Exhibit No. 15, would you
please explain what those pages show?
Yes. Page 4 begins with actual operating results and rate base for the test
period in column (b). Individual normalizing adjustments that are standard components of
our annual reporting to the Staff begin in column (c) on page 4 and continue through column
(0) on page 6. Individual pro forma and additional normalizing adjustments begin in column
(p) on page 6 and continue through column (t) on page 7. The final column on page 7 is the
total pro forma operating results and rate base for the test period.
STANDARD COMMISSION BASIS ADJUSTMENTS
Would you please explain each of these adjustments, the reason for the
adjustment and its effect on test period State of Idaho net operating income and/or rate
base?
Yes. The first adjustment, column (c) on page 4, entitled Deferred FIT Rate
Base, reflects the rate base reduction for Idaho s portion of deferred taxes. The adjustment
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reflects the deferred tax balances arising from accelerated tax depreciation (Accelerated Cost
Recovery System, or ACRS, and Modified Accelerated Cost Recovery, or MACRS), bond
refinancing premiums, and contributions in aid of construction. The effect on Idaho rate base
is a reduction of $7,261 000.
Column (d), Deferred Gain on Office Building, reflects the rate base
reduction for Idaho s portion of the net of tax, unamortized gain on the sale of the Company
general office facility. The facility was sold in December 1986 and leased back by the
Company. The effect on Idaho rate base is a reduction of $128,000.
Column (e), Gas Inventory, reflects the adjustment to rate base for the
average of monthly average value of gas stored at the Company s Jackson Prairie
underground storage facility and the Plymouth LNG Plant. The effect on Idaho rate base is
an increase of $1,572 000.
Column (0, Weatherization and DSM Investment, includes in rate base
balances (net of amortization) of gas demand side management ("DSM") program costs upon
which AFUCE is no longer being accrued and full amortization was implemented beginning
August 1994. These amounts are a component of actual results of operations. The effect on
Idaho rate base is an increase of $941 000.
Please turn to page 5 and explain the adjustments shown there.
The adjustment in column (g), entitled Customer Advances, decreases rate
base for funds advanced by customers for line extensions, as they will most likely be
recorded as contributions in aid of construction at some future time. The effect on Idaho rate
base is a decrease of $1 000.
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The column marked by a dash, and immediately following column
(g),
subtotals columns (b) through (g) and represents actual operating results and rate base plus
the standard rate base adjustments that are included in Commission Basis reporting, but not
generally calculated in the Company s monthly Results of Operations reports.
Column (h), Eliminate Franchise Fees, eliminates the revenues and expenses
associated with local franchise fees, which the Company is allowed to pass through to its
Idaho customers. The adjustment eliminates any timing mismatch that exists between the
revenues and expenses by eliminating the revenues and expenses in their entirety. Franchise
fees are passed through on a separate schedule, which is not part of this proceeding. The
effect of this adjustment is to increase Idaho net operating income by $34,000.
Column (i), Property Tax, restates the 2002 test period accrued levels of
property taxes to the actual amounts. The effect of this particular adjustment is to decrease
Idaho net operating income by $3,000.
Column G), Uncollectible Expense, restates the accrued expense to the actual
level of net write-offs for the test period. The effect of this adjustment is to increase Idaho
net operating income by $73,000.
Please turn to page 6 and explain the adjustments shown there.
Column (k), entitled Regulatory Expense Adjustment, restates booked 2002
regulatory expense to reflect the IPUC assessment rates applied to revenues for the test
period. The effect of this adjustment is to decrease Idaho net operating income by $4,000.
Column (1), Injuries and Damages, is a restating adjustment that replaces the
accrual with the six-year rolling average of actual injuries and damages payments not covered
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by insurance. A six year rolling average and the reserve method of accounting for injuries
and damages, net of insurance proceeds, is a practical methodology to deal with these normal
utility operating expenses that happen to occur on an irregular basis and differ markedly in
materiality. As a result of the WUTC's Order in Docket No. U-88-2380-T, the Company
changed to the reserve method of accounting for injuries and damages not covered by
insurance for both its electric and gas systems. This methodology was accepted by the Idaho
Commission in Case No. WWP-98-11. The effect of this adjustment is to increase Idaho
net operating income by $53,000.
Column (m), FIT is required to reflect the appropriate level of federal income
tax expense for the test period. This adjustment removes the effect of certain Schedule M
items, matches the jurisdictional allocation of other Schedule M items to related Results of
Operations allocations and eliminates any prior period income tax expense. This adjustment
also reflects the proper level of deferred tax expense for the test period. The effect of this
adjustment, all based upon a Federal tax rate of 35%, is to decrease Idaho net operating
income by $71 000.
Column (n), Restate Debt Interest, restates debt interest using the
Company s pro forma weighted average cost of debt, as outlined in the testimony and
exhibits of Mr. Malquist, and applied to Idaho s pro forma level rate base, produces a pro
forma level of tax deductible interest expense. The Federal income tax effect of the restated
level of interest for the test period decreases Idaho net operating income by $576,000.
Column (0), Payroll Clearing, adjusts the payroll loading costs (benefits,
payroll taxes and paid time oft) expensed through a clearing account during the test period
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2002, to the actual payroll loading costs for the test period. The amounts loaded onto labor
charges through the estimated payroll loading rates during the 2002 test period produced an
expense level lower than the actual amount of employee benefits incurred for the test period.
The impact of this true-up to actual on the Idaho gas jurisdiction decreased net operating
income by $70,000.
PRO FORMA ADJUSTMENTS
Please explain the significance of the 5 columns subsequent to column (0)
that begin on page 6 in your Exhibit No. 15.
Certainly. The adjustments subsequent to column (0) are either additional
normalizing adjustments or pro forma adjustments that recognize the jurisdictional impacts of
material items that will impact the pro forma operating period levels for known and
measurable changes. In this case, they encompass only revenue and expense items, as there
were no significant natural gas capital projects. These adjustments bring the operating results
and rate base to the final pro forma level for the test year.
Please continue with your explanation of the adjustments on page 6.
Column
(p),
entitled Revenue/Gas Supply Adjustment is a 3-fold
adjustment taking into account known and measurable changes that include revenue
normalization, which reprices customer usage under present effective rates, as well
weather normalization and an unbilled revenue calculation. Associated gas costs are replaced
with gas costs computed using normalized volumes at the currently effective "weighted
average cost of gas," or W ACOG rates. Revenues associated with the Schedule 191 Tariff
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Rider are excluded from pro forma revenues, and the related amortization expense is
eliminated as well.Mr. Hirschkom is sponsoring this adjustment.The effect of this
particular adjustment is to decrease Idaho net operating income by $112,000.
Please turn to page 7 and explain the adjustments shown there.
Column (q), entitled Pro Forma Pension, updates the 2002 pension expense
to the expense accrual being recorded for 2004. Pension expense, on a system basis, was
$9.4 million during the 2002 test year and has increased to $14 million for the year 2004.
The issues and detail associated with the pension cost increases were outlined earlier in my
Electric Section testimony. Pension costs follow labor charges, so a specific Idaho gas labor
analysis was performed. To be conservative and reduce complexity, this adjustment only pro
forms in the impact of increased pension costs on labor charged to operating expense
accounts, not capitalized labor s impact on rate base. Pension costs that are properly charged
to non-utility labor costs have also been excluded from this adjustment. The effect of this
adjustment decreases Idaho net operating income by $109,000.
Column (r), Pro Forma Insurance, updates the 2002 insurance expense for
general liability, directors and officer liability, property insurance and other policies, to the
actual cost of all signed ongoing and renewed policies providing insurance for 2004.
Insurance costs are mainly expensed at a system level and allocated to electric and gas, so the
issues and detail associated with the insurance cost increases that were outlined earlier in my
Electric Section testimony apply here as well. Insurance costs that are properly charged to
non-utility operations have been excluded from this adjustment. The effect of this adjustment
decreases Idaho net operating income by $131,000.
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Column (s), Pro Forma Labor-Non-Exec, reflects known and measurable
changes to test period union and non-union wages and salaries, and excludes executive
salaries, which are handled separately in the next adjustment. Test period wages and salaries
are restated as if the wage and salary increases for 2002, 2003 and 2004 were in place during
the entire pro forma test period. The methodology behind this adjustment is similar to that
used in the last Idaho general case, Case No. WWP-98-11, except for the separate
treatment of executive salaries. The effect of this adjustment on Idaho net operating income
is a decrease of $174 000.
Column (t), Pro Forma Labor-Executive, reflects known and measurable
changes to executive compensation. During 2002 and 2003 several executives retired, a new
chief financial officer was hired and responsibilities were re-assigned among the executive
group. The compensation level in this adjustment is for the current executive team only.
Compensation for any member of the 2002 officer team who has since left the Company has
been removed from the test year by this adjustment. Compensation costs allocated to non-
utility operations are excluded as executives routinely charge a portion of their time to non-
utility operations, commensurate with the amount of time spent on such activities. The
current executive group s salary allocations are set at their expected pro forma test period
utility/non-utility percentage splits. The impact of this adjustment on Idaho net operating
income is a decrease of $8,000.
The last column on page 7, Pro Forma Total, reflects total 2002 pro forma
results of operations and rate base consisting of 2002 actual results and the total of all
standard and pro forma adjustments.
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Referring back to page 1, line 43, of Exhibit No. 15, what was the actual
and pro forma gas rate of return realized by the Company during the test period?
For the State of Idaho, the actual test period rate of return was 6.26%. The test
period pro forma rate of return is 5.00% under present rates. Thus, the Company does not, on
a pro forma basis for the test period, realize the 9.82% rate of return requested by the
Company in this case.
By way of summary, could you please review the different rates of return
that you have presented in your testimony?
Yes. Basically, there are three different ROR's discussed previously. The
actual ROR earned by the Company during the test period, the Pro Forma ROR determined in
my Exhibit No. 15 and the requested ROR. For convenience of comparison, please refer to
the following graph:
Avista Corp
Rates of Return
12.00%
10.00%
00%26%
00%
00%
00%
00%
Actual
82%
Pro Fonna Request
How much additional net operating income would be required for the
State of Idaho gas operations to allow the Company an opportunity to earn its proposed
82 % rate of return on a pro forma basis?
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The net operating income deficiency amounts to $3,039,000, as shown on line
, page 2 of Exhibit No. 15. The resulting revenue requirement is shown on line 6 and
amounts to $4 754,000, or an increase of 9.16% over pro forma general business and
transportation revenues.
ALLOCA TION PROCEDURES
Have there been any changes to the Company s system and jurisdictional
procedures since the 1998 Case No. WWP-98-
No. For ratemaking purposes, the Company must allocate revenues, expenses
and rate base between electric and gas services and between Washington, Idaho, Oregon and
California jurisdictions where electric and/or gas service is provided.The current
methodology was implemented at the start of 1994 and has not changed. As a result of earlier
reviews, the Staff has found that the allocation system was being applied properly and
produced the proper allocation of financial data. Also as part of earlier reviews, Staff has
stated that the Company s rate base was properly allocated between jurisdictions.
VI.ADVANCED METE~ READING PROJECT ACCOUNTING PROrOSAL
As previously testified by Mr. Holmes, Avista is introducing a proposal
for implementation of Advanced Meter Reading ("AMR") for its Idaho customers.
Does the Company have a proposal for how to account for this project?
Yes it does. As was noted by Mr. Holmes, the Company proposes to install
AMR devices on all Idaho electric and natural gas meters over a four-year period
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commencing January 2005. The project will involve the installation of additional electronics
for existing meters as well as other communication infrastructure, and finally computer
hardware and software investment.
Due to the multi-year nature of this project, as well as the Company s desire to be
able to measure and analyze both the costs and benefits of the entire project, we propose to
treat AMR investment costs as a unique construction project. All capital investment would
follow our standard capitalization policy and be capitalized to construction work in progress,
FERC account 107, until the entire AMR project becomes operational, or used and useful.
that point, the project will be unitized into the appropriate FERC plant accounts, depreciation
would begin and the investment would receive rate base treatment in regulatory filings.
Why are you making this an accounting proposal in this filing?
There are some segments of the capital investment included in this project,
specifically electronic upgrades to existing meters, and/or new meters, that an argument can
be made for immediate inclusion in plant-in-service. That would mean earlier inclusion in
rate base and initiation of depreciation. However, the actual AMR project would not be
completely" used and useful, at least as the whole project is defined, until some 4 years or so
after the project initially begins. Keeping the capital costs bundled, as a single construction
work in progress item, will facilitate easier tracking and analysis of all the aspects of the
Idaho AMR program.Any slight differences in "vintaged" depreciable lives and asset
balances between immediate inclusion into plant-in-service and this proposal should not be
material. The Company requests approval from the Commission to account for the AMR
project as described above.
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Does this conclude your pre-flied direct testimony?
Yes.
191 Falkner, Di
A vista Corporation
INTRODUCTION
Please state your name, business address, and present position with
A vista Corp.
My name is Don M. Falkner. My business address is 1411 East Mission
Avenue, Spokane, Washington. I am employed by Avista Corp., doing business as Avista
Utilities vista" or "Company ) and my current position is Manager of Revenue
Requirements in the Department of State and Federal Regulation.
Have you previously provided direct testimony in this Case?
Yes. My testimony covered accounting and financial data in support of the
Company s need for the proposed increase in rates. I explained pro formed operating results
including expense and rate base adjustments made to actual operating results and rate base.
Are you sponsoring any exhibits to be introduced in this proceeding?
Yes. I am sponsoring Exhibit Nos. 26 and 27, which were prepared under my
supervision and direction.
What is the scope of your rebuttal testimony in this proceeding?
I will be providing a summary of the Company s revised revenue requirement
as well as introducing certain other aspects of the rebuttal testimony sponsored by other
Company witnesses. My rebuttal testimony and exhibits will consolidate the Company
rebuttal position on all the general case revenue requirement adjustments proposed by Staff
witnesses which impact the Company s proposed results of operations.I will list the
adjustments proposed by Staff that the Company is willing to accept for purposes of this case
and will address other proposed adjustments with which the Company does not agree. I will
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also address the comments of Potlatch witness, Dr. Peseau, regarding the test year utilized in
this filing.
II.OVERALL COMPANY REBUTTAL CASE INTRODUCTION
Would you please introduce the other Company witnesses that are
sponsoring rebuttal testimony and note the issues that each will be addressing?
Certainly. For context, with the exception of Mr. Jon Powell, all the following
Company witnesses have previously provided direct testimony in this proceeding. Dr. Avera
will be addressing Staff and Intervenor proposals regarding the appropriate Return on Equity
ROE") for the Company s Idaho utility operations. The Company maintains, through Dr.
Avera s testimony, that the initial recommended 11.50% ROE is appropriate given the unique
circumstances attendant to A vista.
Staff has proposed for purposes of this case that the capital structure and cost of
capital components, other than ROE, should be the embedded December 31 , 2003 actual
levels.The Company concurs, for purposes of this case, that this is a reasonable
recommendation based upon a review of the appropriate utility peer group. The resulting
requested authorized Rate of Return, utilizing the cost of capital components recommended
by Staff witness Ms. Carlock, with the exception of the Company s continued recommended
11.50% ROE, is 9.72%.
Mr. Lafferty will address Potlatch recommendations on the recoverability of the
Company s CS2 investment, Staff recommendations on small generation proj ect Boulder
Park investment recoverability, and Staff and Potlatch recommendations regarding the
appropriate regulatory treatment of the cost of purchased gas contracts listed in previous
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direct testimony as "Deal A and Deal B." The Company s position remains that the costs
associated with the Deal A and Deal B contracts were prudent at the time and should
ultimately be recoverable through the Idaho PCA mechanism.Mr. Lafferty s rebuttal
testimony, in response to Dr. Peseau and Mr. Hessing, supports the reasonableness of the
costs associated with Deal A and Deal B, and explains that the transactions were consistent
with the Company s planning criteria.
Mr. Kopczynski will address the comments and recommendations by Staff regarding
customer service and Company Call Center operations, as well as responding to the Staff s
adjustment to pro fonna vegetation management costs.
Mr. Powell, Avista s Demand Side Management Program Manager, will address Staff
and Intervenor proposals regarding Demand Side Management programs and low income
pro gram funding.
Ms. Knox will address Intervenor proposals associated with Cost of Service
assignment and allocation issues.
Finally, Mr. Hirschkom will respond to Staff and Intervenor testimony regarding rate
spread and rate design. He will also provide guidelines that can be used by the Commission
to implement rate spread and rate design, regardless of the approved level of revenue
requirement.
III.COMBINED REVENUE REQUIREMENT SUMMARY
What are the Company s. revised revenue requirements, for both the
electric and natural gas operating systems for its Idaho jurisdiction, after taking into
account Staff's proposed adjustments that have been accepted by Avista?
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After taking into account the Company s acceptance of several of the Staff s
proposed revenue requirement adjustments, the Company revised electric revenue
requirement is an increase of $31 070 000, or 21.24%, as detailed in Exhibit No. 26. This
should be compared with the original request for an increase of $35 222 000, or 24.08%.
The Company s revised gas revenue requirement is an increase of $4 061 000, or
82%, as outlined in Exhibit No. 27. This should be compared with the original request for
an increase of $4 754 000, or 9.16%.
On a stand-alone basis, the overall electric percentage request is 21.24%, but after
taking into account the Company s original proposed reduction to the power cost surcharge
currently in effect, the overall electric increase would be 8.6%, down from the 11.
originally filed.
IV.ELECTRIC SECTION
UNCONTESTED ADJUSTMENTS
With which adjustments proposed by Staff does the Company concur?
The Company concurs with the following adjustments proposed by Staff that
are noted by Staff direct column identifier and then followed by the column identifier that I
utilized in my ExhibitNo. 26:
Cabinet Gorge E21 ak (estimate updated to actual)
Boulder Park Depr E3/al (depr synchronized between states)
Skookumchuck E5/am (sale approved by IPUC 4/28/04)
Deferred FIT E6/ an (appropriate deferred accounting treatment)
Coyote Springs E7/ao (estimate updated to actual)
Small Gen Options E81 ap (similar treatment to other unfinished plant)
Labor-Non-exec E9/aq (estimate updated to actual)
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Lab or- Exec EI0/ar (estimate updated to actual)
Depreciation E 14/as (depr synchronized between states)
Corp Fees El5/at (similar treatment for other Idaho utilities)
Misc Exp El7/au (similar to prior IPUC treatment)
WECC Exp El8/av (reflects current WECC status)
Adv. Exp El9/aw (similar to prior IPUC treatment)
A vista Foundation E20/ax (correctly assigned to non-utility)
By accepting the adjustments proposed by Staff above, the Company s revised revenue
requirement is reduced from $35 222 000 to $31 070 000, or $4 152 000.
CONTESTED ADJUSTMENTS
Could you please list the various electric revenue requirement
adjustments (other than cost of capital) that are still at issue from the Company
original filing; in doing so, please note the impact of Staff's recommended adjustment
to Net Operating Income ("NOI") and Rate Base as compared to the Company
original filing.
Certainly. Please see the table below. Since the revenue requirement items
still at issue have been recommend by Staff, for convenience, I will be using the Column
references that can be found in the Staffs summary exhibit sponsored by Ms. Patricia Harms.
COL
Electric Adjustments Still at Issue
(Dollars are in thousands)
DESCRIPTION Staff
Rate Base
$(8,518)
(1,085)
Staff
NOI
$230
288
357
554
366
Ell
E12
E13
E16
E2l
Transmission
Boulder Park Disallowance
Vegetation Management
Accts. Rec. Fees
Pension Expense
Legal Expenses
Restate Debt Interest
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Transmission
. On pages 8 through 11 of Ms. Harms' direct testimony, the Staff
recommends that the full test year level of costs associated with the Company s recent
transmission investment, as filed by the Company, be reduced to reflect only one month
of service for average rate base purposes. Do you agree with Staff recommendation
regarding the Company s transmission upgrades?
No.The portion of the Company current multi-year upgrade to our
transmission system that we included in our general filing has already been completed and
moved to plant-in-service. It is known and measurable and currently providing service to our
customers.
The reasons for which the Company has undertaken the transmission upgrade
projects, outlined by Mr. Kopcyznski in his direct testimony, are valid and have not been
refuted by any party in this proceeding. At the same time, no parties have submitted that the
investment included in the Company s filing is imprudent. For these reasons alone, the
investment should be included in rate base for a full 12 months.
How does the Company respond to Staff's contention, that by not
including any reduced costs or increased revenues associated with the investment, the
filing does not provide proper matching of cost and benefits (Harms, Di, pg 8, II 15-19)?
The financial benefits of being able to maintain our ability to import and
export energy, either through secondary sales or through transmission capacity revenue, are
captured in the Company s power supply model. Additionally, had the Company not moved
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to improve our 230 kV capabilities, there was the potential of "Hydro Caps" being imposed
by the Bonneville Power Administration at the Company s Cabinet/Noxon hydro electric
facilities. In other words, we could have been put in the situation of having to reduce
generation during certain times of the year, specifically during spring runoff. The financial
benefits of being able to continue to optimize the generation capabilities of the Clark Fork
proj ects are also captured in the Company s power supply model.
On pages 10 and 11 of Ms. Harms' direct testimony starting on line 8,
Staff has proposed an alternative regulatory treatment that would allow full rate base
treatment of the Company s transmission, while imputing an estimated level of
increased electric revenues and reduced maintenance costs. What is the Company
position regarding the Staff's proposed alternative transmission investment treatment?
Staff notes that this alternative treatment is consistent with the methodology
identified in Commission Order No. 29505, from Idaho Power Company s recent general
case, Case No. IPC-03-13. Ms. Harms goes on to state
Although this methodology does not provide precedential value, it offers
the Commission the option to include new transmission investment in rate
base while protecting customers from inequities of a mismatch.
We note that this Order was issued in May 2004, approximately 3 months after the
Company had made its February 2004 general case filing. Despite the Company s continued
stance that the transmission upgrades are currently used, useful, known and measurable and
provide customer benefits that are included in the Company s power supply model, if the
Commission were to determine in this case that an adjustment to revenues and/or expenses in
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conjunction with the full rate base treatment of the new transmission adjustment was
necessary, Stafsf proposed alternative of including approximately $270 000 in additional
revenues and an expense maintenance reduction of$30 000 would be reasonable. The Staffs
recalculated rate base of $7 801 000 also correctly incorporates the updates for actual capital
costs and the change in depreciation rates. (Harms, Di, pg. 10, 11. 8-25).
Veeetation Manaeement
On pages 12 through 14 of Ms. Stockton s direct testimony, the Staff lays
out their recommendation to reduce the Company s proposed Vegetation Management
expense level to a 6-year average of historical expenditures. Do you agree with the Staff
recommendation?
No. The testimony provided by Mr. Kopczynski supports the utilization of the
four-year average for 2004 through 2007 tree trimming expenditures recommended by our
Vegetation Management director. As he explains, vegetation management is important to
system reliability. Proper vegetation management reduces customer outages, improves safety
and enhances system reliability.
How would the Company propose to address the concerns noted by Ms.
Stockton in her direct testimony suggesting that the Company may not actually
dedicate the resources towards future vegetation management?
In response to the Staff s concerns, the Company recommends the use of a
one-way" balancing account. If the Commission were to authorize the level of vegetation
management costs outlined in our direct case, $1 771 000 for Idaho electric operations, the
Company would agree to commit that level of resources on an annual basis to vegetation
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management going forward. If the Company were to spend less than the level noted above
the difference would be recorded as a liability and either spent in a future period, or returned
to customers through an appropriate tracking mechanism.
What would happen if the Company expended more than the $1,771,000
in vegetation management costs for Idaho electric operations?
Unless the Company was making up for a prior period of reduced spending,
the Company would absorb that difference as a period cost. It would not be tracked.
Implementation of the Company s proposal would ensure that the revenues collected for
vegetation management would be spent for that purpose, or returned to customers.
Do you have any comments regarding Staff's specific proposal to use a 6-
year historical average?
Yes. In some instances a multi-year average may be appropriate, as long as all
the years are reasonably representative of what ongoing expenditures might be. In this case
even Staff notes that 2002 vegetation management costs were "abnormally low." (Stockton
, page 12, 11 24-25). In fact, the 2002 level of $550 255 is not even half of the 6-year
average of $1 322 000 calculated by Staff. If the Commission adopts a multi-year historical
average, the actual 2002 level should be excluded.
What level of vegetation management expense would result by modifying
Staff's proposal through exclusion of the 2002 period from the average?
The result would be $1 477 000 for Idaho electric operations, as compared to
Staffs proposed level of$1 322 000.
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Accounts Receivable Fees
Do you agree with Staff recommendation regarding the Company
Accounts Receivable Fees?
Would you please comment on Ms. Stockton s proposal to remove the
fees associated with the Company s Accounts Receivable Sale Program?
Staff witness Stockton, at page 14, beginning at line 7 discusses the Staff s
proposal to remove fees associated with the sale of customer accounts receivable. As Ms.
Stockton points out in her testimony, the sale was initiated in 1988 and reduced the
Company s need for financing. The Commission has allowed the fees as a recoverable
expense previously.
The Account Receivable Sale program is a cost effective approach of funding the cost
of carrying customer receivables on the Company s balance sheet. The alternative to selling
the accounts receivable would be a working capital addition to rate base at the Company
authorized rate of return.
Staff states that they have calculated working capital for the Company and that it is
negative. Then Staff concludes, at page 15 , lines 16 through 20 of Ms. Stockton s testimony,
that
, "
Because the Company asserts that the Accounts Receivable Sale Program is
substitute for a working capital requirement and the Company does not have a working
capital requirement, I have removed the fees associated with the Accounts Receivable
Program.
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Have you reviewed Staff's working capital workpapers and what have
you found?
Staff s workpapers show that working capital is in fact. positive.not negative.
Hence, the Staffs argument for removing the fees associated with the accounts receivable
sale is not valid. Also, the workpapers show that Staff included the accounts receivable sale
as a reduction to working capital. It is not proper to include the accounts receivable sale as a
reduction to working capital in determining whether working capital is positive. Working
capital should be calculated without the reduction for the accounts receivable sale. If the
result is positive working capital and the positive amount exceeds the accounts receivable
sale amount, then including the fees associated with the accounts receivable sale as an
operating expense is appropriate. Staffs workpapers show that working capital is, in fact
positive by an amount that exceeds the accounts receivable sale amount.
The purpose of my testimony is not to engage in a debate about working capital or the
individual components of working capital. The Company has not included a working capital
adjustment in the past due to the complexity of doing such a study and the fact that the
Commission has historically otherwise allowed the fees associated with the accounts
receivable sale as a recoverable operating expense. Staff has misinterpreted the results of
their working capital study.The Commission should continue to allow the fees as a
recoverable operating expense.
Pension Expense
Could you please briefly describe the Company s request in this case for
pension expense?
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In my direct testimony (Falkner, Di, pg 24 11. 11 pg. 25 11. 6), I outlined the
Company s request in this case to allow for recovery of the Company s 2004 recorded
pension expense accrual of $14 million, or $2.1 million to the Idaho electric jurisdiction, as
detennined in accordance with Financial Accounting Standard 87 ("F AS-87"This
compares to Staffs recommendation for a pension expense level of $8 695 000, or
301 921 to the Idaho electric jurisdiction.
Would you please list the main arguments supporting the Company s use
of the FAS-87 pension accrual, and why the Staff's proposal should be rejected?
Certainly. The following bullet points outline the points I will be making:
F AS-87 has been the standard for pension expense calculations since its adoption in
1987.
It has been previously accepted for regulatory purposes in all of Avista s service
territories, including Idaho.
The reduction of the return on asset assumption is supportable by actual fund return
history, as well as consistency with return reductions by other Northwest utilities.
Actual Company contributions to the pension fund have exceeded the level included
in Idaho general rates by $29 million since 1999.
Absent a larger than minimum contribution in 2002, the 2003 minimum contribution
level would have been approximately $14 million, which is the F AS-87 accrual level
being proposed in this case.
How long has the Company been following F AS-87 in determining its
pension expense amount to be included in customer rates?
The Company has been calculating and recording pension expense according
to FAS-87 since its required implementation date of January 1987.
Was pension expense, as calculated in accordance with FAS-87 financial
reporting rules, accepted for regulatory purposes in the Company s last Idaho general
rate case?
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A vista Corporation
Yes. That was the accepted methodology utilized in the last Idaho general
case, electric case WWP-98-ll. F AS-87 was developed after a long period of review by
the accounting profession. Since it has also been adopted by the Securities and Exchange
Commission, it is the standard applied by all companies, including regulated utilities, for
financial reporting. The fundamental objective of F AS-87 is to recognize the compensation
cost associated with pension benefits over employees ' approximate service lives. As such, it
has been utilized and accepted in previous general filings in all our regulatory jurisdictions.
Similar to other expense items that are accrued for accounting purposes, this standard
requires the use of some assumptions to measure the Company s pension obligations and
annual expense: Assumptions that individually reflect best estimates and are consistent to the
extent that each reflects expectations of the same future economic conditions. These
assumptions include determinations for such items as future return on fund assets, an
appropriate discount rate, and compensation increases, each of which is reviewed annually,
and if necessary, adjusted to reflect updated information.
In determining Avista s pension plan expense, the Company uses an 80/0
actuarial assumption of future rates of return on assets in determining its estimated
pension expense. Can you please explain the 80/0 ROA assumption, and compare this to
the 3.880/0 rate referred to by Staff Witness English?
Yes. The assumption of an 8% return on assets ("ROA") used for determining
our 2004 pension expense was based on long-term expected pension fund returns taking into
account our plan portfolio mix. The 3.88% referred to by Witness English (English, Di, page
11. 7-10), was only incorporated to aid in forecasting pension plan assets in order to
Falkner, Di - Reb
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204
detennine the appropriate level of cash contributions the Company should make to the
current plan year. It was not used in the calculation of detennining pension expense to be
recorded on Company books in 2004.
In 2002 the Company lowered its ROA from 10 to 8%. Could you please
explain the Company s reasoning behind the decision to lower the plan ROA
percentage?
In 2002, the company lowered its ROA percentage from 9% to 8%. This
decision was made in conjunction with a review of our historical returns, advice from
external advisors, and our external auditors. This change was in line with changes seen
throughout the utility industry and other publicly listed companies. At this same time, the
Securities and Exchange Commission communicated to the financial community that they
were concerned about ROA assumptions used in publicly listed company filings. As shown
below in Graphs 1 and 2 below, for March 31 2003 and December 31 2001 , respectively,
virtually all of the Northwest utility companies lowered their ROA assumptions from their
existing levels in 2001.
Gra ph 1
FAS 87 Assumptions
Northwest Utilities Return On Assets
as of March 31 , 2003
1 O. 00%
50%
00%00%
50% Average=8.39%50%
8. 00%
50%
00%
00%
205
mAvista Corp.
. Cascade Natural Gas
0 IDA CORP, Inc.
0 Northwest Natural Gas
. Pacificorp
m:J Portland General Bectric
. Puget Energy
Falkner, Di - Reb
A vista Corporation
Graph 2
FAS 87 Assumptions
Northwest Utilities Return On Assets
as of December 31 , 2001
1 0.00%
50%
00% 9,00%
A verage=9.11 %50%
00%
50%
8. 00%
50%
00%
Witness English states that at the time of the "assumption" change to
mJAvista Corp.
. Cascade Natural Gas
0 IDA CORP, Inc.
0 Northwest Natural Gas
. Pacificorp
8 Portland General Bectric
. Puget Energy
lower the plan ROA to 80/0, the Company s actual pension fund average return (since
1995) was approximately 100/0. Could you please explain this?
Yes. Mr. English, without any real explanation, used a 9-year average (1995-
2003), which resulted in a 9.23% ROA for the period, which I am assuming was rounded to
10%. If Mr. English had instead used a 10-year average ending with our test period (also
ending in the year the assumption change was made (1993-2002)), the resulting average ROA
would have been 7.22%. In order to include known and measurable changes, using a 10-year
average ending in 2003 (1994-2003), the 10-year average "actual" ROA is 8.28%. Either
calculation, in combination with external advice and SEC concerns, supports the Company
decision to reduce the ROA assumption, and that an actuarial 8% ROA assumption is
reasonable.
Stafrs position is that the appropriate pension expense amount to be
included in customer rates "in this case" should be determined by the minimum amount
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the Company was legally required to contribute to the plan versus the F AS-87 expense
level. Do you agree with this?
No. But in fairness, Mr. English is not recommending this as a "strict policy.
Rather he goes on to state that
Given the speculative nature of pension contributions, I believe it is wise
for the Commission to reserve some discretion in detennining amounts to
be recovered through rates based on the individual facts and circumstances
of each case." (English, Di, pages 9 and 10, starting on 1122).
Could you please discuss the contributions historically made to the
Company s pension plan and compare this to the minimum contribution calculation
required to be paid by the Company?
Yes, as described by Mr. English, the minimum contribution is the amount
that a company must fund in order to avoid a funding deficiency in the Funding Standards
Account. (English, Di, page 8, 111-
Historically, prior to 2002, A vista made the minimum required contributions to its
plan. Starting in 2002, due to expectations of higher annual required minimum contributions
extending for the next several years, A vista took a proactive approach by contributing more
than the minimum in order to smooth future cash outlays and to achieve a fully funded
pension plan incrementally over time. For example, as shown in Table 1 below, in 2002 the
Company s estimated calculation for the minimum contribution showed a steady increase in
future contributions.
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Table 1 - Estimated as of 2002 (millions)2002 2003 2004 2005 2006 Total
Estimated Minimum Contribution Requirement $7.$14.$13.$15.$17.$68.
Shown below in Table 2 are the actual contributions for 2002 and 2003 , planned
contributions for 2004, and updated estimated minimum contributions required going
forward.
----
A CTU AL PMTS----
------
ESTIMA TED MIN
----
Table 2 - as of 2004 (millions)2002 2003 2004 2005 2006 Total
Contribution $12.$12.$15.$11.2 $17.$67.
Mr. English states at page 8, lines 18-23 that he proposes a reduction to
the Company s proposed pension expense amount (utilizing FAS-87 requirements) of
$14 million to approximately $8.7 million, calculated as the Company s minimum
required contribution for 2003 (utilizing "ERISA" requirements).How does this
compare to the tables described above?
The $8.7 million as described by Mr. English was the amount estimated
2003 as the minimum contribution to be paid in 2003. However, that 2003 minimum amount
was only determined (in 2003) at that level after Avista had already contributed more than the
minimum required amount in 2002, or an additional $4.5 million in 2002 ($7.5 minimum +
$4., totaling $12 million actual payment).
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What was the impact of Avista s higher than minimum 2002 pension
contribution on the minimum required 2003 contribution that Staff is recommending
for inclusion for recovery in rates in this case?
The minimum contribution amount required in 2003 was reduced from
$14 million to $8.7 million, (down approximately $5.3 million from the original estimate
calculated in 2002), because the Company contributed $4.5 million more than the minimum
contribution in 2002.In other words. absent the Company larger than minimum
contribution in 2002. the minimum contribution required for 2003. would have been $M
million.
If Avista had not made a larger than minimum required pension fund
contribution in 2002, pursuant to ERISA rules, would the 2004 FAS-87 expense level
being proposed by the Company and the 2003 minimum contribution being proposed
by Staff both have been approximately $14 million, on a system basis?
Yes
Have the actual cash contributions made over time by Avista to the
employee pension fund been more or less than the system level of F AS-87 pension
expense included in Idaho customer rates through 2004?
During that time period, cash contributions have exceeded expense included in
rates by approximately $29 million.
Would you please explain why the Company still believes the pension
expense calculation required by F AS-87 is the appropriate methodology for
determining pension expense in this proceeding?
Falkner, Di - Reb
A vista Corporation
209
A vista has been calculating and recording pension expense according to F AS-
87 since its required implementation date of January 1987. FAS-87 was developed over a
long period of review and has been consistently applied annually across multiple industries
including the energy sector, since its inception. This Commission as recently as 1999
accepted it for regulatory purposes for Avista and it is the same methodology being utilized
in our other contiguous jurisdictions. Minimum contribution calculations can be impacted by
any contributions paid by A vista above the minimum, thus penalizing the Company for
pro actively attempting to fully fund its plan incrementally over time in order to smooth
payments, or head off larger future payments.
Based upon my earlier discussion, the Company s decision to lower the ROA
assumption was reasonable, and consistent with the actions of other Northwest utilities.
Comparisons between the FAS-87 pension expense level included in Idaho customers' rates
and the level of cash contributions to the pension plan since 1999 show that Idaho customers
have not been disadvantaged. No evidence has been introduced that future cash contributions
will be materially different than the F AS-87 level of pension expense being proposed by the
Company in this case.
Leeal Expense
Staff Witnesses Harms and English sponsor adjustments to legal
expenses, arguing that such expenses should either have been directly assigned to
unregulated affiliates or were otherwise for extraordinary, non-recurring events.
Would you please respond?
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Yes. In total, this adjustment, according to Staff Witness Hanns, would
increase Idaho electric net operating income by $366 000 and reduce the Company s electric
revenue requirement by $573 000. (Hanns, Direct Test. at page 21 , lines 2-14) (Similar
adjustments were made to increase gas net operating income by $13 000 and decrease the
Company s gas revenue requirements by $20 000.) Staff Witness English further elaborates
on the components of the adjustment: As shown in his Exhibit 123 , he removed $14 035
from test year legal expense, as it relates to A vista Labs, and another $1 326 of expense
related to A vista Communications, arguing that these expenses relate to activities of a
subsidiary and should be disallowed. (English, Direct Test. at page 18 , lines 15-25). With
respect to these two adjustments, the Company does not disagree; they were inadvertently
included in utility results of operations and should be removed.
The Company does take issue, however, with the balance of this adjustment to legal
expenses. Mr. English further removed $74 363 in legal expenses allocated to Idaho that the
Company incurred during the bankruptcy proceedings of Enron Corp. He acknowledged that
those expenses "were prudently incurred " but maintains that they were an "extraordinary
expense that the Company will not incur beyond the test year." (Id., at page 19, lines 1-7).
Similarly, Mr. English removes $478 000 in legal expenses relating to FERC's investigation
into Avista s trading practices. Here again, Mr. English agrees that these expenses may have
been "prudently incurred " but reasons that the investigation has been completed and these
expenses are "not likely to recur beyond 2003." (Id., at page 19 , lines 8-14.
Why does the Company take issue with Stafrs disallowance of the legal
expenses relating to the Enron bankruptcy and the FERC investigation?
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A vista Corporation
211
By way of further explanation, the legal expenses associated with the Enron
bankruptcy were incurred in order to protect the interest of Avista s customers. Avista
incurred expense in arriving at settlements with Enron affiliates over power and gas
contracts, as a result of Enron s bankruptcy proceeding and the need to preserve Avista
claims. Similarly, A vista actively participated in FERC's investigation into trading practices
which investigations ultimately "cleared Avista of any wrongdoing," as recognized by Staff
Witness English. (Id., at page 20, lines 1-13). Therefore, Staffhas raised no concerns about
whether these expenditures were either necessary or prudent only that they maybe non-
recurring or extraordinary.
The real question should be whether these expenses were part of a larger pool of legal
expenditures that reflect a representative level of ongoing legal expense. (Indeed, unlike
widgets'" every item of litigation could be argued , in the extreme, to be unique unto itself
and non-recurring; it would, however, be nonsensical to remove all legal expenses, nor does
Staff so contend.) What we do know is that, through time, the Company will continue to
incur some level of representative legal expense that covers a multitude of matters.
Therefore, absent a showing of imprudence (of which there is none here) a representative
level of expenses should be reflected in rates.
Have you analyzed what would constitute a "representative level of legal
expense" over time?
Yes, we have. Included below is a tabulation of legal expenses charged to
operating expense accounts from 1998 through 2003 (on a "system" basis).
Falkner, Di - Reb
A vista Corporation
212
000 000
000,000
000 000
000,000
000 000
Legal Fees by Year
Operational Expense only
1998 1999 2000 2001 2002 2003
What is especially noteworthy is that the overall level of expense has remained
constant through time, with little fluctuation from year to year, notwithstanding the
incurrence of expenses relating to the FERC investigation and the Enron bankruptcy. Stated
differently, it cannot be said that A vista does not experience a recurring level of legal expense
of approximately $3.8 million per year (system).
Would the Company agree to use a six-year average of legal expenses
charged to operational accounts, in order to "smooth out" any extraordinary items?
Yes. To do so would be consistent with the existing practice of using a six-
year average for "injuries and damages.Utilizing the amounts from the tabulation above
the six-year average is $3 803 000 at a system level, while the 2002 test year level was
870 000. The Company s weighted Four Factor allocation levels for 2002 are 25.48% for
electric and 5.69% for natural gas. Using the "Four Factor" allocators for 20021 would
produce allocated Idaho reductions to legal expenses of $17 100 and $3 800 for the electric
1 Idaho Electric weighted Four Factor - 25.48% / Idaho Natural Gas weighted Four Factor - $5.69%.
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and natural gas systems, respectively. Combining this adjustment for the use of a 6-year
average, with the incorrectly assigned payments for Avista Labs ($14 035-Electric, $3 136-
Gas) and Avista Communication ($1 326-Electric, $303-Gas), noted earlier, would make the
Idaho allocated reductions to legal expense $32 500 and $7 239 for the electric and natural
gas systems, respectively.
Test Year Discussion
Would you please comment on Dr. Peseau s contention at pages 29
through 33 of his direct testimony, that there is a mismatch between revenues and
expenses in this case?
Yes. Dr. Peseau s contention is unfounded. Avista s adjustments included in
this case meet the standard ratemaking procedures that have been historically adopted by the
Commission and followed by A vista in this case and previous cases. The Commission
recent Order No. 29505 in Case No. IPC-03-, dated May 25, 2004, in the Idaho Power
Company case at page 4, reiterated the three general categories of adjustments as:
noffi1alizing adjustments made for unusual occurrences, like one-time events or extreme
weather conditions, so they do not unduly affect the test year; 2) annualizing adjustments
made for events that occurred at some point in the test year to average their effect as if they
had been in existence during the entire year; and 3) known and measurable adjustments made
to include events that occur outside the test year but will continue in the future to affect
Company income and expenses. Each of Avista s adjustments falls into one of these three
categories. The Commission Staff has fully examined the Company s adjustments and have
made their recommendations regarding each individual adjustment.
21
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A vista Corporation
Would you please comment on Dr. Peseau s statement regarding the
selection of a 2002 test year?
Yes. On page 29 at line 19 of Dr. Peseau s testimony he states
, "
For unknown
reasons, Avista chose a 2002 test year, rather than 2003." Avista had a deadline of March 31
2004 to file its electric general rate case. Commission Order No. 29377 in Case No. A VU-
03-6 dated November 18 , 2003 regarding Avista s Power Cost Adjustment ("PC status
report and PCA surcharge continuation established the March 31 , 2004 deadline at page 12 in
the third ordering paragraph. It takes a number of months to prepare and file a general rate
case. There was not enough time for the Company to close it's 2003 financial records, and
then for the regulatory group to prepare a case using a 2003 test year and still meet the March
, 2004 filing deadline. Additionally, much of the information relative to a 2002 test year
had previously been prepared and the Commission Staff had already undertaken an audit of
the 2002 calendar year by the time Order No. 29377 was issued. Hence, the 2002 test year
was chosen for the Company s general rate case filing.
Has the Commission Staff accepted the use of a 2002 test year?
Yes. Ms. Stockton s testimony on page 4 at lines 16-18 states
, "
Staff accepts
the average of monthly average 2002 test year, and agrees with the beginning jurisdictional
results of operations.
Would you please comment on Dr. Peseau s statement regarding the use
of 2004 budget estimates?
Yes. On page 31 of his direct testimony, beginning at line 10, Dr. Peseau
states
, "
Avista s pro forma expense adjustments for items like increased labor, insurance, and
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similar costs are simply 2004 budget estimates." Again, Dr. Peseau s statement is unfounded
and not supported by the evidence. The Pro Forma Insurance adjustment reflects the actual
cost of all signed, ongoing and renewed policies providing insurance for 2004. I noted this in
my direct testimony at page 42 beginning at line 15. Ms. Stockton on page 6 of her direct
testimony beginning at line 19 states that the adjustment reflects the actual cost of insurance
policies that are in effect for 2004. Likewise, with the labor expense adjustments, Staff
verified the amounts and made minor adjustments for information that became known after
the case was filed. Staff verified the insurance expense and labor expense amounts, as well
as the other adjustment amounts.
Would you please comment on Dr. Peseau s preferred recommendation at
page 33 to annualize revenues to 2004 year-end levels to correct what he perceives to be
a mismatch between revenue and expense?
First, the 2004 year-end levels of revenue won t be "known andYes.
measurable" for another six months. Secondly, if this methodology of adjusting revenues to
year-end levels were to be followed, then all expenses and all rate base should also be
adjusted to year-end levels. Another major factor, and perhaps the most important, that is
overlooked by Dr. Peseau is that revenues from load growth caused by new customers are
offset by costs to serve the new customers. Line extension allowances are theoretically
established based on the amount of operating margin, revenue less power cost, that is
available from new customers to offset the capital costs, return and depreciation, associated
with the amount of plant investment that new customers are not required to pay for initially.
In other words, additional revenue is offset by additional cost.
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In the case of load growth from existing customers, as Mr. Hirschkorn states in his
direct testimony on page 7, beginning at line 17, usage per customer appears to have declined
significantly for all customer classes. Continuation of this trend would produce a negative
load growth adjustment for existing customers, which would result in an increase to the
revenue requirement, not a reduction to the revenue requirement.
ELECTRIC REVENUE REQUIREMENT SUMMARY
Referring back to page 1, line 40, of Exhibit No. 26, for
identification, what was the actual and pro forma electric rates of return, as revised by
the accepted Staff proposed adjustments, realized by the Company during the test
period?
For the State of Idaho, the actual test period rate of return was 8.18%,
somewhat below the last authorized rate of return of 8.98%. The test period pro forma rate of
return is 5.080/0 under present rates. Thus, the Company does not, on a pro forma basis for
the test period, realize the 9.72% rate of return requested on rebuttal by the Company in this
case.
How much additional net operating income would be required for the
State of Idaho electric operations to allow the Company an opportunity to earn its
proposed 9.720/0 rate of return on a pro forma basis?
The net operating income deficiency amounts to $19 862 000, as shown on
line 4 of page 2 of Exhibit No. 26. The resulting revenue requirement is shown on line 6 and
amounts to $31 070 000, or an increase of 21.24% over pro forma general business revenues
exclusive of the Company s PCA surcharge reduction proposal.
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NATURAL GAS SECTION
UNCONTESTED ADJUSTMENTS
With which adjustments proposed by Staff does the Company concur?
The Company concurs with the following adjustments proposed by Staff that
are noted by Staff direct column identifier and then followed by the column identifier that I
utilized in my Exhibit No. 27:
Deferred FIT G2/v (appropriate deferred accounting treatment)
Lab or- Exec G3/w (estimate updated to actual)
Labor-Non-exec G4/x (estimate updated to actual)
Depreciation G7/as (depr synchronized between states)
Misc Exp G9/z (similar to prior IPUC treatment)
Corp Fees GI0/aa (similar treatment for other Idaho utilities)
Adv. Exp Gl1/ab (similar to prior IPUC treatment)
A vista Foundation G12/ac (correctly assigned to non-utility)
Actual Therm Usage G13/ad (updated to actual)
Schedule M Allocator G14/ac (conforms to elec system treatment)
By accepting the adjustments proposed by Staff above, the Company s revised revenue
requirement is reduced from $4 754 000 to $4 061 000, or $693 000.
CO NTESTED ADJUSTMENTS
Could you please list the various natural gas, non-cost of capital, revenue
requirement adjustments that are still at issue from the Company s original filing and
note the impact of Staff's recommended adjustment to Net Operating Income ("NOI"
and Rate Base as compared to the Company s original filing.
Falkner, Di - Reb
A vista Corporation
218
Certainly. Please see the table below. Since the revenue requirement items
still at issue have been recommended by Staff, for convenience, I will be using the Column
references that can be found in the Staff s summary exhibit sponsored by Ms. Patricia Harms.
Natural Gas Adjustments Still at Issue
(Dollars are in thousands)
COL DESCRIPTION Staff Staff
NOI Rate Base
Gas Inventory (1,572)
Accts. Rec. Fees
Pension Expense 137
Le2al Expenses
G15 Restate Debt Interest (49)
Does the Staff also make an adjustment to remove gas inventory from
rate base using their working capital reasoning?
Yes. Staff uses the same reasoning at page 23 , beginning on line 11 , of
Kathy Stockton s testimony to disallow gas inventory from rate base. Staff claims that since
gas inventory is nonnally considered part of working capital and since Staff claims that
working capital is negative, Staff removes gas inventory from rate base. As previously stated
above, Staffs interpretation of their working capital analysis is incorrect. Staff workpapers
show that working capital is positive, not negative. Also, Staffs classification of gas
inventory in their working capital analysis excludes it from working capital.The
Commission has historically allowed gas inventory to be included in rate base and should
continue to do so in this case.
As the remaining items still at issue in the natural gas case are the same
as those for the electric case, are the Company s responses to Commission Staff's
proposed adjustments the same as put forth earlier in the electric section?
Falkner, Di - Reb
A vista Corporation
219
Yes.
NATURAL GAS REVENUE REQUIREMENT SUMMARY
Referring back to page 2, line 40, of Exhibit No. 27, for identification,
what was the actual and pro forma natural gas rates of return, as revised by the
accepted Staff proposed adjustments, realized by the Company during the test period?
For the State of Idaho, the actual test period rate of return was 6.26%. The test
period pro forma rate of return is 5.43 % under present rates. Thus, the Company does not, on
a pro forma basis for the test period, realize the 9.72% rate of return requested by the
Company in this case.
How much additional net operating income would be required for the
State of Idaho natural gas operations to allow the Company an opportunity to earn its
proposed 9.720/0 rate of return on a pro forma basis?
The net operating income deficiency amounts to $2 596 000, as shown on line
4 of page 2 of Exhibit No. 27. The resulting revenue requirement is shown on line 6 and
amounts to $4 061 000, or an increase of 7.82% over pro forma general business revenues
and transportation revenues.
Does this conclude your rebuttal testimony?
Yes it does.
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open hearing.
(The following proceedings were had in
(Avista Exhibit Nos. 14 , 15, 26, and 27
having been premarked for identification , were admitted into
evidence.
COMMISSIONER KJELLANDER:We I re ready now for
cross.Why don't we begin with Mr. Purdy.
MR.WARD:
direct?
MR . PURDY:I have none, thank you.
COMMISSIONER KJELLANDER:Mr. Cox.
MR. COX:I have none, thank you.
COMMISSIONER KJELLANDER:Mr. Ward.
CROSS - EXAMINATION
Mr. Falkner , if you'd go to page 28 of your
m there.
Down at the bottom of the page, you discuss --
sorry - - three transmission proj ects that were underway at the
time your testimony was written?
Correct.
Now , I apologize, I didn't have time to look
closely at the rej oinder testimony from Ms. Stockton , so I 'll
just ask you:Has the Company agreed to an adjustment similar
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Avista
to the one that took place in Idaho Power's case wi th respect
to these proj ects?
What we stated through my rebuttal testimony
we were not aware at the time of our original filing of that
issue being addressed with Idaho Power.What we found is that
if the Commission would prefer the matching of benefits and
costs to be similar to Idaho Power , we'd find that reasonable.
We did not include that in our rebuttal case though at this
point in time.
MR . WARD:I have no further questions.
COMMISSIONER KJELLANDER:Thank you , Mr. Ward.
Let's move now to the attorney representing PUC
Staff.I believe that's Ms. Nordstrom.
MS. NORDS TROM :That's correct.Thank you.
CROSS -EXAMINATION
BY MS. NORDSTROM:
Good afternoon.
Good afternoon.
There was previous testimony regarding the
benchmark mechanism and the fact that the Washington Commission
has rej ected its continued use.I'd just like to verify the
costs that this change will create.
It's my understanding, based on Production
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Response 187, that the Company has estimated a need for
least four new employees plus associated costs, approximating
half a million dollars system-wide.Is that correct?
That was the estimate we prepared back in April.
Is that still correct, to your understanding?
It is still correct.We are
- -
the movement of
the benchmark back into the Company is a work in progress at
this point in time.
It's also my understanding that Idaho's share of
this amount would equate to approximately $104 000 annually?
Correct.The numbers that we're talking about
would be the added labor and associated cost with additional
employees coming to the Utility.
Is it also true that the Utility pays Avista
Energy approximately $335,000 annually to manage the benchmark
mechanism?
Yes.
Will there be a tracking mechanism in place to
track these changes and the associated costs?
At this point in time, we have no plans to
prepare a tracking mechanism or propose a tracking mechanism.
They will just be rolled into total Utility costs.
Do you think it I S appropriate for Washington
State to assume the difference in costs associated with their
regulatory Decision?
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That's an interesting question.The - - what'
going to happen regardless of where the Decision was generated
from is we will have a change in how we procure gas for the
Company.The connection between Washington and Idaho as far as
the natural gas procurement is kind of - - it's very obvious,
and it's probably going to be an issue that we'll address
somewhere down the road.At this point in time we're not
asking for recovery in this case, and we'll address it in a
future regulatory proceeding.
Do you think this situation is analogous to the
Potlatch supply and service agreements which Idaho paid for all
those changes that were associated wi th those agreements, the
PURPA agreement in particular?
m not familiar with the Potlatch agreement.
I just wanted to clarify your rebuttal testimony
to make sure that I understand it properly.Do you agree with
Staff's calculation methodology to restate debt interest in
these two cases?
The only difference is the level of rateYes.
base that's utilized in the calculation.The methodology is
the same methodology we implemented in the direct case.
So is that the reason
- -
this difference in rate
base numbers - - is that the reason why Staff's restated debt
interest adjustments were listed under the contested
adjustments on pages 5 and 28 of your rebuttal testimony?
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Correct.
Staff witness Harms advocated deferring return on
Coyote Springs 2 to mi tigate the associated rate increase.
Does the Company oppose this deferral?
No, the Company agrees wi th that proposal.
Are you familiar with the rejoinder testimony
filed by Staff witness Stockton on July 16 , 2004?
Yes, I am.
Did Ms. Stockton accurately characterize the
agreement reached between Avista and Staff to reduce Staff'
accounts receivable fees and gas inventory adjustments by half
given the relative meri ts of Staff's and the Company'
pos i t ions?
Yes , that was properly characterized.
On page 6 of your rebuttal testimony, you respond
to Staff -proposed transmission adjustments.Does Avista agree
with Staff that the Beacon to Bell transmission line should be
removed from rate base because its completion was suspended
until 2005?
We worked with Staff during theCorrect.
discovery process to update all the numbers we put in, which
were estimates to the actual numbers.That particular proj ect
has been deferred beyond when this regulatory proceeding will
be f ini shed.
Does Avista agree wi th Staff's adj ustment to
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update cost estimates to actuals for the Beacon to Rathdrum
line and for the Pine Creek substation rebuild?
Yes.As I stated on page 8 , lines 3 through 4
that the Staff correctly updated the actuals, the information
to actual.
Okay.Turning your attention to pensions, when
was the return on asset assumption changed from nine percent to
eight percent?
It was back in 2002.The actual decision was
the discussion was -- ongoing during the later parts of 2001.
Isn't it true that at that time, the average
actual return on assets between 1995 and 2001 was 9.
percent?
Well , yes, that is correct, for that time period,
the '95 through 2002, was approximately 9.23 percent.Wha t
did was to just go out one year farther and take a more normal
Starting with 1994, going out to 2002 , theten-year average.
number was 7.22 percent.And that was the information that the
Company, along with their outside advisers, were evaluating
during the process of changing the assumption.
You state in your rebuttal testimony on page 16
lines 1 7 through 19 , that the Company is proacti vely attempting
to achieve a fully- funded pension plan over time.
Is it correct to imply by this statement that the
penslon plan is not currently fully funded?
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FALKNER (X)Avista
Correct.
And would it be correct to say that the poor
investment performance of 2000, 2001 , and 2002 substantially
helped to create this underfunding?
Well , the situation that we're in is a point
that's happened over time.Obviously, the low returns for that
particular time period was not helpful.We do use an averaging
process for how the actual rate of return on the pension plan
comes into play in the calculation.
At the same time, what we're looking when
mention proacti vely, what we were seeing were estimates of the
mlnlmum funding contribution continuing to escalate if we
stayed at that minimum level.There was basically described
what was described as a bow wave going forward of increasing
costs or cash contributions.What the Company was hoping to do
was mitigate that future increase in cost by some proactive
payments early on that would work into the fund.
You state on page 19 that the Company would be
penalized for attempting to fully fund its pension plan over
time if the minimum contribution method was accepted.
Wouldn't ratepayers be penalized if anything
greater than the minimum contribution were recovered through
rates if investment performance increased?
Could you restate that question?
I f investment performance were toSure.
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lncrease, wouldn't ratepayers be penalized if anything greater
than the minimum contribution were recovered in rates?
Well , I guess that's a timing question.How long
is the Company going to be out for a general case, when would
we come back in, what would be the pension costs at that point
in time.There are a number of costs that go up and down;
penslon might be one of them.But it's when you
- -
if you look
at just the history that we had since 1999, which is the last
general rate increase that we had, the penSlon expense was
approximately $2.2 million on a system level and just the
contributions between then and now has
- -
if you look at who
has - - which side of the equation you're on, customers have
actually benefited by approximately $29 million.We'
contributed more than penSlon expense.So it is kind of a
timing issue.It just depends when the Company would come back
in for a general case.
But that customer benefit was , in large part, due
to the performance of the stock market.Correct?
It I S one of the components.I mean , the FAS 87
calculation is a multi-layered calculation.
But, wouldn't you say, a large component of that
calculation?
Actually, the returns even prlor to the last
general case were a benefit to the customer , or benefit to the
calculation.We don't discount the fact that the return on the
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assets is one component of the calculation.
Isn't it true that if the investments in the plan
earned more than the return on asset assumption , then the plan
would become fully funded over time?
That's the hope.
Have you received the actuarial report for 2004
yet?
No, we're scheduled to get that sometime in
September.
But would you accept that the investments in the
Avista pension plan earned approximately 24 percent in 2003?
That's the number we have for 2003?2004 is
another situation , another case.The updated information or
for like the first five months of 2004, the rate of return
approximately 1.6 percent.You have your good years and you
have your bad years and you kind of average out.2003 was an
unexpectedly good year.
So basically none of the pension expenses at
issue in this case take into consideration the effect of the
24 percent returns in the pension plan that were achieved in
2003?
Actually, they are incorporated into the
calculation.The rate base
- -
excuse me - - the fund assets
that accumulated or grew 24 percent is part of the calculation
for the expected return on asset, and the return that's over
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FALKNER (X)Avista83701
and above the expected level, the eight percent assumption and
the 24 percent, that gets averaged in over time.So there's a
component of that in the 2004 calculation.
Would you agree that a slight change in any one
of the many assumptions used to calculate pension expense could
have a significant effect on the calculation?
The various factors do have
- -
have different
levels of sensitivity but they all can impact the calculation
and that's why they re all
- -
any changes or any evaluations or
assumptions are always taken very seriously by the Company.
And it's not just the Company.We deal wi th our external
audi tors who are paYlng at tention to the industry, we have
actuarial firms that we hire to advise us on the proper level
and we compare ourselves to industry, not only ours, not only
electric industry, but outside.So what we're thinking that we
see is that the changes we make are consistent and generally
supported.
So along those lines, a decrease in the return on
assumption will increase the pension expense.Correct?
You mean return on asset assumption?
Yes.
Correct.If you lower the return number , the
calculation has a number - - there's a service cost , an interest
cost, and an amortization piece.Those are all positive or
expense increases.The return on asset decreases the overall
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Has Avista' s position on Staff's legal expense adjustments
changed in light of the Commission Order on Reconsideration
last week that denied recovery of similar legal expenses
requested by Idaho Power Company?
I didn't read that closely, the Order from the
Idaho Power Company.My recollection was they were asking for
a five-year amortization of the costs.Is that correct?
They were asking for recovery of their legal
expenses that had otherwise been denied.
Okay.Tha t has - - we haven t changed our
posi tion.As far as legal costs go, what our position is, if
you were taking them in isolation , there are almost any single
litigation cases included in a test year could be viewed as
nonrecurrlng or unlque.Our hope is that we don't have
recurring legal costs for the same type of case and that's the
issue that we have with taking out particular costs for the
2002 test period.
What we've tried to show is over time, our legal
costs come through in a fairly tight range, right around
$3.8 million regardless of the makeup of those costs, and
that I S a six-year look.Our contention is that when you step
back and look at that, that our level of 2002 expenses or legal
costs are representative of what we I 11 see going forward.
Isn't it true that Avista' s 2002 legal expenses
had some expenses that should have been directly assigned?
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FALKNER (X)Avista
Directly assigned to our nonutility operations?
Correct.
Yes, that's correct.There was some miscodings
on some invoices, and we agree wi th Staff that those should
properly be taken out.
Isn't it possible that other years also had these
types of legal expense miscodings?
That would be speculation.We have a number of
processes, internal controls.We try to catch as much as
possible that all the distribution coding on invoices are done
properly.But I think even in this caseWe do make mistakes.
it's a relatively immaterial number , based on the total.
So it is possible that the six-year average
proposed by Avista would also contain these types of
misallocations?
There could be some minor misallocation that
would not materially change the overall number.
What was the level of legal expense that was
requested by the Company in this case?
We basically used the 2002 actuals as -- and
the - - if you look at the graph or the table on page 22 , it'
approximately $3.87 million.
And how much is Staff proposlng to remove?
Actually, I can't remember exactly, off the top
of my head.Staff is looking to reduce the Company's electric
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FALKNER (X)
Avista
revenue requirement by approximately $573,000 regarding legal
expenses, and gas, approximately 20,000.
So it's fair to say that 3.2 or 3.3 million are
still included out of that $3.8 million of legal expense?
If you were to assume the Staff adjustment, yes.
Okay.So relatively speaking, it's not that
large of an adj ustment in context?
Well , I think to some people $500 000 is a lot of
To other people, maybe it I S not.money.
In the context of this adj ustment, we're looking
at a level of the last six years that doesn't show 3.3 to be
representati ve of an ongolng expense.8 looks to be a little
bi t more representative of what we might be seeing going
forward.
MS. NORDSTROM:Thank you.No further quest ions.
COMMISSIONER KJELLANDER:Are there questions
from members of the Commission?
COMMISSIONER HANSEN:I do.
COMMISSIONER KJELLANDER:Commi s s i one r Hans en .
EXAMINATION
BY COMMISSIONER HANSEN:
I just had one follow up:
I believe if I understood correctly, you
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Avista83701
mentioned that you gave out a five percent salary increase.
Was that correct?Did I hear that?
That's the assumption that we're using in the
pension plan calculation.
Right.
It'not
2004 .That'
what we actually gave out in '03 or
the moving-forward assumption over time.
I was just also curious , did the Company lssue
any bonuses or incentive pay during this period to any
employees?
Yes.
And could you give me a percentage?Did you have
a percentage that that would fall in , like ten percent,
20 percent, 16 percent, what that would be?
I really don't know , off the top of my head.
did have an incentive payout during this time period.Wha t the
percentage is, I wouldn't know.It wouldn't be ten percent.
COMMISSIONER SMITH:Something larger?
THE WITNESS:No, it would be less.
COMMISSIONER KJELLANDER:Are there further
questions from members of the Commission?Commissioner Smi th.
COMMISSIONER SMITH:, just one.
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EXAMINATION
BY COMMISSIONER SMITH:
You discussed in your answers to questions from
Staff Counsel this change that the Washington Commission
making - - causing the Company to make in gas procurement, but
then you said you weren't requesting any recovery of costs in
thi s case?
Correct.The numbers we're using right now
they're just estimates.We don't really have a way to nail
them down to meet the known and measurable test.
Oh, okay.Well , I was just wondering what you
thought might happen for your next case, ike maybe Idaho
Commissioners will leave and won't remember what the UTC did,
or maybe UTC Commissioners will change and will revert back.
Do you think there's something that's going to save us from
this train wreck?
m not aware of any discussions that have
contemplated any of the Idaho Commissioners leaving, to the
best of my knowledge.
Well, Commissioners do leave.
When it comes back before either the Washington
or Idaho Commission , or Oregon for that matter, I'm just going
to assume that the issue will be decided by the merits of the
case at that point in time.There will be pluses and minuses,
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there will be the Staff position , I assume, and there will be a
Company position.
Okay.That's fair..
Thank you.COMMISSIONER SMITH:
COMMI S S IONER KJELLANDER:We're ready now for
redirect.
No redirect.Thank you.MR . MEYER:
COMMISSIONER KJELLANDER:Thank you for your
test imony .Appreciate your presence today.
THE WITNESS:Thank you.
(The wi tness left the stand.
COMMI S S IONER KJELLANDER:Mr. Meyer , if you would
like to call your next witness, please?
Yes.Mr. Kopczynski , please.MR. MEYER:
DON F. KOPCZYNSKI
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.
Very well.For the record , please state your
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name, maybe even spell your name, and tell us by whom you'
employed.
My name is Don Kopczynski , spelling is
, and employed by Avista Corporation.
And have you prepared both direct and rebuttal
testimony?
Yes, I have.
Do you have any changes to make to ei ther?
I have one change to rebuttal testimony.It's on
page 7.On line 3, the first sentence, I have an addition at
the end.In 2003, Avista hadSo the sentence currently reads:
49,000 opens/closes in the Idaho jurisdiction.
And I would add after that this clarification:
Which would have required a field visit.
So the sentence now would read:In 2003, Avista
had 49,000 opens/closes in the Idaho jurisdiction which would
have required a field visit.
Any other revisions?
No.
So if I were to ask you the questions that appear
in your direct and your rebuttal testimony, would your answers
be the same?
Yes, they would.
Also, are you sponsoring what has been marked as
Exhibi t No. 12?
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HEDRICK COURT REPORTING
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KOPCZYNSKI (Di)
Avista
Yes.
Was that prepared by you or under your
supervision?
Yes, it was.
Is that true and correct , to the best of your
knowledge?
Yes, it is.
And wi th that, then , I move that theMR. MEYER:
testimony be spread as if read, and Exhibit 12 be introduced.
COMMISSIONER KJELLANDER:And wi thou t obj ect ion,
we'll spread the testimony and admi t the exhibi t .
MR. MEYER:Thank you.
(The following prefiled direct and
rebuttal testimony of Mr. Kopczynski is spread upon the
record.
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P. O. BOX 578, BOISE, ID
KOPCZYNSKI (Di)Avista83701
I. INTRODUCTION
Please state your name, employer and business address.
My name is Don F. Kopczynski and I am employed as the General Manager of
Energy Delivery for A vista Utilities, at 1411 East Mission Avenue, Spokane, Washington.
Would you briefly describe your educational background and
professional experience?
Yes. Prior to joining the Company in 1979, I earned a Bachelor of Science
Degree in Engineering from the University of Idaho. I have also earned a Master s Degree in
Business Management from Washington State University and a Master s Degree
Organizational Leadership from Gonzaga University.Over the past 24 years I have spent
approximately 14 years in Energy Delivery, managing Engineering, various aspects of
Operations, and Customer Service. In addition, I spent three years managing the Energy
Resources Department, including Power Supply, Generation and Production, and Natural Gas
Supply.More recently, I worked in the areas of Corporate business analysis and
development, and served in a variety of leadership roles in subsidiary operations for A vista
Corp. I was appointed General Manager of Energy Delivery in 2003. I serve on several
boards of directors including the University of Idaho Research Park and the Second Harvest
Food Banle
What is the scope of your testimony?
I will provide an overview of the Company natural gas and electric
distribution facilities, operations, and customer programs in Idaho.I will also discuss
significant investments being made in the Company s electric transmission system, and
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describe our continuing focus on vegetation management. Lastly, I will discuss the factors
driving the need for the pro forma adjustments proposed in this case for both programs.
Are you sponsoring exhibits in this proceeding?
Yes. I am sponsoring Exhibit No. 12, which was prepared under my direction.
II. OVERVIEW OF A VISTA'S ENERGY DELIVERY SERVICE
Please provide an overview of the customers served by Avista Utilities in
Idaho.
As of December 31 , 2003 , the Company served 109 315 electric customers
and 61 799 natural gas customers in the five northern counties of Idaho. Avista s largest
electric customer in Idaho is the Potlatch Corporation s Lewiston facility, with an annual
usage of approximately 870 million kWh.The Company anticipates residential and
commercial electric load growth to average between 2.0 and 2.5 percent annually for the next
four years, primarily due to expected increases in both population and the number of
businesses in its service territory. While the number of electric customers is expected to
increase, the average annual usage by residential customers is not expected to change
significantly. For the next four years, Avista expects natural gas load growth to average
between 4.0 and 4.5% annually in its Idaho and Washington service territories. The natural
gas load growth is primarily due to expected conversions from electric and oil space heat and
electric water heating to natural gas, and increases in both population and the number of
businesses in Avista s service territory.
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Please describe the Company s electric and natural gas delivery facilities.
A vista Utilities operates a vertically-integrated electric system in Idaho. In
addition to the hydroelectric and thermal generating resources described by Mr. Storro, the
Company has approximately 4 216 miles of lines in the following classes in Idaho: 269 miles
of 230 kV transmission, 603 miles of 115 kV transmission, and 3 342 miles of sub-
transmission and distribution line at a variety of voltages. The predominant distribution
voltage is 13.2 kV. Avista owns and maintains a total of 1,467 miles of natural gas pipelines
in the state of Idaho, of which 488 miles are steel and 979 miles are polyethylene.
Please describe the Company s operations centers that support electric
and gas customers in Idaho.
The Company has construction offices in Grangeville, Orofino, Lewiston-
Clarkston, Moscow-Pullman, Kellogg, S1. Maries, Coeur d' Alene, Sandpoint and Bonner
Ferry, and customer contact center operations in Lewiston and Coeur d' Alene. Avista s four
customer contact centers in Coeur d' Alene , Lewiston, Spokane, and Medford, Oregon are
networked, allowing the full pool of regular and part-time employees to respond to customer
calls in all jurisdictions.
What construction and maintenance programs does the Company have in
place to maintain gas and electric facilities?
A vista Utilities utilizes Company seasonal and regular crews for gas and
electric construction, including new and reconstructed lines, damage repair, and connecting
new customers.The Company employs contract crews and temporary and part-time
employees to meet customer needs during the peak construction season. The company also
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has several maintenance programs to ensure the reliability of our electric and gas
infrastructure, including underground cable replacement, wood pole inspection and
replacement, vegetation management, electric transmission line inspection and rebuild
substation inspection, valve and regulator station maintenance, atmospheric corrosion
protection, leak survey, and an array of programs directed toward the inspection
maintenance, repair and replacement of specific pieces of gas and electric distribution
equipment.
Please explain the customer service programs that A vista provides for its
customers in Idaho.
A vista Utilities offers a number of programs for its Idaho customers such as
energy efficiency programs, Project Share for emergency assistance to customers, a CARES
program, level pay plans, and payment arrangements. Some of these programs will serve to
mitigate the impact on customers of the proposed rate increase.
Please describe Avista Utilities' conservation, or energy efficiency,
programs.
For the past eight years, Avista Utilities' energy efficiency programs in Idaho
have provided for the consistent delivery of comprehensive conservation services. Avista
Utilities offers energy efficiency services to residential, commercial, and industrial
customers. Programs include audits or direct incentives for residential weatherization, high-
efficiency furnaces and water heaters, and commercial qualifying gas-efficiency projects. In
2003, the American Council for an Energy-Efficient Economy (ACEEE) awarded Avista its
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Recognition of Achievement Certificate" for its gas efficiency programs. The ACEEE had
recognized Avista s electric HV AC rooftop program with a similar award in 2002.
Please describe the recent results of the Company Project Share
efforts?
Project Share is a voluntary contribution option allowing customers to include
donations that are distributed through community action agencies to customers in need.
A vista Utilities has consistently had relatively high per-customer contributions when
compared to other utilities with Project Share programs. A vista Utilities customers donated
$320 661 on system basis in 2003 of which $127 226 was directed to Idaho Community
Action Agencies. The Company contributed an additional $60 000 to Idaho in 2003.
Does the Company offer a bill averaging program?
Yes. Comfort Level Billing is the Company s option for customers to pay the
same bill amount each month of the year. This allows customers to more easily budget for
energy bills and it also avoids higher winter bills. This program has been well-received by
participating customers. Approximately 14 000 Idaho customers are on Comfort Level
Billing.
In addition, the Company s Contact Center Representatives work with customers to
set up payment arrangements to pay energy bills. In 2002, 31 773 Idaho customers were
provided with over 91 500 such payment arrangements.
Please summarize A vista s CARES program.
In Idaho, Avista is currently working with over 750 special needs customers
in the CARES (Customer Assistance Referral and Evaluation Service) program. Specially
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trained representatives provide referrals to area agencies and churches for customers with
special needs for help with housing, utilities, medical assistance, etc. In 2002, over 7 300
Idaho customers received $1 700 000 in various fonns of energy assistance (Federal LlliEAP
program, Project Share, and local community funds). This program and the partnerships we
have fonned have been invaluable to customers who often have nowhere else to go for help.
What has been Avista s experience with customer service automation?
Customers are able to access Avista s Interactive Voice Response (IVR)
system for automated transactions such as:
Entering their own payment arrangements (52 000 system wide in 2002)
Reporting outages and listening to automated outage messages (80 000
messages spoken in 2002)
Conducting other business such as obtaining account balances and requesting
a duplicate bill (over 92 000 customers obtained their account balance in
2002).
Our goal is to provide convenient options to our customers. The IVR is available 7
days a week/24 hours a day. Many customers would rather use automation than speak to an
agent. (Over 28% of all callers used the automated system without speaking to a customer
service agent in 2002). In addition to customer convenience, we are able to offset labor costs
by use of the IVR. In 2002, we would have needed an additional 16 full-time representatives
to handle the automated volume (adding as much as $500 000 in costs). Total call volume
(including automated transactions) has gone from one million calls in 2000 to 1.4 million in
2003.
In addition, Avista s "Net Reps" responded to over four times the amount of e-mails
in 2003 compared to 2000, which is an indicator that internet contact is gaining popularity.
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The number of E-Bill customers has increased three times over 2001. Customers enjoy the
easy, convenient options available with this service.
Please provide some examples of Avista s community involvement in
north Idaho?
Our employees have been very active in civic and community activities. For
example, recently Company employees:
were Bronze Sponsors of the American Cancer Society s 2003 Relay for Life
in Coeur d' Alene;
assisted in gathering 3 200 pounds of personal care items for the Coeur
d' Alene and Post Falls food bank;
received certificates of appreciation from Habitat for Humanity and the City
of Pinehurst; and
were awarded the Business of the Month for October 2003 from the Wallace
Chamber of Commerce.
III. MAJOR TRANSMISSION PROJECTS
Please briefly describe Avista s Transmission upgrade projects.
Avista s transmission plan will add over 100 circuit miles of new 230 kV
transmission line to its system and will increase the capacity of another 50 miles of
transmission line.Also, A vista is constructing two new 230 kV substations and is
reconstructing three existing transmission substations.Related projects at six 230 kV
substations are necessary to meet capacity requirements, upgrade protective relaying systems
and to meet regional and national reliability standards. In total, A vista will perfonn work in
eleven of its thirteen 230 kV substations or 85% of its system.
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What are the most significant projects A vista is undertaking?
The most significant projects are described below. Each of these projects are
shown on the map in Exhibit No. 12.
Beacon-Rathdrum 230: A vista is reconstructing 25 miles of transmission
line between Rathdrum, ill and Spokane W A. This project includes
reconstructing the Rathdrum 230 kV substation in Idaho.
Dry Creek: Avista is constructing a new 230 kV substation near Clarkston
W A that will enable existing transmission lines to fonn a ring around the
Lewiston, ID and Clarkston, W A area which will serve load and improve
reliability by reducing congestion during peak energy flows.
Spokane Valley Reinforcement: A vista is adding 500 MW of 230 kV to 115kV transfonnation capability to serve customers in eastern Washington and
Northern Idaho.
Pinecreek Substation: Avista recently completed the reconstruction of this
230 kV facility located in Pinehurst, ID.
Palouse Reinforcement: Avista plans to construct 60 miles of 230
transmission line between the Benewah and Shawnee substations to relieve
congestion on the existing Benewah-Moscow 230 kV line and to provide an
alternant source of power to the Shawnee Substation. The Benewah
Substation will be upgraded to increase its capacity and service reliability.
Beacon-Bell 230: Avista is uprating the capacity on these lines from 400 to
800 MV A to prevent overloads between A vista and BP A's largest substations
in Spokane, W A by reconductoring the existing lines.
What are the expected costs of these upgrades?
The overall cost of these transmission projects is estimated to be $100 million.
In this filing the Company has included the cost of three projects with near tenn completion
dates. These three projects are Pine Creek 230, Beacon-Rathdrum 230, and Beacon-Bell 230
at a system cost estimated to be $26.3 million. Mr. Falkner has included the Idaho allocated
cost of approximately $9 million in his revenue requirement analysis.
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What is A vista doing to minimize the cost and environmental impact of
these projects?
Wherever possible, A vista is committed to upgrading existing transmission
lines and using existing corridors rather than building new lines. This reduces the impact to
the environment and to property owners and other stakeholders. With regard to substations at
Rathdrum, Dry Creek and Boulder, the Company believes it has achieved the right blend of
reliability, cost and operational flexibility for now and into the foreseeable future.
Are these projects coordinated with BPA's projects in the region?
Yes. In August of 2002, A vista entered into an agreement with BP A known as
the West of Hatwai letter agreement. Avista s plan to upgrade its 230 kV facilities supports
and enhances BP A's 500 kV project to construct a transmission line between Grand Coulee
Dam and Bell Substation in North Spokane. By working together, both Avista and BPA have
achieved a least cost plan of service that addresses commercial, load service and regional
reliability issues.
This plan has been reviewed by peer utilities and approved by other Northwest
transmission owners and by utility members of the Western Electricity Coordinating Council
(WECC).The Northwest Power Pool Transmission Planning Committee agreed that a
blended plan of Avista s and BPA's stand-alone plans was the best plan. Avista and BPA
continue to coordinate, plan and schedule construction activities to minimize the security and
reliability issues during this transmission expansion phase.
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What are the Western Electricity Coordinating Council's and the North
American Electricity Reliability Council's (NERC) roles in upgrading Avista
transmission s system
WECC and NERC are the governing bodies that assign the transmission
transfer capacity for all cutplanes in the western United States. They also establish planning
and operating standards that member systems must adhere to in order to maintain reliability
throughout the western interconnection. A vista and BP A are currently working through the
WECC three-phase rating process to determine a new transfer limit for the West of Hatwai
cutplane. This process demands considerable analysis of how these additions operate in
conjunction with the bulk transmission system throughout the western interconnection
(western United States as well as a portion of Canada and Mexico).
What is the West of Hatwai cutplane and what is its effect on regional
reliability?
The West of Hatwai cutplane or "transfer path" is identified by WECC as the
combination of transmission lines that are crossed by a line drawn from BP A's Grand Coulee
Bell 230 kV line corridor extending southward to the Lewiston-Clarkston area encompassing
Avista s 230 kV lines to Wanapum (Pacificorp/Scottish Power) and Oxbow (Idaho Power).
It is shown as Path #6 on WECC's map of principal transmission lines. West of Hatwai has a
path rating of 2800 MW and is continuously monitored by BP A and A vista to ensure that
scheduled and real time power flows do not exceed the path rating. Typically, the generation
output of hydropower during the spring runoff combines with light load conditions which
increases loading on West of Hatwai up to the path rating. Recent load reductions at Kaiser
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Mead, Columbia Falls, and the Addy mine have increased loading on these transmission
facilities. A vista has deployed numerous short-term operational strategies to maximize the
amount of transmission available across the cutplane. Continued reliance on these short-term
strategies could have a long-term adverse impact on reliability if A vista and BP A do not
construct the planned facilities.
Has A vista used any operational strategies to defer the expansion of
transmission facilities?
Yes. As mentioned earlier, A vista has used several short-term strategies to
defer the expansion. These include efforts in demand side management, fuel switching to
natural gas, thermally uprating several 230 kV transmission lines, installing numerous
thermal relay protection schemes, and operating its 115 kV system in an open, radial system.
Under a radial scheme, transmission lines are "sectionalized" by control and communication
to specific switches and operating these switches in a normally open configuration. Thus
load can be served from transformers in a manner that if one line section suffers an outage
the outage is isolated to that sectionalized portion of the line. This reduces both the length of
the outage and the number of customers effected by the outage. Since February of 2000
A vista radialized its 115 kV network to prevent bulk transfer across that system associated
with outages on parallel path 230 kV and 500 kV transmission lines. This has made the 115
kV lines primarily a load service system and has created additional capacity and reduced
customer outages for most end-use customers. This has reduced transmission losses by 15-
aMW and has increased reliability to customers as well as reducing the amount of time for
restoration.
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250
Has the loss of load in the aluminum industry had any impact on Avista
transmission projects?
Yes.As noted earlier, the loss of the Mead Aluminum smelter load in
Spokane combined with the reductions at the Columbia Falls smelter in Columbia Falls
Montana and the Addy Mine Works in Addy, Washington have added significantly to the
congestion and potential system overloads across the West of Hatwai cutplane. This loss of
load on BP A's system has increased the use of transmission on both BP A's and Avista
networked systems. The existing transmission system was developed to accommodate these
large loads in the eastern Washington/northern Idaho/western Montana area. The absence of
these large loads has increased the burden on the surrounding transmission network, which is
now transferring this power west to the Interstate 5 corridor in western Washington and
Oregon.
Have the efforts to form Regional Transmission Organizations affected
Avista s plans for transmission projects?
No. Although Avista is actively engaged in the effort to form a regional
transmission organization (RTO), Avista s transmission upgrade plan is required to serve
load on Avista s system and is being coordinated with other regional transmission upgrade
efforts.A vista is proceeding with its transmission upgrade plan irrespective of R
development efforts, because there are immediate capacity and reliability issues that must be
addressed proactively.
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Has A vista involved communities and landowners in these projects?
Yes. A vista has a long history of seeking public input when planning and
siting transmission lines and substation facilities.The vast majority of community
involvement is conducted voluntarily outside the permitting and regulatory process. In fact
Avista believes that incorporating public input enhances these projects.
IV. VEGETATION MANAGEMENT PROGRAM
Please provide an overview of the Company s vegetation management
program.
Vegetation management, or "tree-trimming,reduces customer outages
improves safety, and enhances system reliability. Scheduled and ongoing prevention of
growing tree limbs making contact with distribution and transmission wires reduces future
costs of responding to a series of outages from storm damage. A vista Utilities has a
comprehensive and professionally-staffed vegetation management program to ensure facility
rights-of-way are maintained in alignment with national utility vegetation management work
practices. The program is managed by a system forester, who is also a Certified Arborist and
a Certified Utility Specialist, a Forester and a Forestry Field Specialist. The maintenance of
rights-of-way is both cyc1e- and time-based, providing a systematic treatment for all
applicable facilities throughout the service territory. The Company s vegetation management
approach is integrated meaning that a variety of management techniques are selected to
provide a least-cost treatment for specific sites based on terrain, line construction and
voltage, and customer considerations.
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What standards does the Company use to guide the treatment of rights-
of-way?
The Company s vegetation management program operates in compliance with
Section 218 of the National Electric Safety Code. Additionally, Avista complies with both
ANSI A-300 for Tree Care Operations - Tree, Shrub, and Other Woody Plant Maintenance-
Standard Practices, and ANSI Z133.1 - Pruning, Trimming, Repairing and Maintaining, and
Removing Trees and Cutting Brush - Safety Requirements. The Company also maintains
compliance with all OSHA and State safety and work-practice requirements.
What is Integrated Vegetation Management?
Integrated Vegetation Management is the practice of applying a variety of
management techniques to move, over the longer term, toward a stable, low-growing plant
community that does not interfere with overhead lines, pose a fire hazard, or affect
accessibility. This approach involves the forester making an on-site assessment of each
circuit as scheduled (Le. the circuit isn t simply trimmed at its appointed cycle time, but a
complete assessment is made to refine the appropriate prescription for treatment application).
The assessment includes current vegetation type and composition, vegetation condition, and
reviews of environmental requirements, line voltage, type of line construction, line loading,
and the criticality of circuit customers (e., hospitals, etc.). Specific treatment work is then
prescribed, which could include pruning, tree removals, right-of-way clearing, danger-tree
removal, and/or application of herbicide or tree growth regulator. The combination of
treatments is designed to meet Avista multiple vegetation management objectives
including reliability, specific customer considerations, and at the least cost.
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In addition to Integrated Vegetation Management what efforts has A vista
Utilities made to drive work-practice efficiencies into the program?
In the past several years the Company has moved to make vegetation
management programs more efficient through the development of expertise and deployment
of strategies using both herbicides, and more recently, tree-growth regulator. Both of these
treatments can provide lower-cost solution than conventional trimming, or more
importantly, help manage vegetation where trimming and tree removal are not effective
options. The Company has tree trimming contract crews to gain efficiencies. Contract crews
have larger and more diverse equipment pools to draw on, achieve efficiency through job-site
reporting, can be staffed to follow the seasonal nature of the workload, and keep more of a
craft-competency focus. At the same time, contract employees receive the same customer
training as A vista employees, generally live in our Idaho and Washington service territories
and have long-tenn relationships with the Company. The Company has also instituted the
use of right-of-way clearing machinery and off-road trimming vehicles, and has varied crew
compliment and size to better match the type of work.
Why is vegetation management an important operations program for
A vista?
Effective management of rights-of-way vegetation allows the Company to
provide safe and reliable electric service to our customers, at a reasonable cost. Maintenance
of appropriate clearances minimizes instantaneous disruptions to customer service, and
effective management of "danger trees" in and near the right-of-way reduces the risk of line
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outage and damage to facilities.Appropriate management of vegetation also protects
customers, emergency workers, and A vista line and tree personnel.
What is the advantage of approaching vegetation management on a
systematic, cycle basis?
Setting appropriate cycle times for each circuit reduces costs of maintenance
over time. There is an optimal time period for such circuit rotation that we seek to achieve.
Importantly, the cycle time is not the same for each circuit, but is tailored to specific
conditions, including moisture, soil type, vegetation composition and condition, accessibility
and customer considerations. Avista s cycle length ranges from two to eight years, with an
average of four years for most residential communities. Throughout the 1990', when this
comprehensive vegetation management program was initiated efforts focused
reclaiming rights-of-way, where tree removal rates averaged 45%.After the initial
reclamation, ongoing maintenance costs tend to be lower when applied on a more regular
interval. Avista s electric circuits were in very good condition in the late 1990', from a
vegetation management perspective, which allowed the Company to maintain satisfactory
levels of customer reliability through the emergency funding reductions that occurred during
the difficult financial circumstances faced by A vista, caused by the western energy crisis.
How does the Company s vegetation management program interface with
customers and the community?
A vista actively encourages the planting of compatible trees under power lines
as an educational effort to avoid future maintenance costs. We participate in the Idaho
Urban and Community Forestry Program as co-sponsors of Arbor Day tree planting grants
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while promoting responsible tree planting near power lines. We work with towns and cities
to remove tall growing trees from under powerlines and replant vegetation with appropriate
low growing species. Our System Forester gives educational talks to neighborhood groups
service clubs and professional organizations about vegetation and how to avoid tree-wire
conflicts.
Please explain why the Company is proposing an increase in vegetation
management costs over the costs included in the 2002 test period.
As described by Company witnesses Morris and Malquist, the Company
entered a period of extreme financial stress beginning in early 2001. All budgets were
reviewed for cost reductions. The vegetation management program had benefited from
consistent previous attention and some aspects of the 2001 and 2002 cycle-basis could be
temporarily deferred without significant consequences to customers' or Company facilities.
What is the proforma adjustment for vegetation management in this
case?
The Idaho jurisdictional adjustment, as included in Mr. Falkner s testimony, is
$1.2 million. In that adjustment we have taken the annual vegetation management projects
scheduled for 2004 through 2007, and calculated a levelized amount. The work was broken
out between distribution and transmission. We also included an average amount for the work
that had been temporarily deferred. The sum of those amounts was ultimately compared to
the actual vegetation management expenditures during 2002.
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Has Avista s electric system reliability been unduly affected due to the
short-term reduction in activity and funding levels during 2001 and 2002?
No.The Company maintained its vegetation management program in
manner that continued to allow the identification and appropriate response for areas that
required immediate attention. The Company s vegetation management program was not
eliminated, but temporarily maintained at a lower level which considered appropriate levels
of reliability and safety.
Does this conclude your prefiled direct testimony?
Yes.
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Please state your name, the name of your employer, your business
address, and current position.
My name is Don F. Kopczynski. I am employed by Avista Corporation at
1411 East Mission Avenue, Spokane, Washington. In the time period since I filed direct
testimony, I have been named Vice-President of Transmission and Distribution Operations.
What is the purpose of your rebuttal testimony?
My testimony will respond to Staffs direct testimony relating to customer
service quality and vegetation management issues.
Please summarize your rebuttal testimony.
Staff Witness Marilyn Parker has identified five areas of concern to Staff
regarding customer service. These include a lack of customer participation in the Winter
Payment Plan the Company timeliness of answering incoming customer calls
disconnection procedures, and the potential for out-of-cycle meter reading. I address each of
these issues in turn.
A vista Utilities has historically been "the hometown utility" with an emphasis on
reliable, high-quality, and low-cost service. It is our firm intention to continue this legacy.
Thus, my response to Ms. Parker s concerns is generally supportive of her positions while
recognizing that several issues are concurrently being reviewed in the Staff-hosted Best
Practices Task Force comprised of Idaho jurisdictional utilities and interested stakeholders.
In regard to vegetation management, the Company reiterates its initial proposal to
increase its tree-trimming expenditures with related cost recovery. An alternative proposal, a
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one-way balancing account, is suggested as a means to avoid any concerns about over-
collection, or a mismatch of future revenue to expense.
Staff Witness Parker, starting at page 11 of her direct testimony, states
that Staff is concerned that no A vista customer in Idaho participated in the Winter
Payment Plan during the last two heating seasons. She states that the Company should
resolve computer programming problems so that customers may participate in this
program while simultaneously receiving protection from disconnection by declaring
eligibility for the Moratorium. What is the Company s response to this concern?
We have undertaken further investigation regarding the Company s computer
capabilities for simultaneously placing customers on the Winter Payment Plan and the Idaho
Moratorium. Our computer system does allow customers to be set up on both. We will train
all customer service representatives by November 1 2004.
Any residential customer who declares that he or she is unable to pay in full for utility
service and whose household includes children, elderly or infirm persons will be offered the
opportunity to establish a Winter Payment Plan. If a customer makes a decision to go on the
Winter Payment Plan, the process will be to set up a payment plan with an end date of April
1 st and set up Idaho Moratorium simultaneously. When customers pay the required amount
under their payment plan, it will be in affect until April 1. If a customer is not able to keep
their payment plan, the payment plan will drop and they will continue to be enrolled in the
Idaho Moratorium which will be in effect until March
As noted in Ms. Parker s testimony, A vista is an active participant in the Best
Practices task force and we are committed to developing enhanced customer education in
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collaboration with the Staff, other Idaho jurisdictional energy utilities, and other interested
stakeholders.
Are there additional payment issues the Company would like to comment
on?
Yes. Ms. Parker at page 21 , lines 23-24 of her direct testimony, notes that
A vista currently does not have the ability to make payment arrangements on the Company
website. The Company will add to our website the ability to make payment arrangements
within the next few months.
Ms. Parker beginning at page 14 of her testimony, expresses concern
regarding the Company s level of service as measured by the average time to answer
incoming customer calls. What is the Company s response?
Before I discuss Staff s specific suggestions and the Company s response, I
want to provide an overview of how A vista approaches establishing customer service
standards.As stated by Ms. Parker, service standards are generally measured by the
percentage of incoming customers answered in a defined number of seconds.The
Company s internal goal has been set at answering 70% of incoming calls within 60 seconds.
In national regulatory meetings over the past two years, there have been significant
discussions about establishing a higher standard of service.
The Company attempts to balance the cost of meeting service standard goals with
customer satisfaction. The cost of meeting service standards is predominantly labor, or the
number of contact center representatives available to answer calls. Customer satisfaction is
defined by specific service attributes important to our customers to drive positive evaluation
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of the Company s service. The Company measures five such attributes and the importance of
these to customers. The results of Avista s recent customer service
survey are as follows.
Customers Responding
Very or Somewhat Important"
98.4%
98.3%
97.
96.
91. 7%
Attribute
Representative being informed and knowledgeable
Representative providing all of the information needed in one call
Representative handling the call in a friendly, caring manner
Representative meeting needs promptly
Connecting to a representative in one minute or less
These data suggest that knowledgeable representatives who can promptly respond to
customer requests in a courteous manner are what Avista s customers value. These data also
suggest that a response from the Company within 60 seconds on hold is acceptable to
customers. Balancing customer satisfaction results with the cost for service improvement has
historically been Avista s approach to appropriate contact center standards.
In addition, even with the current goals, as stated above, our customer service surveys
indicate that customer satisfaction has remained high. In fact, our most recent overall
customer satisfaction survey results show a satisfied customer rating of 90% in our Idaho and
Washington operating divisions.
In regard to Staff's specific recommendations of moving from a 700/0-
second standard to 800/0-30 seconds standard, what is the Company s response?
In the past 18 months, Avista has added 6.5 full time equivalent (FTE)
positions to the Contact Centers. For the 12 month period ending June 30, 2004 Avista
answered 69.29% of calls in 60 seconds. However, for the month of June 2004, the number
of calls answered within 60 seconds has increased to 74%.
261
Kopczynski, Di - Reb
A vista Corporation
The Company s analysis shows that an additional nine FTE positions would be
required to answer 80% of incoming customer calls within 30 seconds. Many of these
positions would be part-time due to the need to match call volumes with the appropriate
staffing levels of the contact center. For example, a typical Monday can have about 1500
calls, or 30%, more than other days. This need for flexible staffing means that nine FTE
translates to approximately 13 new employees.
The Company intends to add this additional contact center staff in the next year and
establish 80% of incoming calls answered in 30 seconds as a target. This additional FTE
complement, with a 27.4% allocation to Idaho, would increase expense over that requested in
the Company s Application by $162 735 (or $593 925 on a system basis).We believe it
would be reasonable and appropriate to reflect these additional costs in the Company
revenue requirement in this case.
What is the Company s response to Ms. Parker s recommendation that
the Company significantly reduce the number of abandoned calls per month?
As the Company moves to an 80%-answered-calls-in-30-seconds standard, the
number of customers who hang up before they reach a contact center representative (or
abandoned calls) should be reduced. Ms. Parker notes that the average number of abandoned
calls increased in 2003 over 2002. However when comparing the average number of
abandoned calls to an increasing call volume, abandoned calls in the past five years have
remained relatively steady or decreased as a percentage of call volume. This is shown in the
following chart which illustrates a downward trend in the percentage of abandoned calls.
262
Kopczynski, Di - Reb
A vista Corporation
Avista Utilities Call Volume and Abandoned % 1998-
2004
1200000
Q) 1000000
800000
600000
400000
200000
1998 1999 2000 2001 2002 2003 2004
(Th ru-call Volume -+-Abandoned % May)
Ms. Parker observes at page 18 of her testimony that "Staff does not
0% -g
t: C)0% 0 ~"C 0% ; u.c
...
0% c:c :..
believe this practice (outbound disconnection recorded message) complies with the
spirit of the rule. However, the Best Practices Task Force plans to address the issue
soon of how to improve the disconnection notification process. Both A vista and Staff
will be participating in the discussions." What is Avista s response?
Avista is an active participant in the Best Practices Task Force and looks
forward to examining improvements to this component. As I stated earlier, Avista places
high import on responsive and appropriate customer service levels.
Ms. Parker, at pages 22 and 23 of her testimony, states a concern about
out-of-cycle meter readings. She observes that Staff intends to explore this matter
going forward. What is the Company s perspective on this issue?
The Company does not routinely read meters outside of regular monthly meter
reading cycles. Reading meters as part of a regularly scheduled route takes advantage of
economies of scale; reading individual meters on an as-needed basis creates significant
Kopczynski, Di - Reb
A vista Corporation
263
upward cost pressure. These costs, in turn, need to be balanced with the benefits to be
achieved by out-of-cycle meter readings.
In 2003, Avista had 49 000 opens/closes in the Idaho jurisdiction. Approximately 3%
of these changes had the meter read within one day of service changes as part of the regularly
scheduled meter reading route. The average cost of an individually read meter is $18 per trip.
The cost of reading the remaining 47 530 meters (49 000 meters less the 3% picked up by
scheduled routes) would be $855 540.With approximately 109 000 electric Avista
customers in Idaho, out-of-cycle meter reads would result in an additional cost of
approximately $8 per year for every customer.
The Company believes that its bill estimating system is relatively accurate and the
additional cost of moving to individual meter reads for out-of-cycle meter reading is not
warranted.
Do you have other observations regarding Ms. Parker s testimony?
Yes.I appreciate Ms. Parker s recognition of the Company s customer
assistance programs, in particular our Customer Assistance Referral and Evaluation Service
(CARES) program.
Does the Company agree with Staff Witnesses Patricia Harms' and Kathy
Stockton s adjustment to the Company s pro forma level of vegetation management, or
tree trimming, expense?
, the Company disagrees with the Staff adjustment on tree trimming. The
Company continues to support its request to include an increased level of vegetation
Kopczynski, Di-Reb
A vista Corporation
264
management expense in its rate request. Company witness Don Falkner elaborates on this
issue and provides an altemati ve accounting treatment.
We recognize the Staffs concern regarding an increase in expense from that included
in the Company s historic test year. However, for the reasons outlined in my direct testimony
and the recent increased emphasis on transmission reliability, and vegetation management in
particular, we believe the additional funding is especially important at this time. The tree
trimming and danger tree work is important for system reliability. This benefits both
residential and commercial customers in rural and urban communities throughout north
Idaho.
As explained by Mr. Falkner, a one-way balancing account would ensure that any
dollars collected in rates but not expended on vegetation management would be returned to
customers. If the Company were to spend in excess of the amount included in rates, the
Company would absorb the additional costs.
Does this conclude your prefiled rebuttal testimony?
Yes.
I Extraordinary costs due to events such as severe weather, however, may cause the Company to seek additional
relief.
Kopczynski, Di - Reb
A vista Corporation
265
(The following proceedings were had in
open hearing.
(Avista Exhibi t No. 12 , having been
premarked for identification , was admitted into evidence.
COMMISSIONER KJELLANDER:And we're ready now for
Why don't we begin with Mr. Woodbury.cross.
MR. WOODBURY:Thank you.I'd defer to
Ms. Nordstrom.
CROSS -EXAMINATION
BY MS. NORDS TROM :
Good afternoon Mr.Kopc zynski.
Good afternoon.
On page 16,line 16,of your direct test imony ,
you referred to emergency funding reductions that were caused
by the Western energy crisis in regards to vegetation
management.Does this mean that the amount Avista spent on
vegetation management in 2001 and 2002 was less than
originally budgeted?
Yes.
MS. NORDSTROM:Thank you.I have no further
questions.
COMMISSIONER KJELLANDER:Move now to Mr. Ward.
No questions.MR. WARD:Thank you.
266
HEDRICK COURT REPORTING
O. BOX 578 , BOISE , ID 83701
KOPCZYNSKI (X)
Avista
COMMISSIONER KJELLANDER:
No questions.MR . COX:
COMMISSIONER KJELLANDER:
No questions.MR . PURDY:
COMMISSIONER KJELLANDER:
Commission.
Redirect.
Mr. Cox.
Thank you.
Mr. Purdy.
Questions from the
MR. MEYER:Can't think of any.
COMMISSIONER KJELLANDER:Thank you for taking
the time to spell your name , and we appreciate your presence.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:
your next witness?
If you 'd like to call
Sure.The next witness MR. MEYER:
Mr. Bill Johnson.
WILLIAM G. JOHNSON
produced as a witness at the instance of Avista, being first
duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MR. MEYER:
For the record, please state your name and your
employer.
267
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
JOHNSON (Di)Avista
Bill Johnson, Avista Corporation.
case?
So if I were to ask you the questions that appear
And have you prepared direct testimony in this
Yes, I have.
Any changes to make to that?
No.
ln that direct testimony, would your answers be the same?
Yes , they would.
Are you also sponsoring what has been marked as
Exhibit No. 10 attached to that testimony?
Yes.
Was that prepared by you or under your direct ion
and supervision?
Yes , it was.
MR . MEYER:With that, I ask that his testimony
be spread as if read , and move the admission of Exhibi t No. 10.
COMMI S S IONER KJELLANDER:Thank you.Without
obj ection then , we would spread the testimony, and admit
Exhibi t No. 10.
MR. MEYER:Thank you.
(The following prefiled direct testimony
of Mr. Johnson is spread upon the record.
268
HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
JOHNSON (Di)Avista
I. INTRODUCTION
Please state your name, business address, and present position with
A vista Corporation.
My name is William G. Johnson. My business address is 1411 East Mission
Avenue, Spokane, Washington, and I am employed by the Company as a Senior Power
Supply Analyst in the Energy Resources Department.
What is your educational background?
I graduated from the University of Montana in 1981 with a Bachelor of Arts
Degree in Political Science/Economics. I obtained a Master of Arts Degree in Economics
from the University of Montana in 1985.
How long have you been employed by the Company and what are your
duties as a Senior Power Supply Analyst?
I started working for Avista in April 1990 as a Demand Side Resource
Analyst. I joined the Energy Resources Department as a Power Contracts Analyst in June
1996. My primary responsibilities involve long-term resource planning issues.
What is the scope of your testimony in this proceeding?
My testimony will 1) describe the adjustments to the 2002 test period power
supply revenues and expenses, and 2) describe the new base level of power supply costs for
Power Cost Adjustment (PCA) calculation purposes, using the proforma costs proposed by
the Company in this filing. A table of contents for my testimony is as follows:
269
Johnson, Di
A vista Corporation
Description
Introduction
Summary
Proforma Power Supply Costs
New Base Costs for PCA Calculations
Are you sponsoring any exhibits to be introduced in this proceeding?
Yes. I am sponsoring Exhibit No.1 0, Schedules 1 through 4, which were
prepared under my supervision and direction.
Are other company witnesses providing testimony regarding issues you
are addressing?
Yes. Company Witness Kalich provides detailed testimony on the AURORA
model used by the Company to develop a portion of the proforma power supply revenues and
expenses included in my exhibits.
II. SUMMARY
Please provide an overview of your direct testimony.
My testimony explains adjustments made to normalize power supply revenue
and expense items in the proforma period compared to the 2002 test period. This involves
estimating revenues and expenses based on normal stream flow and weather conditions, and
expected wholesale market power prices. In addition, adjustments are made to reflect known
and measurable power contract changes between the 2002 test period, and the time period
that retail rates are expected to be in effect (i., the proforma period beginning September 1
2004 and ending August 31 , 2005). The net effect of my adjustments to the 2002-test period
power supply net expense is a decrease of $30 522 000 on a system basis. The Idaho
270
Johnson, Di
A vista Corporation
allocation of this adjustment is incorporated into the revenue requirement calculation for the
Idaho jurisdiction by Witness Falkner.
III. PROFORMA POWER SUPPLY COSTS
Overview
Please identify the specific power supply cost items that are covered by
your testimony and the total adjustment being proposed.
Exhibit No.1 0, Schedule 1 identifies the power supply expense and revenue
items that fall within the scope of my testimony. These revenue and expense items are
related to power purchases and sales, wheeling expenses, thermal fuel expenses and other
miscellaneous power supply revenues and expenses identified in Exhibit No.1 0, Schedule 1.
What is the basis for the adjustments to the 2002 actual power supply
revenues and expenses?
Adjustments are made to set the power supply revenues and expenses based
on normal weather and normal stream flows. The AURORA model is used to normalize
power supply revenue and expenses that are dependent upon weather and stream flows. The
AURORA Model dispatches Company resources on an hourly basis and calculates the level
of generation from the Company s thermal resources along with the short-tenD purchases and
sales required to serve system requirements.
Adjustments are also made to reflect known and measurable contract changes
between the 2002 test period and the profonna period. The Company has included proforma
power supply adjustments to reflect power costs for the twelve-month period beginning
September 1 , 2004 and ending August 31 , 2005.
271
Johnson, Di
A vista Corporation
What changes has the Company made in the calculation of normal power
supply costs from the prior general rate case?
The primary change has been the adoption of an hourly system simulation
model as explained by Mr. Kalich. This model calculates the dispatch of Company resources
in each hour of the profonna year, rather than a monthly average dispatch as was done with
the dispatch model used in prior rate cases.
Power supply adjustments for known and measurable changes have been prepared
using the same methods that have been used in prior general rate cases. Detailed work papers
have been provided to the Commission coincident to this filing, that supports each of the
proforma adjustments. A brief description of each adjustment is also included in Exhibit No.
, Schedule 2.
What is the overall change in normalized power supply costs compared to
the prior general rate case?
Power supply expense has increased by approximately $11 million (Idaho)
from the prior general rate case. This increase is primarily driven by reduced wholesale net
revenues and an increase in fuel expense. Wholesale net revenue decreased by approximately
$6 million (Idaho) due primarily to the restructuring of the capacity sale to Portland General
Electric. The increase in fuel expense is driven by approximately $10.5 million (Idaho)
increase in natural gas fuel expense due to the addition of the Coyote Springs 2 plant, which
is offset by an approximately $6 million (Idaho) reduction in thermal fuel costs due mostly to
the sale of the Centralia plant.
272
Johnson, Di
A vista Corporation
. ""-
Short-Term Purchases and Sales
How are the short-term market purchases (Account 555) and sales
(Account 447) determined in the proforma?
Short-term market purchases and sales are an output of the AURORA model.
They are the purchases and sales made to balance the system obligations and resources on an
hourly basis. Mr. Kalich explains the derivation of the short-term sales revenue, and short-
term purchase expense in detail in his testimony. Exhibit No.1 0 Schedule 3 shows the
proforma monthly short-term purchases and sales amounts and average price. These figure
were taken from Mr. Kalich's Exhibit No. 11. As shown in Exhibit No. 10, Schedule 3
during the proforma period the Company is a net seller on an annual basis.
~-
Term Contracts
What long-term contracts are included in the proforma?
There are five long-term or medium-term purchases and several small PURP A
purchases and one pending wind energy purchase. The long-term purchase is the WNP-
purchase from the Bonneville Power Administration (BP A). There are four medium-term
purchases with a term of January 2004 through December 2006. There are approximately
average megawatts of PURP A and other small power purchases. In addition, a new wind
power purchase that is expected to begin in early 2004 will provide approximately 10 average
megawatts of energy. A brief summary of these contracts is provided in Exhibit No.1 0
Schedule 2, and the detail of the costs for each is included in the workpapers that have been
provided with this filing.
273
Johnson, Di
A vista Corporation
The Company has very few remaining long-term sales. One that remains is the
Peaker capacity sale. This sale is the fonner Portland General Electric capacity sale that was
monetized in 1998. The other two long-tenn sales of more substantial dollar volume include
the Nichols pumping sale and the sale of reserves and control area services to Mirant for their
half of Coyote Springs 2. With the Nichols sale, A vista sells power to the other owners
Colstrip units 3 and 4 to supply power to the pumps that supply water to the plant. The
contract rate is the Dow Jones Mid Columbia index price. For the proforma, the revenue
from the sale is based on the average market purchase and sales price developed by the
AURORA model. The net effect is little, if any, impact on overall net power supply expense
since the revenue from the sale offsets the cost created by the obligation. The advantage of
this sale is that it reduces the transmission losses associated with wheeling Colstrip energy to
Avista s system since some of Avista s Colstrip energy is "laid-off' at Colstrip to serve the
Nichols pumping load.
What is the impact on net power supply expense due to the expiration of
most of the long-term sales contracts since the last general rate case?
The net expense increase due to the expiration of long-term wholesale
contracts is approximately $15.7 million on a system basis. This is almost entirely due to the
restructuring of the Portland General Electric (PGE) capacity sale. In the 1998 rate case the
revenue from this sale was $18 288 000 ($10.16/kW/month) per year (system). With the
restructuring of the contract the current revenue is $1 800 000 per year ($I/kW/month)
(system), a revenue decrease of $16 488 000 per year on a system basis.Customers
however, have already received the full benefits of the original PGE capacity sale through the
274
Johnson, Di
A vista Corporation
accelerated amortization of the payment A vista received for restructuring the contract (PGE
Monetization). This accelerated amortization of the monetized contract payment was used to
offset a portion of the PCA deferral balance. The amortization of the monetized contract
payment ended December 2002.
The termination of other long-term energy sales had a relatively small impact on net
power supply expense. Long-term wholesale energy sales reduced net power supply expense
by approximately $750 000 (system) in the 1998 general rate case. The proforma in this
filing does not include any net revenue from wholesale energy sales. It does include revenue
from the sale of non-energy products, such as exchange capacity, generation reserves and
load following services.
Thermal Fuel Expense
How are thermal fuel expenses determined in the proforma?
Thermal fuel expenses include the Colstrip coal costs, Kettle Falls wood waste
costs and natural gas expense for the Company s gas-fired resources including Coyote
Springs 2, Rathdrum, Northeast, Boulder Park, and the Kettle Falls combustion turbine. Unit
coal costs at Colstrip are based on the long-term coal supply and transportation agreements.
Unit wood fuel costs at Kettle Falls are based on the multiple shorter-term contracts with fuel
suppliers. Unit fuel costs for natural gas are based on folWard market prices. Total fuel costs
for each plant are based on the unit fuel cost and the plant's level of generation as determined
by the AURORA model. Exhibit No.1 0, Schedule 3 shows the proforma fuel costs by
month for each plant.
275
Johnson, Di
A vista Corporation
What is the change in Colstrip and Kettle Falls unit fuel costs?
The Colstrip per unit coal cost has increased from $10.27 per ton in the 2002
test year to $10.35 per ton in the profonna. The Kettle Falls per unit wood waste cost has
increased from $12.77 per green ton in the test year to $13.82 per green ton in the profonna.
The unit fuel costs increase at Kettle Falls is due in part to the increased demand for wood
fuels and the increased distance from the plant for new suppliers.
What is the change in natural gas fuel costs?
Natural gas fuel costs in 2002 did not include fuel consumption at Coyote
Springs 2, which accounts for over $30 million of the total $35.6 million natural gas fuel
expense in the proforma included in Account 547. Natural gas fuel expense will vary
significantly based on both the cost of natural gas and the generation level of the natural gas
fueled plants. In the profonna year, Coyote Springs 2 generates approximately 111 average
megawatts (aMW) and the Company s other gas fueled plants combined, which are primarily
peaking units, generate approximately 5 aMW.
Natural gas fuel unit costs are based on the forward market price of natural gas (as of
December 10, 2003) as explained by Mr. Kalich. The average price of natural gas at Malin
(gas price for Coyote Springs 2) during the profonna is $4.48 per dekatherm. Natural gas
expenses also include the expense for natural gas transportation agreements used to serve the
Coyote Springs 2 plant.
276
Johnson, Di
A vista Corporation
Do proforma natural gas fuel expenses include the cost of the fixed price
gas purchases made in 2001 ?
No. The proforma natural gas fuel expenses are based on the current forward
market price of natural gas (as of December 10, 2003). The proforma net expense for natural
gas purchased for, but not consumed for generation is normalized to $0 since the proforma
assumes that all gas purchased will be consumed for generation and included in Account 547.
Mr. Lafferty s testimony addresses the fixed price gas purchases made in 2001.
Transmission Expense
What factors are driving the increase in transmission expense in the
proforma?
Transmission expense in Account 565 increases by approximately $1.3
million (system) over the test year.The primary reason for the increased expense
additional amounts of transmission purchased in the proforma period. The amount of BP
transmission purchased to integrate generation is 343 MW, which includes 196 MW for
Colstrip and 147 MW for Coyote Springs 2.Prior to operating Coyote Springs 2 the
Company held 267 Megawatts of BP A transmission to integrate generation. Other changes
include a 15 MW increase in transmission capacity to the California Oregon Border (COB)
purchased from Portland General Electric, and an increase in short-term transmission expense
for short-term system purchases and sales.
277
Johnson, Di
A vista Corporation
IV. PCA CALCULA TI 0 NS
Is the Company proposing any changes to how the PCA deferral
calculated each month?
No. PCA entries will continue to be calculated in the same manner as the
current calculations. The final order in this case will determine the new authorized level of
power supply revenues and expenses used in the PCA calculation.There will be an
additional line to accommodate the new power purchase from the Potlatch Lewiston facility,
which I will discuss later in my testimony.
Will the PCA continue to include the revenues and expenses from
purchases and sales of transactions related to the acquisition of natural gas for thermal
generation?
Yes. The Company will likely continue to fix the price in advance on some
portion of natural gas necessary to run thermal generation. There will also be instances
where the Company later, because of a change in market electric and natural gas prices, sells
the gas and purchases electricity. These types of transactions may lead to a net gain or loss
on the sale of the natural gas that will be recorded as a separate line in the PCA. The
objective of these transactions is to provide some stability over time to the cost of natural gas
to fuel these generators, while also having the opportunity to make the most economic
decision when the time comes to either bum the gas or sell the gas and purchase electricity.
The revenue and expenses from these transactions will be recorded in Account 557 (Other
Power Supply Expenses) for the cost of the natural gas purchased and Account 456 (Other
Electric Revenues) for the revenue from the natural gas sales.
278
Johnson, Di
A vista Corporation
How will changes in the costs associated with Potlatch's Lewiston
generation be included in the PCA?
The Potlatch purchase expense will be a separate line item in the PCA
calculation. Changes in the Potlatch purchase expense will be included in the PCA at 100
percent of the change. change in Potlatch Lewiston corresponding to the change in
Potlatch generation will also be included at the 100 percent level in the retail revenue credit.
Additional Potlatch load changes, not corresponding to their generation, will be included at
the 90 percent level in the retail revenue credit within the PCA. The proposed base level for
the Potlatch power purchase expense and the Potlatch revenue corresponding to their
generation is shown in Exhibit 10, Schedule 4.
Will there be any change in how the retail revenue adjustment is
calculated in the PCA?
No. The only changes that will occur will be in the new authorized level of
retail sales and the incremental cost of power that will be approved in this case. The
Company has proposed that the authorized retail sales will be based on the weather-adjusted
2002 sales used in this case. The proposed base level of retail sales is shown in Exhibit 10
Schedule 4. The incremental cost of power is $36.38/MWh, which is the weighted average
price of Avista s short-term market sales and purchases as determined by the AURORA
model.
279
Johnson, Di
A vista Corporation
What is the new authorized level of power supply expense proposed by the
Company for the PCA?
The new authorized level of annual power supply expense is $71 456 998.
This is the sum of Accounts 555 (Purchased Power), 501 (Thermal Fuel), and 547 (Fuel) less
Account 447 (Sale for Resale). The current level of authorized power supply expense is
$57 866,430. The increase in expense is $13 590 568 on a system basis. The proforma-
authorized expense does not include the cost of power purchased from Potlatch. That
expense will be included as a separate non-system (100% allocated to Idaho) expense in the
PCA and changes to that expense will be included at the 100 percent level in the PCA
deferral calculation. The proposed base level of net power supply expense is shown in
Exhibit 10, Schedule 4.
Does that conclude your pre-filed direct testimony?
Yes.
280
Johnson, Di
A vista Corporation
(The following proceedings were had in
open hearing.
(Avista Exhibit No. 10, having been
premarked for identification , was admitted into evidence.
COMMISSIONER KJELLANDER:And we're ready now for
cross.Let's begin wi th Mr. Purdy.
I have none.MR . PURDY:Thank you.
COMMISSIONER KJELLANDER:Mr. Cox.
MR . COX:I have none.
COMMISSIONER KJELLANDER:Mr. Ward.
MR . WARD:No quest ions.
COMMISSIONER KJELLANDER:Counsel for the PUC
Staff.
MR. WOODBURY:Thank you, Mr. Cha i rman .
CROSS - EXAMINATION
BY MR. WOODBURY:
Mr. Johnson , just a couple of questions:
On page 5, you reference a pending wind energy
purchase of ten average megawatts which would be on-line early
2004 .Is that proj ect on-line?
Yes, it is , in April.
Was that a PURPA-qualifying facili ty proj ect
contract?
281
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
JOHNSON (X)Avista
No, it's not.It's a --
What is the location of that?
It's the state line.State line,
Oregon/Washington border.
On the same page, you state that regarding
thermal fuel expense, that uni t fuel costs for natural gas are
based on forward market prices.
Does the Company utilize forward market prices
for both its natural gas distribution and electric generation
operations?
I'd have to understand what sense are you asking.
Are we doing it for both generation?
I was just wondering whether the forecasting for
those individual purposes is different or is it the same?
Generally, it's going to be the same.We have a
forward price, a forward curve on natural gas.m not as
familiar with the natural gas side , so I will say generally we
have forward price curves for natural gas.
What differences would there be?
Because I'm not sure about what basins the
natural gas business is buying their gas from.We're picking
specific basins or specific delivery hubs for power generation
purposes.
Thank you very much.
MR. WOODBURY:Mr. Chairman, no further
282
HEDRI CK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
JOHNSON (X)
Avista
questions.
Mr. Woodbury.
Commi s s ion?
COMMISSIONER KJELLANDER:Thank you,
Are there questions from members of the
If not, we're ready for redirect.
MR . MEYER:No redirect.
COMMISSIONER KJELLANDER:Thank you.
Thank you , Mr. Johnson.
(The wi tness left the stand.
MR. MEYER:The next wi tness would be Mr. Storro.
RICHARD L. STORRO
produced as a witness at the instance of Avista, being first
duly sworn , was examined and testified as follows:
BY MR.MEYER:
please?
DIRECT EXAMINATION
All set?
Yes.
For the record, your name and your employer
Richard Storro, Avista Corporation.
And have you prepared and prefiled direct
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HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
STORRO (Di)Avista
testimony?
Yes.
Any changes to that?
No.
So if I were to ask you the questions that appear
ln that prefiled direct , would your answers be the same?
Yes, they would.
Are you also sponsoring what has been marked for
identification as Exhibit No.
Yes.
Was that prepared by you or under your direction
and supervision?
Yes , it was.
MR . MEYER:Wi th that , I move the admission of
Exhibi t No.5, and ask that his testimony be spread as if read.
COMMISSIONER KJELLANDER:And without objection
we will admit the testimony and
- -
actually, admit Exhibit
No.5, and spread the testimony as if read.
MR . MEYER:Thank you.
(The following prefiled direct testimony
of Mr. Storro is spread upon the record.
284
HEDRI CK COURT REPORTING
O. BOX 578, BOISE , ID 83701
STORRO (Di)Avista
I. INTRODUCTION
Please state your name, employer and business address.
My name is Richard L. Storro. My business address is 1411 East Mission
Avenue, Spokane, Washington, and I am employed by the Company as the Director of Power
Supply.
What is your educational background?
I participated in a program with the College of Idaho and the University of
Idaho , where upon completion I received a Bachelor of Science degree in physics from the
College of Idaho and a Bachelor of Science degree in electrical engineering from the
University of Idaho, both in 1973.
How long have you been employed by the Company?
I started working for Avista in 1973 as a distribution engineer. I have worked in
various engineering positions, and have held management positions in line and gas
operations, system operations, hydro production and construction, and transmission. I joined
the Energy Resources Department as a Power Marketer in 1997 and became Director of
Power Supply in 2001. My primary responsibilities involve the oversight of both the short-
term and long-term planning and acquisition of power supply resources for the Company.
What is the scope of your testimony in this proceeding?
My testimony will provide an overview of Avista s resource planning and power
operations. I will provide an update on the Company s Cabinet Unit #2 upgrade, a status
report on the Company s license commitments at the Clark Fork River hydroelectric projects
and also on the current re-licensing effort for the Spokane River hydroelectric projects.
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Finally, my testimony will address the Company s Risk Management Policy and some
general comments regarding power supply resource management in relation to the
Commission s order in Case No. A VU-03-
A table of contents for my testimony is as follows:
Description Page
ll.
III
Introduction
A vista s Resource Planning and Power Operations
Hydroelectric Projects Update
Risk Policy and Resource Man~gement
I am sponsoring Exhibit No.5 and the schedules listed in the following table for
identification, which were prepared under my direction:
Exhibit No.
Schedule
II. AVISTA'S RESOURCE PLANNING AND POWER OPERATIONS
Would you please provide a brief overview of Avista s resource planning
and power supply operations?
Yes. The Company uses a combination of owned, leased and contracted
resources to serve its retail and wholesale load requirements. Dispatch decisions related to
these resources are made within the Energy Resources Department of A vista Utilities. The
Department conducts studies on a regular basis to determine the need for capacity and energy
resources on a short-term, medium-term and long-term basis. The Company enters into
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short-term and medium-term wholesale sales and purchases transactions to balance its
resources with load requirements. Longer-term resource decisions related to building new
resources, upgrades to existing resources, demand-side management (DSM) and long-term
contract purchases are generally made in conjunction with the Company Integrated
Resource Plan (IRP) and RFP processes. The Company, however, also acquires resources
outside of an RFP process. Schedule No.1 of Exhibit No.5 provides additional details
related to Avista s resource planning and power operations, as well as a tabulation of its
projected loads and resources for the next twenty years.
Has the load forecast included in pages 8 and 9 of Schedule No.1 been
updated as compared to that recently filed in the Company s 2003 Integrated Resource
Plan (IRP) in Case No. A VU-03-02?
Yes. Avista prepared a new load forecast in fall of 2003 for the years 2005-
2014. In general, retail load projections have been reduced somewhat from those included in
the 2003 IRP.However, the Potlatch Lewiston plant load has been separated from their
generation sale amount. The Potlatch load had been included in the 2003 IRP load figures
net of Potlatch's generation. The effect of this change is an increase in load above the level
in the 2003 IRP.
Has the Company s forecast of available resources been updated
compared to that recently filed in the 2003 IRP?
There has been no substantial change to the forecast of available resources.
The purchase of Potlatch generation, however, is now included in the Company s list of
resources.
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Please summarize the future net load and resource position for the
Company.
The Company remains in a nearly balanced energy position for 2005 through
2007 on an average annual basis. However, there are monthly and quarterly deficits and
surpluses within the years even though the annual averages are close to balanced. In general
terms, the Company s annual net resource energy position becomes deficient in 2008 and
beyond. The average energy resource deficiency is 22 aMW in 2008 and increases to 333
aMW in 2014. The Company s capacity position is either surplus or nearly balanced through
2007. The capacity deficiency is 33 MW in 2008 and increases to 481 MW in 2014.
How will the Company plan to meet the future needs for resources
beginning in 2008?
The Company plans to continue to pursue the preferred resource strategy laid
out in its recent 2003 IR.P.The Company would expect to evaluate a mix of options
including medium-term market purchases in heavy load hour and light load hour time-blocks
generation ownership options, renewable resource options demand-side resource options
and generation lease options or tollingl options. As stated earlier, longer-term resource
decisions related to building new resources upgrades to existing resources demand-side
management (DSM) and long-term contract purchases are generally made in conjunction with
the Company s IRP and RFP processes. As determined in the 2003 IR.P , the Company
1 "Tolling" is an energy conversion service whereby a provider takes customer supplied natural gas and converts
it to an amount of electric energy which is delivered to the customer as determined by a defined conversion
ratio. The conversion ratio can be tied to the heat rate and variable operating costs of a generating plant. The
fixed cost of the plant can be covered in fixed fees charged by the tolling service provider. Tolling service may
be contingent on the operation of a specific generation plant.
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preferred resource strategy includes a mix of combined cycle combustion turbine, wind, coal-
fired, and simple cycle natural gas combustion turbine generation. The Company, however
is not precluded from acquiring resources outside of an RFP process.
The Company is currently in the process of concluding an RFP process for the
addition of a long-tenn renewable wind resource to its resource mix. The Company has
entered into a letter of intent agreement for 25-35 MW of wind generation capability. The
average annual energy is estimated to be 8-10 aMW. The Company is hopeful that an
agreement will be signed by March 31 , 2004
III. HYDROELECTRIC PROJECTS UPDATE
Could you provide an update on generation upgrades on the Clark Fork
River hydroelectric generation projects?
Yes. The Company is in the process of upgrading the Cabinet Gorge Project
Unit #2. This approximately $6.6 million capital project consists of removing the original
1952 propeller runner and replacing it with a modem design mixed-flow runner. Estimated
increases in capacity of up to 17 MW and energy of approximately 3 aMW are expected due
to the increased efficiencies and water flow from the new design. The Company expects the
project to be completed in March 2004. Mr. Falkner has included the costs associated with
the upgrade in his revenue requirement calculations, and Mr. Johnson has included the
benefits from the upgrade in his power supply adjustments.
The Company completed a similar upgrade project in 2001 for the Cabinet Gorge
Project Unit #3. The capacity of the unit was increased from 55 MW up to 72 MW and an
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estimated 4.aMW of additional energy can be produced as a result of the increased
efficiency.
The Company is continuing to look for opportunities for additional efficiency
upgrades, in conjunction with other maintenance work, on unit #4 at Cabinet and units #1 and
#3 at Noxon.
Could you provide an update regarding work being done under the
existing FERC operating license for the Company s Clark Fork River generation
projects?
Yes. The Clark Fork Settlement Agreement, signed in February 1999, was
subsequently incorporated into the 45-year FERC operating license for the Company
Cabinet and Noxon hydroelectric generating facilities issued on February 23 2000. Although
the new license became effective on March 1 , 2001 , implementation efforts under the
Agreement were already well underway at that time.With just over five years of
implementation efforts complete, the Clark Fork Project has made significant progress
toward meeting the goals, terms, and conditions of the Protection, Mitigation and
Enhancement (PM&E) measures. Specifically, the purchase of more than 1100 acres of
important bull trout, wetland, and associated upland habitat, will ensure protection of these
crucial resources. The fish passage program has reestablished bull trout connectivity between
Lake Pend Oreille and the Clark Fork River tributaries above Cabinet Gorge Dam. Over the
last four years, Avista has developed two experimental fish passage facilities, and has already
radio tagged and safely transported a total of 105 adult bull trout above Cabinet Gorge Dam.
Once the fish are transported, implementation staff monitor their movement and spawning
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efforts. Juvenile bull trout on their downstream migration are collected in tributary streams
and transported to the Clark Fork River downstream of Cabinet Gorge Dam. Recreation
facility improvements have been made to 19 different sites along the reservoirs. These
upgrades range from improved access new signage and addition of interpretation and
education material, to the total redesign and reconstruction of 9 sites. Finally, tribal members
continue to monitor known cultural and historic resources located within the project
boundary, to ensure that these sites are appropriately protected.
When the new Clark Fork license was received, the high levels of total dissolved gas
occurring during spill periods at Cabinet Gorge Dam was an issue that remained unresolved.
A plan to mitigate the high total gas levels has been developed with stakeholders including
the Idaho Department of Environmental Quality. The plan calls for the modification of an
existing diversion tunnel with engineering studies to commence in 2004.The tunnel
modification would be completed by 2010 at an estimated cost of $37 million (including
AFUDC and inflation). If needed, the modification of a second tunnel would occur within 10
years of completion of the first tunnel at an estimated cost of $23 million (including AFUDC
and inflation).The second tunnel would be constructed only after an analysis of the
perfonnance of the first tunnel and an evaluation of the environmental benefits.
photograph of the Cabinet Gorge project and the existing tunnels is provided as Schedule No.
The Company has not proposed an increase in rates in this filing related to these
expected costs. The Company plans to defer the costs and address recovery of them in a
future rate filing.
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Would you please give an update on the status of your efforts to relicense
the Spokane River Hydroelectric Project?
Yes.The Company is in the process of prepanng to relicense five
hydroelectric generation projects located on the Spokane River. These projects, which are all
under one FERC license, include Long Lake, Nine Mile, Upper Falls, Monroe Street, and
Post Falls. The projects have a total generating capacity of 156 MW, and average annual
energy production of approximately 105 aMW. Our current license for these Spokane River
projects expires in July 2007, creating a deadline in July 2005 for filing a new application.
are developing that application using FERC's alternative licensing procedures. Since
2001 , we have been working with numerous stakeholders to understand and resolve issues
related to the Spokane River Project. That consultation has occurred within five technical
work groups and a lead, or plenary group. The first full season of field studies were
completed in 2003, and we are currently reviewing those results. Stakeholders are also
beginning to work on proposals for PM&E measures. Our goal is similar to what was
accomplished on the Clark Fork Project: a comprehensive settlement agreement defining the
terms and conditions of a new license based on a consensus of local, state and federal
agencies, tribes, and local citizens. We plan to have a draft license application completed at
the end of 2004.
The Company has not proposed an increase in rates in this filing related to these
expected costs. The Company plans to defer the costs and address recovery of them in a
future rate filing.
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IV. RISK POLICY AND RESOURCE MANAGEMENT
Could you please describe the purpose of the Company s Energy
Resources Risk Policy?
Yes. A vista Utilities uses a variety of techniques to manage its business risks.
The Risk Policy is one risk management tool. The overall purpose of the Risk Policy is to
provide general guidance to the Energy Resources workgroup with regard to the management
of the company s energy risk exposure, as it relates to electric power or natural gas resources.
The management of volumetric limits for the imbalance between projected loads and
resources for an 18-month forward period is part of the Risk Policy guidance. The Risk
Policy also provides structure for the appropriate management approvals for longer-term
transactions depending on the term and time of delivery into the future. The Company s Risk
Policy is included as Confidential Schedule No.3 of Exhibit No.
The purpose of the Risk Policy is not to develop a specific procurement strategy for
buying or selling power or natural gas fuel for generation at any particular time. Rather
several factors, including the variability associated with loads, hydroelectric generation, and
electric power and natural gas prices, are considered in the decision-making process with
regard to procurement of electric power and natural gas fuel for generation, consistent with
the Risk Policy. Those factors, and more specifically how they are taken into account with
respect to certain natural gas price hedges deferred to this case in the Commission s order on
the Company s PCA filing in Case No. A VU-03-, are discussed in more detail in Witness
Lafferty s direct testimony.
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293
The Commission, in the Company s recent PCA order, indicated that the
Company should present an acceptable risk management protocol for long-term sales
or purchases as part its PCA deferred case in its general rate case filing. Please
describe how the Company has addressed this issue.
The Company believes that the questions posed by the Commission and Staff
in the PCA case are more closely associated with resource procurement strategies rather than
risk management, per se. The Company believes that the infonnation provided as part of this
general rate case, primarily in Mr. Lafferty s testimony, will serve to answer the questions
associated with the Company s resource procurement strategies and more specifically those
questions associated with medium-term natural gas hedges that were deferred from the PCA
case. The Company and Staff expect to have follow-up discussions following this general
rate case regarding resource procurement strategies and risk management, in general.
What is the scope of testimony of other Energy Resources witnesses?
Mr. Robert Lafferty will provide testimony concerning the prudence of the
Coyote Springs 2, Boulder Park and the Kettle Falls Combustion Turbine resource
acquisitions. Mr. Lafferty will also provide testimony addressing the issues deferred from the
Company s PCA case regarding the prudence of medium-term natural gas hedge transactions.
Mr. William Johnson will provide testimony regarding power supply pro-fonna adjustments.
Mr. Clint Kalich will provide testimony regarding the Aurora power supply model, inputs
and assumptions.
Does that conclude your pre-filed direct testimony?
Yes it does.
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(The following proceedings were had in
open hearing.
(Avista Exhibi t No.5, having been
premarked for identification , was admitted into evidence.
COMMISSIONER KJELLANDER:And let's begin with
Mr. Cox.
MR. COX:I have no cross.
COMMISSIONER KJELLANDER:Mr. Purdy.
MR. PURDY:I have none, thank you.
COMMISSIONER KJELLANDER:Mr. Ward.
MR. WARD:No questions.
COMMISSIONER KJELLANDER:And the Counsel
representing Staff?
MR. WOODBURY:Thank you, Mr. Chairman.
CROSS-EXAMINATION
BY MR. WOODBURY:
Mr. Storro, in your discussion
--
or, you provide
an overview of Avista resource planning and power operations.
Are you speaking of Avista Utili ties only?
Yes.
Okay.And then I gather from a following
discussion that Avista uses a combination of owned, leased, and
contracted resources to serve its retail and wholesale load
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Avista
requirements.In the retail and wholesale load requirements,
we I re just talking about Utility obligations then?
Tha t 's correct.
Pages 6 and 7 , you discuss reserves , planning
reserves?
Yes.
And you state that the Company plans for reserves
ln an amount equal to ten percent of firm peak loads, plus
90 average megawatts?
Right.
To account for river freeze-ups and forced
outages.
And then you state that the WECC requlres Avista
to carry operating reserves equal to seven percent of the
Company's on-l ine thermal resources and five percent of its
on-line hydroelectric resources.
How do those reserve requirements compare?Does
the Company plan for more reserves than required by WECC?
The plan and reserve requirement that the
10 percent plus 90 megawatts generally exceeds the seven
percent and five percent requirements under WECC.The na t ure
of our system is such that during most of the year we always
exceed our reserve requirements.We typically have
considerable amount of
MR. WARD:A little louder , please, Mr. Storro.
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Avista
THE WITNESS:Sorry.
We typically have a considerable amount of
reserve capacity because of the nature of our hydro system
available, and so we generally exceed those requirements.
Did I answer your question?
Yeah.BY MR. WOODBURY:The surplus deficiency
numbers you show for I guess years 2007, 2008, and 2014 , you
show capac i t Y megawatt s and energy average megawatt s , and I
chose those years because of where the deficit first shows up
and then the largest deficit amount.Are those based on normal
condi tions , cri tical water planning, or 80 percent confidence
level?
Well , on page 1 , you see a dependable capaci ty
number , page 1 of my exhibi
Uh-huh.
Okay.Page 1, it shows a dependable capacity
number , it shows capaci ty under average water , and it shows a
capacity under critical water.Is that where you were at?
Wai t a minute.Yes.
And that addresses our resources on both
Clark Fork River and Spokane.
Well , wait a second.In your discussion of the
Company's energy resource risk policy, you attach that as a
confidential exhibit?
Yes.
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Avista
But looking at that policy, it calls for reVlew
on an annual basis and modification when necessary, and I was
wondering whether there is any review of the policy subsequent
to the Commission's Order and the Company's last PCA extension
or continuation?
The policy right now is under reVlew.We do take
a look at that on an annual basis.But to the extent that we
have changes or other things that might affect how we
administer the policy, we might take those issues up at monthly
risk management committee meetings.But at this present time,
the policy for the Utility is under review and we will be
initiating some changes in that I believe in the near future.
The copy that the Company filed was a revised
November 9, 2000?
That's right.
And have there been any changes in that Slnce
then?
No.
On page 10 of your testimony, you state:The
Company believes that the questions posed by the Commission and
Staff in the PCA case are more closely associated wi th resource
procurement strategies rather than risk management , per se.
And you state that the Company and Staff expect
to have follow-up discussions following this general rate case
regarding resource procurement strategies and risk management
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Avista
in general.
And this is in relation to the Commission'
direction in that Order:We expect the Company to present an
acceptable risk managem~nt protocol for long-term sales or
purchases as part of its PCA deferred case in its general rate
case filing.
Are you meaning by the earlier language that the
Company deferred presentation in this case for a later date?
I think the point we were trying to make in that
case is that the statements that were made were more leaning
towards our procurement strategies or buying and selling
strategies.They're not particularly the risk management
associated around the strategies.But we entertain the fact or
thought of the fact that after that is over , after these
hearings are over , there would be addi tional discussions
between Staff and the Company relative to the
- -
whatever
approach may be appropriate relative to procurement strategies.
Thank you, Mr. Storro.I have a real hard time
hearing you.
Sorry.
MR . WOODBURY:Mr. Chairman , no further
questions.
COMMISSIONER KJELLANDER:Are there any questions
from members of the Commission?Commissioner Smi th.
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Avista
EXAMINATION
BY COMMISSIONER SMITH:
I was just curlOUS:Avista is a winter-peaking
utility, isn't it?
Yes, we are, still winter, getting closer to
peaking in the summer.
Well, that's what I wanted to ask.Have you been
tracking your winter and summer peaks, and are they getting
further apart or closer together?
We do track them annually, look at our capaci
and energy requirements for particularly capacity in the winter
peak is getting closer
- -
summer peak is getting closer to the
winter peak.
So you foresee yourself being a dual-peaking
utility?
I can see the peaks, of course, being similar for
winter and summer , so
And what do you think is driving that?
Obviously, air conditioning load, and possibly
other sort of mitigation measures in the winter that people
might take to minimlze their costs.
I was going to say so it's more a fact of the
summer peak growing?
I think so.
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Avista
And the winter peaks just holding steady?
Well, winter peak is still continuing to grow but
not dramatically, and we, of course , being a dual-field
utili ty, a lot of people converting to natural gas.
Thank you.
COMMI S S IONER KJELLANDER:Any further questions
from members of the Commission?
I f not , we're ready for redirect.
MR . MEYER:No redirect.
COMMISSIONER KJELLANDER:Thank you.
Mr. Storro, thank you for your testimony.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:I think at this point
we're going to take a ten-minute break , and it would probably
be our intention to try to get back here around a quarter till.
(Recess.
COMM IS S IONER KJELLANDER:I think we're ready to
get back and resume the hearing.And wi th that then , we are
back on the record, and, Mr. Meyer , if you'd like to call your
next witness?And just for the record, what's the intent then
for the remainder of the day?
MR. MEYER:Kalich , and then Tara Knox.With
that, I'm guessing, based on our preliminary time estimates, if
they're still true, that should take us until 4:00 or just
beyond.
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Avista
COMMISSIONER KJELLANDER:All right.We I re ready
then.
MR. MEYER:Call to the stand Mr. Kalich.
CLINT KALICH
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?For the record , please state your
name and your employer.
My name is Clint Kalich, and I work for Avista
Corporation.
Have you prepared direct testimony in this
case?
Yes , I have.
Any correct ions to make to that?
None.
So if I were to ask you the questions in that
prefiled direct, would your answers be the same?
They woul d be.
Are you also sponsoring what has been marked for
identification as Exhibit 11?
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KALICH (Di)
Avista
Yes.
Was that prepared by you or under your direction
and supervision?
Yes, it was.
MR . MEYER:With that , I ask that his testimony
be spread as if read , and move the introduction of Exhibit
No. 11 , please.
COMMI S S IONER KJELLANDER:Wi thout obj ection , we
would spread the testimony as if read , and admit Exhibit
No. 11.
MR . MEYER:Thank you.
(The following prefiled direct testimony
of Mr. Kalich is spread upon the record.
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KALICH (Di)
Avista
I. INTRODUCTION
Please state your name, the name of your employer, and your business
address.
My name is Clint Kalich. I am employed by Avista Corporation at 1411 East
Mission Avenue, Spokane, Washington.
In what capacity are you employed?
am the Manager of Power Supply Planning & Analysis, in the Energy
Resources Department of A vista Utilities.
Please state your educational background and professional experience.
I graduated from Central Washington University in 1991 with a Bachelor of
Science Degree in Business Economics.Shortly after graduation I accepted an analyst
position with Economic and Engineering Services, Inc. (now EES Consulting, Inc.), a
northwest management-consulting finn located in Bellevue, Washington. While employed
by EES, I worked primarily for municipalities, public utility districts, and cooperatives in the
area of electric utility management. My specific areas of focus were economic analyses
around new resource development, rate case proceedings involving the Bonneville Power
Administration, integrated (least-cost) resource planning, and demand-side management
program development. In late 1995 I left Economic and Engineering Services, Inc. to join
Tacoma Power in Tacoma, Washington. I provided key analytical and policy support in the
areas of resource development, procurement, and optimization, hydroelectric operations and
re-licensing, unbundled power supply rate-making, contract negotiations, and system
operations. I helped develop, and ultimately managed, Tacoma Power s industrial market
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access program serving one-quarter of the company s retail load. In mid-2000 I joined Avista
Utilities as a Senior Power Resource Analyst. Early in 2001 I was promoted to my current
capacity. I assist the Company in the areas of resource analysis, dispatch modeling, resource
procurement, integrated resource planning, and rate case proceedings. Much of my career has
involved resource dispatch modeling of the nature described in this testimony.
What is the scope of your testimony in this proceeding?
My testimony will describe the Company s use of the AURORA dispatch
model, hereinafter referred to as the "Dispatch Model " including key inputs, assumptions
and results. A table of contents for my testimony is as follows:
DescriptionI. IntroductionII. Executive Summaryill. The Dispatch ModelIV. Assumptions & CalculationsV. Results
Pages
Are you sponsoring exhibits in this proceeding?
Yes. I am sponsoring one confidential exhibit marked as Exhibit No. 11. All
information contained in the exhibit was prepared under my direction.
II. EXECUTIVE SUMMARY
Please provide an overview of your direct testimony.
My testimony will describe the hourly dispatch model used by the Company in
this case. I will briefly explain the Dispatch Model's advantages over the monthly model
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used in previous filings before this Commission. I will explain the Company s experience
using this model and how it dispatches resources, including hydroelectric projects.
I will also explain the key assumptions driving the Dispatch Model's market forecast
of electricity prices. Included in the discussion will be the variables of natural gas, Western
Electricity Coordination Council (WECC) loads and resources, and hydroelectric conditions.
I will explain how the Company s retail loads were developed for the proforma period, and
ultimately how the Company s generation resources and various contracts were modeled.
will describe how the model dispatches our resources and contracts in a manner that
maximizes benefits to customers. Finally, I will explain the modeling results that were
utilized by Witness Johnson to complete his power supply proforma adjustment calculations.
III. THE DISPATCH MODEL
What modeling changes has the Company made in the calculation of
normal power supply costs from the prior general rate case?
In this case the Company has used the AURORA system dispatch model for
the detennination of power supply costs. The model optimizes the dispatch of Company-
owned resources and contracts in each hour of the profonna year. Rather than using monthly
average dispatch values, as was done with the model used in prior rate cases, the Dispatch
Model more accurately reflects true system dispatch by evaluating future resource decisions
on an hourly basis.
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What benefits does the Dispatch Model offer for this type of analysis?
There are two primary benefits. The first is that the Dispatch Model generates
hourly electricity prices across the WECC, accounting for its specific mix of resources and
loads. The Northwest marketplace is not insulated from the rest of the WECC, as we
experienced during the 2000-01 energy crisis. The Dispatch Model more accurately reflects
the impact of regions outside the Northwest, limited by known transfer (transmission)
capabilities. Ultimately, the Dispatch Model allows the Company to generate robust price
forecasts in-house instead of relying on exogenous forecasts.
The second benefit is potentially even more significant. The Company owns a
number of resources, including hydroelectric plants and natural gas-fired peaking units
which have the capability of serving customer loads during the more valuable on-peak hours.
By optimizing regional loads and resources on an hourly basis, the Dispatch Model is able to
more accurately value the capabilities of these resources. For example, actual 2003 on-peak
prices were 18 percent greater than off-peak prices. By comparison, the Dispatch Model
prices for the proforma period averaged 19 percent.
Please briefly describe the Dispatch Model used to dispatch the
Company s portfolio for the proforma period.
The AURORA Electric Market Model was developed by EPIS, Inc. of West
Linn, Oregon. AURORA is a fundamentals-based tool that contains demand and resource
data for all of the WECC, including resources owned by the Company. AURORA employs
multi-area, transmission-constrained dispatch logic to simulate real market conditions. Its
true economic dispatch captures the dynamics and economics of electricity markets-both
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short-term (hourly, daily, monthly) and long-term. On an hourly basis the Dispatch Model
develops an available resource stack, sorting resources from lowest cost to highest cost.
then compares this resource stack with forecasted load to arrive at the least-cost market-
clearing price.
What experience does the Company s have using AURORA?
The Company purchased AURORA in April of 2002. Since that time it has
been used for numerous studies, including the 2003 Integrated Resource Plan ("IRP"
What efforts has the Company made to make the AURORA model
available to Commission Staff?
The license negotiated by the Company for AURORA was structured in such a
way that it is extended to both Idaho and Washington Commission Staff. Members of both
Commission Staffs attended the initial user training session with Company staff, and have
attended the two annual AURORA conferences where modeling topics were discussed and
additional training was provided. Each annual license renewal provides for an additional two
days of on-site training, which is available to Commission Staff upon request.
IV. ASSUMPTIONS AND CALCULATIONS
Are the assumptions utilized for the Dispatch Model in this proceeding
similar to those used in the 2003 Integrated Resource Plan filed with this Commission
last year?
Yes, with a few exceptions. First, forward market natural gas prices are
constantly changing. Given the importance of this variable in setting wholesale electricity
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prices, it has been updated to reflect more recent forward market prices. Specifically, the
Company set prices based on forward curves available on December 10, 2003. Second
Colstrip fuel prices are modified to reflect actual mining budgets. The Kettle Falls fuel price
is also modestly different from the IRP, and reflects updated calculations based upon current
fuel supplies. A vista loads were updated to reflect weather-adjusted 2002 actual values
including Potlatch Corporation s 2002 net load. Finally, two new wholesale power contracts
have been included in the Dispatch Model; one to reflect the Company s reserve contract
obligations, and another to represent a pending wind energy contract.
How does the Dispatch Model determine the output from the Company
hydroelectric projects?
The model begins by "peak-shaving loads usIng hydro resources.
determines which hours represent the highest loads and allocates to them as much
hydroelectric energy as possible. Over the proforma period, the Dispatch Model dispatches
69.6 percent of the Company s hydro generation during on-peak hours. Since on-peak hours
represent only 57 percent of the year, this demonstrates a substantial shift of hydro resources
to the more valuable (expensive) hours.
How does the Dispatch Model's utilization of Company hydro resources
compare to actual history at the plants?
As explained above, over the proforma period the Dispatch Model shapes 69.
percent of available hydroelectric energy into the on-peak hours. This compares with a
year average through 2003 of65.9 percent, and an average since 1989 of67.3 percent.
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On a broader scale, what calculations is the Dispatch Model performing?
The Dispatch Model's goal is to minimize overall system operating costs
across the WECC, including Avista s portfolio of loads and resources. The dispatch model
generates a wholesale electric market price forecast by evaluating all resources in the WECC
simultaneously in a least-cost equation to meet regional loads. As the Dispatch Model
progresses from hour to hour, it "operates" those resources necessary to meet load. With
respect to the Company s portfolio, the Dispatch Model tracks the hourly output and fuel
costs associated with the Company s generation. It also calculates, on an hourly basis, energy
quantities for the Company contractual rights and obligations.In every hour the
Company s loads and obligations are compared to determine a net position. This position is
then balanced using the wholesale electricity market. The cost or value of this energy is
calculated based on the electric market-clearing price for the specified hour.
The thermal fuel costs and market transaction values are provided to Witness
Johnson, where he adds other resource and contract revenues and expenses to detennine the
net power supply expense.
How does the Dispatch Model determine electric market prices, and how
are they used to calculate market purchases and sales?
The Dispatch Model calculates electricity pnces for the entire WECC,
separated into numerous areas. One of these areas represents the Mid-Columbia index in the
study. The load in each area is compared to available resources, including available
transmission, to determine the price for each hour. Ultimately, the market price for the hour
is set based on the last resource in the stack to be dispatched. This resource is referred to as
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Page 7
the "marginal resource." Given the prominence of natural gas-fired resources on the margin
this fuel is a key variable in the determination of hourly wholesale electricity prices.
What is the Company assuming for natural gas prices in the proforma
period?
Natural gas prices are a function of average commodity cost, transportation
and taxes where applicable. For the proforma, natural gas prices were set using forward
prices as of December 10, 2003. Due to the varied locations of our plants, the average price
for the period ranges from a low of $4.40 per decathenn at Rathdrum, to a high of $4.63 per
decatherm for Northeast, Boulder Park, and the Kettle Falls CT. The average price at Coyote
Springs 2 is $4.48 per decathenn. For comparison, the average Henry Hub price for the
period is $4.85 per decathenn. See Table 1 in the following section for a listing of the
monthly natural gas prices assumed for each of the Company s gas-fired plants.
V. RESULTS
What is the average forecast wholesale electric market price of power
over the proforma period?
For the proforma period the average wholesale market price is $39.48 per
megawatt-hour, as presented below in Table 1. Natural gas prices for the Company s natural
gas-fired plants are shown as well. The averages are weighted to account for the actual
number of hours in each month of the profonna period.
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Table 1
Proforma Market Prices
Northwest Power Prices Gas Prices
Month On-Peak Off-Peak Flat CSII Rathdrum NE/BP/KFCT
($/MWh)($/MWh)($/MWh)($/dth)($/dth)($/dth)
Sep-47.37.43.501 4.421 648
Oct-O4 45.37.42.4.496 4.416 643
Nov-O4 44.37.41.683 603 837
Dec-O4 46.39.43.46 836 756 996
Jan-O5 41.47 35.39.946 866 111
Feb-O5 41.37.39.906 826 069
Mar-O5 43.37.40.716 636 871
Apr-O5 36.31.34.221 141 357
May-O5 35.28.32.116 036 247
Jun-O5 35.27.32.111 031 242
Jul-42.37.40.116 036 247
Aug-O5 46.39.43.121 041 253
\erage 42.40 35.39.48 4.478 398 624
What are the outputs from the Dispatch Model?
The Dispatch Model tracks the Company s portfolio during each hour of the
proforma study. Fuel costs and generation for each resource are summarized by month.
Total market sales and purchases, and their revenues and costs, are also determined. These
values are provided to Witness Johnson for his calculations of total power supply expense;
they are contained in Confidential Exhibit No. 11. Page 1 of the exhibit also contains a
monthly summary of modeled energy for each of our contracts.
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Why does the Dispatch Model forecast relatively low levels of generation
for some of the Company s natural gas-fired plants during the proforma period?
The WECC is currently over-built, meaning that there is more generation
available than is needed to serve load. Until the WECC returns to a closer balance of loads
and resources, we expect that our less-efficient gas-fired plants will not run for significant
periods.
Boulder Park provides a good example of this. In the proforma period it is forecast to
run at a capacity factor of 18 percent, but a Dispatch Model run for 2010 resulted in a
capacity factor of 52 percent. This increased operation illustrates the expectation that load
growth will eventually erode the regional generation surplus.
Does this conclude your pre-filed direct testimony?
Yes
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(The following proceedings were had in
open hearing.
(Avista Exhibit No. 11 , having been
premarked for identification , was admitted into evidence.
COMMISSIONER KJELLANDER:Ready now for cross.
Let's begin wi th Mr. Ward.
MR . WARD:No questions.
MR . COX:No questions.
COMMISSIONER KJELLANDER:Mr. Woodbury.
MR . WOODBURY:Thank you, Mr. Cha i rman .
CROSS - EXAMINATION
BY MR. WOODBURY:
Mr. Kalich , just one question:
In the context of power supply, if , as a resul
of this case , rates increase, would you expect that there be
some reduction in kilowatt hours sold and how is that factored
into power supply costs for the AURORA model?
Yeah , the way it is factored into AURORA is the
power supply or a forecast of loads is created and actually
then is an input to AURORA itself , doesn't calculate or try to
estimate elastici ty effects.In talking wi th our in-house
economist who prepares that forecast, elasticity effects are
indeed included in the forecast of loads.
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HEDRI CK COURT REPORTINGP. O. BOX 578, BOISE , ID 83701
KALICH (X)Avista
Do you know what load growth is assumed for
Avista in the next few years?
Percentage or -- about 30 megawatts I guess is
about the annual average increase, I bel ieve
itself?
And is that different than in the WECC terri tory
You know , off the top of my head , there's a
number of areas across the WECC.Each one has a different rate
of growth.I guess at this point I wouldn't be able to talk in
generalities about the WECC.
percentage?
percent.
Thirty average megawatts is equivalent to what
Of our load, approximately 2.6, I believe,
And is the
- -
is it a similar proj ected increase
in load in the Northwest , do you know?
questions.
Mr. Woodbury.
Commi s s ion?
I don't have that figure.
MR. WOODBURY:Mr. Chairman , Staff has no further
COMMISSIONER KJELLANDER:Thank you
Are there any questions from members of the
If not, how about redirect?
MR . MEYER:None.
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HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
KALICH (X)
Avista
COMMISSIONER KJELLANDER:Thank you very much for
your testimony today.
(The wi tness left the stand.
MR . MEYER:Next wi tness, Tara Knox.
I told Tara that she'll thank me for this
tomorrow , not tonight.
TARA KNOX,
produced as a witness at the instance of Avista, being first
duly sworn , was examined and testified as follows:
DIRECT EXAMINATION
BY MR. MEYER:
Ms. Knox , for the record, please state your name
and your employer.
My name is Tara Knox , and I work for Avista Corp.
And have you prepared and prefiled both direct
and rebuttal testimony?
Yes, I have.
Do you have any changes to make to either?
No, I do not.
Are you also sponsorlng what have been marked as
Exhibits 16 and 17 to your direct , and Exhibits 28 and 29 to
your rebuttal?
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE , ID 83701
KNOX (Di)
Avista
Tha t 's correct.
Were those prepared by you or under your
direction and supervision?
Yes, they were.
MR . MEYER:Wi th that , I ask that Ms. Knox'
direct and rebuttal be spread as if read , and move the
admission of 16 , 17 , 28 and 29.
COMMISSIONER KJELLANDER:And wi thout obj ection,
we'll spread both the direct and rebuttal testimony across the
record as if read, and admit Exhibits 16 , 17 , 28, and 29.
MR. MEYER:Thank you.
(The following prefiled direct and
rebuttal testimony of Ms. Knox is spread upon the record.
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HEDRICK COURT REPORTING
P. O. BOX 578 , BOISE , ID 83701
KNOX (Di)Avista
Please state your name, business address and present position with A vista
Corporation?
My name is Tara L. Knox and my business address is 1411 East Mission
Avenue, Spokane, Washington.I am employed as a Rate Analyst in the Rates and
Regulation Department.
Would you briefly describe your duties?
I am responsible for preparing data for and maintaining the regulatory cost of
service models for the Company as well as providing support in the preparation of results of
operations reports and miscellaneous other duties as required.
Would you describe your educational background and professional
experience?
I graduated from Washington State University with a Bachelor of Arts degree
in General Humanities in 1982 and a Master of Accounting degree in 1990. As an employee
in the Rate Department at A vista since 1991 I have attended several ratemaking classes
including the EEl Electric Rates Advanced Course that specializes in cost allocation and cost
of service issues. I have also been a member of the Cost of Service Working Group since
1999, which is a discussion group made up of technical professionals from utilities
throughout the United States and Canada concerned with cost of service issues.
What is the scope of your testimony in these proceedings?
My testimony and exhibits will cover the Company s electric and natural gas
cost of service studies performed for these proceedings and the weather normalization
adjustments to retail usage.
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ELECTRI C SER VI CE
ELECTRIC WEATHER NORMALIZATION
Would you please briefly summarize your testimony related to electric
weather normalization?
The Company s weather normalization adjustment incorporates the effect of
both heating and cooling on weather sensitive customer groups. The weather adjustment is
developed from regression analysis of five years of billed usage per customer, billing period
heating degree day data and billing period cooling degree day data. The resulting weather
sensitivity coefficients for each customer subgroup are multiplied by the average number of
customers in each subgroup during the test period and the difference between normal
heating/cooling degree days and test period observed heating/cooling degree days. This
calculation produces the change in kWh usage required to adjust existing loads to the amount
expected if weather had been normal. Mr. Hirschkom includes the adjustment to normal
usage as part of the Revenue Adjustment for pro forma results of operations. Mr. Kalich
includes the adjustment to normal loads in the modeling for the Pro Forma Power Supply
Adjustment for pro forma results of operations.
Is this different from the method employed in the Company s prior cases?
Yes, although the actual methodology has changed very little. The prior
method did not include the effect of weather sensitive cooling. During the regression phase
of the process, more combinations of variables are tested to arrive at the best fit. Also, the
time period used for the analysis was modified to reflect exactly five heating seasons, July
through June, rather than the five and one-half heating seasons included in the prior method.
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The application of the results of the regression analysis is the same as the prior method, only
now we apply both the difference between normal and actual cooling degree days as well as
normal and actual heating degree days.
Why is it important to include cooling sensitivity in the electric weather
normalization process?
Analysis of the billed usage data since the late 1990's have indicated that
summer weather sensitive usage has become significant for many of the customer groups.
This is most likely reflective of increased saturation of the air conditioning market in the
Although normally a winter peaking utility, in recent years the Company hasregion.
experienced summer peaks near the same level as the winter peaks. In fact, in 2002 the
annual system peak occurred during July. Without incorporating cooling sensitivity the prior
method would add usage during an abnormally hot summer due to fewer than normal heating
degree days.
ELECTRIC COST OF SERVICE
Would you please briefly summarize your testimony related to the electric
cost of service study?
I believe the Base Case cost of service study presented in this case is a fair
representation of the costs to serve each customer group. For comparison purposes, I have
also provided results of an alternative scenario to illustrate the impact of different allocation
decisions in the cost of service process.
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The Base Case study shows Residential Service Schedule 1 and Extra Large General
Service Schedule 25 (not including the Potlatch Lewiston plant) earn substantially less than
the overall rate of return under present rates. General Service Schedule 11, Large General
Service Schedule 21 , and Pumping Service Schedule 31 earn substantially more than the
overall rate of return under present rates (although less that the requested rate of return). The
Potlatch Lewiston plant (at Schedule 25 rates) and Street and Area Lights earn close to the
overall rate of return under present rates.
Are you sponsoring any exhibits related to the electric cost of service
study?
Yes. I am sponsoring Exhibit No. 16 divided into the following Schedules:
Schedule 1, electric cost of service study process description; Schedule 2, Electric Base Case
cost of service study model output; and Schedule 3, alternate scenario summary results.
Was this exhibit prepared by you or under your supervision?
Yes.
What is an electric cost of service study and what is its purpose?
An electric cost of service study is an engineering-economic study, which
apportions the revenue, expenses, and rate base associated with providing electric service to
designated groups of customers. The groups are made up of customers with similar load
characteristics and facilities requirements. Costs are assigned in relation to each groups
characteristics, resulting in an evaluation the cost of the service provided to each group. The
rate of return by customer group indicates whether the revenue provided by the customers in
each group recovers the cost to serve those customers. The study results are used as a guide
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in determining the appropriate rate spread among the groups of customers. Schedule 1 of
Exhibit No. 16 explains the basic concepts involved in performing an electric cost of service
study. It also details the specific methodology and assumptions utilized in the Company
Base Case cost of service study.
What is the basis for the electric cost of service study provided in this
case?
The electric cost of service study provided by the Company as Exhibit No. 16,
Schedule 2 is based on the 2002 test year pro-forma results of operations presented by Mr.
Falkner in Exhibit No. 14.
Would you please describe what is shown in Schedule 2?
Exhibit No. 16, Schedule 2 is the Electric Cost of Service Study. The exhibit
shows the Excel spreadsheet model calculation of the cost of service results. This detail has
been divided into three distinct segments.
Part 1 is composed of a series of summaries of the study results. The summary on
page 1 shows the results of the study by FERC account category. The rate of return by rate
schedule and the ratio of each schedule s return to the overall return are shown on Lines 39
and 40. This summary was provided to Mr. Hirschkorn for his work on rate spread and rate
design. The results will be discussed in more detail later in my testimony.
Pages 2 and 3 are both summaries that show the revenue to cost relationship at current
and proposed revenue. Costs by category are shown first at the existing schedule returns
(revenue); next the costs are shown as if all schedules were providing equal recovery (cost).
These comparisons show how far current and proposed rates are from rates that would be in
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alignment with the cost study.Page 2 shows the costs segregated into production
transmission, distribution, and common functional categories. Page 3 segregates the costs
into demand, energy, and customer classifications.
Part 2 is the cost of service calculations from the spreadsheet called "Assign" showing
the functionalization, classification, and allocation of each line item in the study. The
supporting schedules required to run the model made up of the allocation and classification
factors used in the study are shown on pages 31 through 35.
Finally, Part 3 is the spreadsheet called "Proforma.This worksheet shows the
segregation of Mr. Falkner s pro forma results of operations into the detailed accounting data
used in this study.
Base Case Cost of Service. Electric
Does the Company s electric Base Case cost of service study follow the
methodology filed in the Company s last electric general rate case in Idaho?
The methodology is the same as the cost of service study filed in Case No.
WWP-98-11 with one modification.
Please explain this modification.
Administrative and general costs that cannot be directly assigned to
production, transmission, distribution, or customer relation s functions are left in the
common cost category.In Avista s 1998 case these common costs were allocated to
customer groups by a 60% customer-40% energy allocation factor. In this case the allocation
factor for these common costs has been modified to reflect a four-factor allocation based on
direct O&M, direct labor, net direct plant, and number of customers. With this change the
323 Knox, Di
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same four-factor allocation used on common costs at the utility and jurisdictional levels is
now also applied at the customer group level.
Why did you choose to make this modification?
As I was replicating the methodology from WWP-98-11 to prepare the cost
studies for this case, I considered the need to update the common cost allocator. The four-
factor allocator is accepted in all of the Company s jurisdictions for determining the
appropriate sharing of common costs for results of operations. It is primarily based on other
costs within the study, and reflects a variety of relationships rather than being solely
dependent on a single comparison. The four-factor provides a balanced approach that I
consider more appropriate than the factor used in the last case.
What are the results of the Company s Base Case cost of service study?
The following table shows the rate of return and the ratio of the schedule
return to the overall return (relative return ratio) at present rates for each rate schedule:
Table 1
Customer Class Rate of Return Return Ratio
Residential Service Schedule 1.97%0.42
General Service Schedule 70%
Large General Service Schedule 21 12%1.73
Extra Large General Service Schedule 25 1.17%
Potlatch Ex Lg Gen Service Schedule 25P 24%1.11
Pumping Service Schedule 31 24%1.54
Lighting Schedules 41 - 55%
Total Idaho Electric 71 %1.00
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As can be observed from the above table, residential and extra large general service
schedules (1 and 25) show significant under-recovery of the costs to serve them. The
summary results of this study were provided to Mr. Hirschkom as an input into development
of the proposed rates.
Would you please explain the significance of Schedules 25 and 25P in the
table above?
There are currently 15 customers served on Schedule 25 including the 100
average megawatt load from the Potlatch facilities in Lewiston, Idaho (potlatch Lewiston).
Potlatch Lewiston alone has nearly three times the usage of the other fourteen Schedule 25
customers combined. Prior to 2002 Potlatch Lewiston was served on a special contract with
a sharing of their retail revenue between the Idaho and Washington jurisdictions. Since
January of 2002 Potlatch Lewiston has been served at Schedule 25 rates. This is the first
Idaho embedded cost study to reflect Potlatch Lewiston' s full 100 average megawatt load. In
this case Potlatch Lewiston has been evaluated as a separate cost of service class, due
primarily to the load being significantly higher than other Schedule 25 customers.
Why is the rate of return for Potlatch Lewiston higher than the rate of
return for the remainder of Schedule 25?
There are two primary factors driving the cost differences between the
Potlatch Lewiston plant and the other Schedule 25 customers.
First, Potlatch Lewiston has a significantly higher load factor (98% at the time of the
system peak compared to 77% for the rest of Schedule 25). The cost study reflects load
factor through the relative allocation of energy related costs compared to demand related
325 Knox, Di
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costs. Schedule 25 customers are allocated approximately ten percent of energy related costs
and nine percent of demand related costs.Potlatch on the other hand is allocated
approximately twenty-eight percent of energy related costs but only twenty percent of
demand related costs. The net effect is less demand related production and transmission
costs are allocated to the Potlatch Lewiston plant relative to their consumption than the rest
of schedule 25 customers that have a lower load factor.
Second, Potlatch Lewiston is excluded from allocations of demand related primary
distribution plant. This includes FERC accounts 364 through 368 comprised of poles,
conduit, and overhead or underground conductors & devices. The situation at the Potlatch
Lewiston plant is unique in that they receive primary voltage power at the 115 kV substation
that is dedicated to them. No Company owned primary distribution plant is interconnected
with that substation, therefore exclusion from the allocation is appropriate. The cost of the
substation is directly assigned to Potlatch. The net effect is less distribution facility costs are
assigned or allocated to the Potlatch Lewiston plant relative to their consumption than the rest
of Schedule 25 customers who do receive the benefit of the interconnected primary
distribution system.
Alternative Scenario
Were the results of the Base Case methodology compared to the
methodology from Case No. WWP-98-11 (A vista's last general rate filing)?
Yes, the alternative scenario shown in Exhibit No. 16, Schedule 3 represents
the results using the methodology from Case No. WWP-98-11. The only difference is the
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allocation factor used for common costs. In this scenario common costs are allocated 60% by
number of customers and 40% by annual customer level consumption. The effect of the prior
methodology is to have a heavier emphasis on number of customers. Table 2 below shows
the relative return ratios from this scenario in comparison to the Base Case.
Table
Customer Grou Base Case WWP-98-Difference
Residential Service Schedule 0.42
General Service Schedule 11 1.99
Large General Service Schedule 21 1.73 1.97 +0.
Extra Large General Service Schedule 25 +0.
Potlatch Ex Lg Gen Service Schedule 25P 1.11 1.19 +0.
Pumping Service Schedule 31 1.54 1.66 +0.
Lighting Schedules 41 - 49 1.39 +0.42
Residential and General Service schedules that have relatively low usage per
customer show lower relative rates of return in this scenario which emphasizes the number of
customers. The change in non-metered lighting service is dramatic because most individual
area light customers that also take service on another schedule are counted as customers only
on their metered service schedule. The municipal street lighting customers that do receive
separate bills for lighting service and therefore are counted as lighting customers tend to have
hundreds of lights. This phenomenon causes changes in the amount of customer allocation to
have a greater effect on the results for lighting service.
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What conclusions do you draw from the results of these two cost of
service studies?
In both scenarios residential and extra large general service customers are providing
less than the cost to serve them. General service, large general service, and pumping service
customers are consistently above the overall rate of return. Potlatch Lewiston is close to the
overall return. Lighting service is also close to the overall return in the Base Case.
NATURAL GAS SERVICE
NA TURAL GAS WEATHER NORMALIZATION
Would you please briefly summarize your natural gas weather
normalization testimony?
No change has been made to the historical methodology used to calculate
natural gas weather sensitivity.The weather adjustment is developed from regression
analysis of five and one-half years of billed usage per customer and billing period heating
degree day data. The resulting weather sensitivity coefficient for each customer subgroup is
multiplied by the average number of customers in the subgroup during the test period and the
difference between normal heating degree days and test period heating degree days. This
calculation produces the change in therm usage required to adjust existing loads to the
amount expected if weather had been normal. Mr. Hirschkorn includes the adjustment to
normal usage as part of the Revenue/Gas Supply Adjustment for pro forma results of
operations.
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Is this different from the method employed in the Company s prior cases?
No. This method has been utilized in the Company s last Idaho natural gas
general rate filing as well as the semi-annual commission basis reporting.
The Company is proposing to modify the weather normalization
methodology for electric usage, why not for natural gas usage as well?
The change to the electric methodology was necessary to reflect the impact of
air conditioning load during the summer months. Natural gas is not used for air conditioning,
the usage per customer data shows no cooling sensitivity, and the current regression fit
statistics for the weather sensitive subgroups are excellent. Therefore, there is no need to
change the existing methodology.
NA TURAL GAS COST OF SERVICE
Would you please briefly summarize your testimony related to the
Company s natural gas cost of service study?
Yes. I believe the Base Case cost of service study presented in this case is a
fair representation of the costs to serve each customer group. The study indicates that
General Service Schedule 101 (primarily residential customers) is earning slightly less than
the overall return, all other schedules are earning more than the overall return but less than
the requested return.
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Are you sponsoring any exhibits related to the natural gas cost of service
study?
Yes. I am sponsoring Exhibit No. 17 divided into the following Schedules:
Schedule 4, natural gas cost of service study process description; and Schedule 5, natural gas
cost of service study model output.
Was this exhibit prepared by you or under your supervision?
Yes.
Please describe the natural gas cost of service study and its purpose.
A natural gas cost of service study is an engineering-economic study which
apportions the revenue, expenses, and rate base associated with providing natural gas service
to designated groups of customers. The groups are made up of customers with similar usage
characteristics and facility requirements. Costs are assigned in relation to each groups
characteristics, resulting in an evaluation of the cost of the service provided to each group.
The rate of return by customer group indicates whether the revenue provided by the
customers in each group recovers the cost to serve those customers. The study results are
used as a guide in determining the appropriate rate spread among the groups of customers.
Exhibit No. 17, Schedule 4 explains the basic concepts involved in performing a natural gas
cost of service study. It also details the specific methodology and assumptions utilized in the
Company s Base Case cost of service study.
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What is the basis for the natural gas cost of service study provided in this
case?
The cost of service study provided by the Company as Exhibit No. 17,
Schedule 5 is based on the 2002 test year pro-forma results of operations presented by Mr.
Falkner in Exhibit No. 15.
Would you please describe what is shown in Schedule S?
Exhibit No. 17, Schedule 5 is the Natural Gas Cost of Service Study. The
exhibit shows the Excel spreadsheet model calculation of the cost of service results. This
detail has been divided into three distinct segments.
Part 1 is composed of a series of summaries of the study results. Page 1 shows the
results of the study by FERC account category. The rate of return and the ratio of each
schedule s return to the overall return are shown on lines 38 and 39. This summary is
provided to Mr. Hirschkorn for his work on rate spread and rate design. The results will be
discussed in more detail later in my testimony. The additional summaries show the costs
organized by functional category (page 2) and classification (page 3), including margin and
unit cost analysis at current and proposed rates.
Part 2 is the cost of service calculation from the spreadsheet called "Assign" showing
the functionalization, classification, and allocation of each line item in the study. The
supporting schedules required to run the model are shown on pages 28 through 44.
Finally, Part 3 is the spreadsheet called "Proforma.This worksheet shows the
segregation of Mr. Falkner s pro-forma results of operations into the detailed accounting data
used in this study.
Knox, Di
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331
When was the last time the Company filed a natural gas cost of service
study with the Idaho Public Utilities Commission?
The last natural gas cost of service study was filed with Case No. WWP-88-
5. Purchased gas cost allocations have been examined and approved by the Commission with
each periodic purchased gas tracker filing that has occurred in the interim. Distribution base
rates have not been adjusted since February of 1990.
Does the Natural Gas Base Case cost of service study utilize the
methodology from Avista's last Idaho natural gas case?
No. The Base Case cost of service methodology for distribution, customer
services, and administrative general costs is based on the most recent methodology
employed by A vista in the Washington jurisdiction.This methodology, accepted in
Washington since 1994, resulted from a fully litigated cost of service case specifically
intended to detennine appropriate natural gas distribution rates in the era of transportation
service (WUTC Docket No. UG-940814). The result was a compromise methodology
accepting ideas promulgated by Washington Natural Gas Company (now Puget Sound
Energy), the Commission Staff, and Public Counsel.
Purchased gas costs reflect the Idaho accepted methodology that has evolved with
industry changes through periodic tracker filings.Underground storage costs use the
allocation method required by the Idaho Commission order in Case No. WWP-88-
What are the key elements that define this methodology?
Natural gas main investment has been segregated into large and small mains.
Large usage customers that take service from large mains do not receive an allocation of
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small mains. Meter installation and services investment is allocated by number of customers
weighted by the relative current cost of those items. System facilities that serve all customers
are classified by the peak and average ratio that reflects the system load factor, then allocated
by coincident peak demand and throughput, respectively. Demand side management costs
are treated in the same way as system facilities. General plant is allocated by the sum of all
other plant. Administrative & general expenses are segregated into labor related, plant
related, revenue related, and "other The costs are then allocated by factors associated with
labor, plant in service, or revenue, respectively. The "other" A&G amounts get a combined
allocation that is one-half based on O&M expenses and one-half based on throughput. A
detailed description of the methodology is included in Exhibit No. 17, Schedule 4.
What are the results of the Company natural gas cost of service study?
The following table shows the rate of return and relative return ratio at present
rates for each rate schedule:
Table 3
Customer Class Rate of Return Return Rati 0
Residential Service Schedule 101 76%
Small Firm Service Schedule 111 04%1.21
Large Firm Service Schedule 121 27%1.25
Interruptible Service Schedule 131 44%1.49
Transportation Service Schedule 146 88%1.57
Total Idaho Natural Gas System 00%1.00
These results indicate that Schedule 101 is currently earning slightly less than the
overall return. The other schedules are earning more than the overall return by varying
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degrees. The summary results of this study were provided to Mr. Hirschkom as an input into
development of the proposed rates.
Does this conclude your pre-filed direct testimony?
Yes.
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Please state your name, business address and present position with A vista
Corporation?
My name is Tara L. Knox and my business address is 1411 East Mission
Avenue, Spokane, Washington.I am employed as a Rate Analyst in the Rates and
Regulation Department.
Have you previously submitted direct testimony in this proceeding?
Yes, I sponsored the electric and natural gas cost of service studies.
What is the scope of your rebuttal testimony in this proceeding?
My testimony responds to the cost of service issues discussed in the testimony
of Staff witness Fuss, Potlatch witness Peseau, and Coeur Silver Valley witness Yankel.
Would you please summarize your rebuttal testimony?
With regard to natural gas cost of service, the Company finds Commission
staff recommendation for allocation of underground storage costs and related capacity release
revenues to be reasonable.
Regarding electric cost of service, the Company supports the following: 1) resource
costs should be excluded from the O&M portion of the four-factor allocator used for common
costs in the Company s cost of service study; 2) although 100% demand allocation is an
approach that could be used to classify transmission costs as described by witness Peseau, it
represents a material change from the peak credit methodology the Company has historically
applied and should not be used; and 3) the cost of primary distribution plant Mr. Yankel
proposes to assign to Schedule 25 customers is understated and cannot be reasonably
estimated without considerable additional investigation. The Company recognizes, however
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that the costs for these facilities probably fall between the Company s allocation and Mr.
Yankel's estimated assignment. Therefore, the Company proposes an intenTIediate cost
assignment.
Are you sponsoring any exhibits with your rebuttal testimony?
Yes. I am sponsoring two exhibits. Exhibit No. 28 includes revised Natural
Gas Cost of Service summary infonTIation, and Exhibit No. 29 includes revised Electric Cost
of Service summary infonTIation.
I. Gas Cost of Service Issues
Please describe the issue regarding Natural Gas underground storage
costs referred to earlier.
In the Company s cost of service study, underground storage costs and
capacity release revenues are spread to customer classes based on annual consumption. Staff
witness Fuss, on pages 11 through 13, recommends allocating underground storage costs by
consumption only during the winter months to better match the benefits received trom these
assets. Mr. Fuss also recommends spreading underground storage capacity release revenue
(offset to cost) by another similar allocation factor. This factor is created trom a combination
of winter monthly usage and scheduled withdrawals which essentially results in weighted
winter consumption.
What do you recommend in response to Mr. Fuss s proposal regarding
underground storage costs?
I have no philosophical obj ection to using an allocation based on winter
consumption to spread underground storage and related costs. In the Company s last natural
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gas general case in Idaho (Case No. WWP-88-5), the Company originally proposed using
winter thenns to allocate these costs for similar reasons, but at the conclusion of that case the
Commission selected annual throughput as the preferred option.
I am somewhat concerned about the lack of consistency between the allocations used
for underground storage costs versus the capacity release revenues. I see no reason why the
same allocation factor should not be used for both. While the weighted allocation is slightly
more refined, the winter thenn allocator is more straightforward and less complicated. The
resulting ratios are very similar and will produce nearly the same results. Therefore, I
propose using the less complicated winter thenn allocator for both underground storage costs
and capacity release revenues.
Have you prepared an exhibit summarizing the natural gas cost of service
results associated with the Company s proposed changes described above?
Yes. Exhibit No. 28 is a summary of the natural gas cost of service results
incorporating the proposed changes described above, and all non-contested natural gas
adjustments to the pro- fonna results discussed in Mr. Falkner s rebuttal testimony.
II. Electric Cost of Service Issues
Moving on to electric cost of service, what issues are you addressing?
Three different cost of service issues were raised by the parties in this case that
I will address. Potlatch witness Peseau recommends two changes to the cost of service study:
a change to the calculation of the common cost allocator, and a change in the allocation
methodology for transmission costs. Coeur Silver Valley witness Yankel recommends direct
assignment of certain distribution costs to Schedule 25 customers.
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Regarding the common cost allocator, can you summarize the issue?
Yes. Dr. Peseau points out that resource costs (purchased power and fuel)
were not removed from the direct O&M expense portion of the four-factor allocator. He
discusses various reasons to support the exclusion of purchased power and fuel expenses
largely stemming from their volatility.
Do you agree that resource costs should be excluded from the direct
O&M expense portion of the four-factor allocator?
Yes.The theory behind moving to the four-factor allocation factor for
common costs was to emulate the four-factor allocation used for the Company s utility and
jurisdictional separation process. Examination of the detail behind the calculation of the
utility four-factor shows that resource costs are excluded from the direct O&M expense factor
calculation. Specifically, FERC Accounts 501, 547, 555, 557, & 565 are excluded from the
electric utility allocation factor.These resource costs tend to be high dollar value
transactions that do not require proportionate administrative support. Labor costs are also
excluded from the direct O&M portion of the four-factor to avoid double counting. In light
of this information, I find that the simplified direct O&M factor utilized in the Company Base
Case study should have been refined to exclude accounts 501 , 547, 555 , 557, 565 and labor
dollars. I have revised the Company s electric cost of service study to reflect this change.
What is the effect on the Company s Base Case electric cost of service
study when this one factor has been refined as you describe?
Exhibit No. 29, Page 1 , lines 1 through 8 show the incremental changes to rate
base, net income, rate of return and return ratio due entirely to modification of this one
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allocation factor.As you can see by the return ratio companson below, while this
modification changes the absolute results, the basic under-earning/over-eaming relationships
do not change a great deal.
Table 1
Rate Class Base Case Revised 4-factor Increase
Return Ratio Return Ratio (Decrease)
Residential Schedule 1 .42 .39 (0.03)
General Service Schedule 11-(0.05)
Large General Service Schedule 21-1.72 1.73
Extra Large General Service Schedule 25
Potlatch Lewiston Schedule 25P 1.11 1.19
Pumping Service Schedule 31-1.54 1.53 (0.01)
Street & Area Lights Schedules 41 - 49 (0.10)
Idaho Jurisdictional Total 1.00 1.00
This information is derived from columns K through M on Exhibit 29, Page 1.
Turning to the allocation of transmission costs, what is the issue here?
Dr. Peseau advocates using a 100% demand allocation for all transmission
costs. He cites Idaho Power Company and Avista s FERC transmission tariff utilization of
this approach to justify changing from Avista s traditional peak credit method.
Do you agree with Dr. Peseau s argument that transmission costs
embedded in bundled retail rates should be allocated in accordance with FERC tariffed
wholesale rates?
No.The wholesale transmission tariff cost analysis is independent from
transmission system cost analysis for jurisdictional ratemaking. From the perspective of
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jurisdictional retail ratemaking, the revenues from FERC transmission transactions are simply
an offset to transmission cost. As long as this revenue offset is allocated in the same manner
as the associated costs, customers are receiving a fair share of the benefits of non-retail usage
of the transmission system. State Commissions have jurisdiction over bundled retail rate
issues, and this Commission has consistently accepted A vista s combination of demand and
energy for the allocation of transmission costs.
Mr. Peseau mentions the Idaho Power Company transmission
classification methodology. How does Pacificorp (governed by the Idaho Commission)
allocate transmission costs?
Pacificorp, doing business as Utah Power in Idaho, also uses a combination of
energy and demand for jurisdictional separation and Idaho cost of service purposes. Each
company s system and circumstances should be evaluated on their own merits to detennine
the best fit.
Please explain the peak credit classification theory the Company uses for
production and transmission costs?
The peak credit theory acknowledges that baseload production facilities
provide energy throughout the year as well as capacity during system peaks and likewise the
transmission system is required not only for use during peak times but for everyday delivery
of energy. The intent is to reflect how these systems are used by the consumers.
Does the Commission Staff take issue with the Company s peak credit
approach to transmission costs?
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No. Mr. Hessing accepted the Company cost of service methodology and
pointed out the value inherent in maintaining consistent methodology over time.
Do you agree with Dr. Peseau that transmission costs should be classified
1000/0 as demand-related in the Company s cost of service study?
No. Although this an accepted approach, I think the Company s peak credit
approach is equally valid and use of a consistent methodology over time is the overriding
factor.
involved here?
Regarding Mr. Yankel's distribution plant assignment, what is the issue
Mr. Yankel has proposed incorporating a direct assignment of primary
distribution costs in FERC Accounts 364, 365 , 366, and 367 to Schedule 25 customers. The
method he used to estimate these costs is a ratio based on the sum of the circuit mileage from
the appropriate substation to each Schedule 25 customer.
Isn direct assignment of costs whenever possible preferred over
allocation in a cost of service study?
Yes, as long as it is a viable assignment. In this case there are a number of
problems with the flat circuit mileage approach to estimating the amounts assigned to these
customers.
What are the problems with Mr. Yankel's direct assignment?
First and foremost, the assignment process he uses does not account for the
relative cost of the conductor and other materials that are necessary to support the capacity
requirements of these extra large usage customers. The flat mileage based allocation implies
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that the major feeder lines necessary to ensure adequate capacity for these customers have the
same cost per mile as simple single-phase circuits serving residential neighborhoods. This is
clearly not the case. Additionally, the line mile measurement used by Mr. Yankel looked
only at the direct route from the closest substation to the customer. Some of these customers
may also receive power from alternative routes or other substations in the case of interruption
in power along the direct route. To the extent that other substations may be found to be
available as back-up resources, Mr. Yankel's assignment of primary distribution cost is
understated, as well as the current substation costs assigned to these customers in the
Company s study.
What would be required to come up with an acceptable direct assignment
of primary plant to these customers?
A thorough engineering cost analysis that incorporates the factors addressed
above would be required. A dollar estimate could then be assigned to Schedule 25, with the
remaining primary distribution plant allocated by non-coincident peak demand to the other
customer groups.
Q. - What does Mr. Yankel's analysis indicate?
There is material difference between a primary demand allocation, used by the
Company, for these fourteen customers and Mr. Yankel' s unweighted line mile analysis.
Given the limited distances observed between the Schedule 25 customers and the substations
that have been directly assigned to them, the Company believes that the demand allocation
used in its study overstates the relative primary plant costs related to these customers.
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The discussion above indicates that Mr. Yankel's cost study understates
primary distribution costs for Schedule 25 customers and the Company s Base Case
study overstates them. Do you have a propos~l in response to this issue?
Yes. I have prepared a cost of service scenario that provides reasonable
movement between the two positions. In this analysis I have taken the plant dollars Schedule
25 customers were assigned for accounts 364, 365, 366, and 367 in Mr. Yankel's proposal
and added to that assignment one-half the difference between the Base Case study demand
allocated amounts and Mr. Yankel's amounts.
What are the results of this scenario?
Exhibit No. 29, page 2 is the cost of service basic summary from this model
run. The refinement of the four-factor allocator has also been incorporated into this analysis.
On Exhibit No. 29, page 1 , lines 9 through 16 I illustrate the incremental changes in rate base
net income, rate of return, and return ratios compared to the results with only the refined four-
factor.
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Table 2
Rate Class Base Case Rev 4-factor Rev 4- factor &Increase
Return Return Direct Sch 25 (Decrease)Ratio Ratio Return Ratio vs Base Case
Residential Schedule 1 .42 .39 .36 (0.06)
General Service Sch 11-1.96 (0.10)
Lg General Svc Sch 21-1.72 1.73 1.68 (0.04)
Extra Lg Gen Svc Sch 25 0.37
Potlatch Lewiston Sch 25P 1.11 1.19 1.19
Pumping Service Sch 31-1.54 1.53 1.48 (0.06)
St & Area Lts Sch 41 - 49 (0.11)
Idaho Jurisdictional Total 1.00 1.00 1.00
This infonnation is derived from columns K through M on Exhibit 29, Page 1.
How would you interpret the results shown here?
There is a material increase in the rate of return for Schedule 25 customers.
Naturally, in this type of cost study where the system total remains fixed, if one group is
relieved of cost responsibility, all other groups then absorb a portion of those costs. As can
be observed from Table 2 above, the negative impact on the other customer groups is not
nearly as dramatic as the positive impact on Schedule 25.
spread?
Have you shared this analysis with Mr. Hirschkorn for his work on rate
Yes. He was provided with a copy of the infonnation on Exhibit No. 29, Page
2 for incorporation into his rebuttal testimony.
Does this conclude your pre-filed rebuttal testimony?
Yes.
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(The following proceedings were had in
open hearing.
(Avista Exhibi t Nos. 16, 17 , 28 , and 29,
having been premarked for identification , were admitted into
evidence.
COMMISSIONER KJELLANDER:And we are ready now
for cross.Let's begin wi th Mr. Cox.
MR . COX:Thank you.
CROSS - EXAMINATION
BY MR. COX:
Ms. Knox , I'm interested in this concept of load
research data, and I'm wondering if you could give us an
overvlew --
COMMISSIONER KJELLANDER:m sorry, do you have
your mi rophone on?
MR . COX:I apologi ze Is that better?
COMMI S S IONER KJELLANDER:That'better.
BY MR.COX:What was stating,Ms.Knox was
that was interested interested,in how thi load research
data is developed and wonder if you could give us, in general
a general theory, a general overview , of how the load research
data fits into the overall development of allocators?
We use two
- -
basically two demand allocators,
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one for generation and transmission.We use a system
coincident peak.And then for distribution-related demand
costs, we use a noncoincident peak allocation.
Okay.And what is the test year that you used to
develop this data?
What we - - we used a combination of weather
sensitivity estimates and billing data and to come up with an
estimate of like the daily demand for given groups, because we
have that information from our billing system.And then we
apply a load shape that comes out of the most recent full-blown
demand study that we have done, which was 1993.
So then for 1993, do you take , what, a peak for
X day, like in July, and compare it to 2002?
Okay, it's different for the coincident peak from
the noncoincident peak.
Okay.
So which would you like to do first?
Why don't we start with noncoincident first?
Noncoinc ident peak.Okay.For the noncoincident
peak -- let's see -- we take the billing data for 2002 , and so
we have a monthly billing data for all 12 months for each rate
class.Now, this is only for the classes that have to be
estimated.Schedule 25, which includes also the Potlatch
Lewiston , we have actual hourly information because they re on
the MV 90 system.But for Schedule 1 , Schedule 11
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Schedule 21 , and Schedule 31, we make an estimate.To do that,
we start with the monthly kilowatt hours that were billed in
the test year , so the 2002 , and divide it by the hours in the
month to come up with an hourly kilowatt hours -- an hourly?
Yeah - - hourly kilowat ts, for the average hour in that month.
The load research data from 1993, we have the same average
worked out from the data from 1993.And then we come up wi th a
ratio of what was computed for the noncoincident peak compared
to the average in 1993.We apply that ratio to the 2002
average kilowatts.
And that's how you manipulate those figures to
make it figure, I guess , a model , I would say?
That's the way we accommodate the changes in the
customer makeup.And, you know , of course, there are going to
be a lot of differences in nine years.And so we're capturing
with the current billing data, we're capturing the customers
that we have today.We're estimating the peak relationship
from what the peak relationship was in 2000 -- or , in '93.
Now , there are some differences from ' 93 to 2002
as I understand it.For example , the air condi tioning has gone
up more , you have the peak time periods are different today,
apparently?
Yes.
I guess the question I have:Wouldn't it be a
fairer resul t for all concerned to admit the load research data
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from 1993 can't be massaged enough to immediately fit 2002
condi tions, so the best thing to do would be to give load
research customer average percentage increase?Would you
concede that?
Would you like me to repeat it agaln or
I guess I'd like you to repeat the question.
Sure.Wouldn't a fair resul t for all concerned
to admit that the load research data from 1993 can't be
massaged enough to immediately fit 2002 conditions so that the
best thing would be to give load research customer average
percentage increase?
No, I think that by using the current billing
da ta, you are updating it enough to come up wi th something that
is close enough to give a rational estimate.It's not great,
it would be bet ter to have current load research , but I would
not characterize it as a "cannot be massaged enough.I think
we come up with a reasonable estimate.
Q .But I guess you concede you would have to massage
, and, secondly, there are changed condi t ions.And all I'
suggesting is that another way of looking at this is just to
apply the average percentage increase?
That wouldn't be my solution.
Okay.Thank you.Let's move on to another
topic.
Is it your understanding that Mr. Yankel'
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posi tion is that the Commission should use the actual distance
of overhead and underground prime distribution plant that
used to service a Schedule 25 customer as a means of allocating
assigned costs , as opposed to using the noncoincident peak data
that was used in the Company's original study?
Yes, I believe so.He uses a straight ratio
based on the line miles of overhead and underground.
Okay.Is it accurate to say that your criticisms
of Mr. Yankel' s suggestion is generally contained in your
rebuttal testimony, page 7 , line 20?Actually it's page 7
line 20, through page 8, line
Yes.
Okay.Is it fair to summarize this criticism
into two areas where you bel ieve Mr. Yankel did not, one
address backup during interruptions, and , two, address the
costs of actual costs of facilities?
The most important one is the cost differential
between the type of plant that is necessary for large demand
customers, and also there has not been adequate research into
what other facilities might also serve those customers.
Okay.Please look at page 8 of your rebuttal
testimony.Do you see where you state on lines 4 through
that there may be other substations or lines involved if there
lS an interruption?Do you see that?
Yes.
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Could this work the other way as well?Could
these directly assigned substations and these primary lines
serve other customers if they were interrupted?
Yes.
Yes?
Let'now turn Mr. Yankel' s proposal based
upon cost.You state beginning on page 7 , line 22 , of your
rebuttal that, quote:The flat mileage based allocation
implies that the maj or feeder lines necessary to ensure
adequate capaci ty for these customers has the same cost per
mile as simple single-phased circuits serving residential
neighborhoods.
Do you see that?
Yes.
Is it possible that the primary distribution
facility serving Coeur Mining is some of the oldest in the
system?
I really do not know the age of the plant servlng
Coeur Silver Valley.
Fair enough.Is it possible that the part of the
distribution facility serving Coeur Mining may be fully
depreciated?
Same answer:I do not know the age of the plant
that serves Coeur Silver Valley.
Is it possible that the original costs of the
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primary distribution facility servlng Coeur Mining may have
been cheaper to install per mile than the cost of new primary
distribution plant going into serVlce today?
It is possible.
Okay.Do you agree that there are 20 to 30 miles
of primary distribution circuits serving Schedule 25
customers?
Measured horizontally, yes.
Okay.And isn't it true that you supplied data
ln this case that indicates that Avista has 3,049 miles of
overhead and 808 of underground primary circuits in Idaho?
That sounds about right.I'd have to look at the
exhibi t
Well , any way how you calculate this, this
less than one percent of the primary distribution system in
Idaho.Why can't you look at your property rates for less than
one percent of your system instead of speculating the costs of
this?Less than one percent is not the same as the average?
That's something that needs to be investigated.
m not sure how di f f i cul t it wi 11 be to pull up those records
and identify them , and there may
- -
over time , you know
plant's put in , there's a repair from here to here , you know
there's a lot of things that it will take time to investigate
even if it is only 30 miles of line.It takes more time than
that.
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But that hasn't been done, to your knowledge?
It has not been done , to my knowledge.
Do you have any reason to doubt that the
what I S in your exhibits and I think in what Coeur' s
- -
what
Yankel 's testimony and exhibi ts , do you have any reason to
doubt that those are inaccurate (sic)?
We had a Supplemental Response that was sent to
Mr. Yankel from his Question No.8 that showed that there'
31.5 miles of distribution line.
Yes.That's why I think in my prlor question
asked that 25 to 30, so - - but based upon that, you believe
that's accurate?
I believe that I s our best estimate.
Okay.Okay, on page 8 of your rebuttal
testimony, line 2, you state:These circuits for Schedule
do not have the same cost per mile as a simple single-phase
circuit servlng residential neighborhoods.
Do you see that?
Yes.
Can you give a rough percentage of how many
miles - - circui t miles - - of primary is on your system that
single phase versus three phases?
No, I cannot.
Is it maybe five percent?
I really, without having the engineers in the GIS
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department look into it, I really do not know if it's 75
percent is
- -
would be the , you know, the laterals and the
little lines that go out, compared to the major trunk lines.
It would be a pure guess on my part.
Well, is it possible it's five percent?
Five percent of which kind?
The single versus three phased?
, I would think it would be somewhere in the
50 to 75 percent would be the smaller.
Okay.How many customers are in Idaho?
I don't remember wi thout looking.
494 sound right?
Electric or gas?
Okay.Actually, let me try this one for you:
106,515?
Well , I can give you a number right here if I can
find my exhibi
I believe it's from Exhibit 16.
Sixteen, Schedule Yes, 106,515 average
customers at the
- -
for the year 2002.
Okay.And 87 000 I mentioned was for residential
customers.Is that correct?
Yes.
Okay.Mr. Yankel proposes to asslgn 21 miles
from Exhibit 306 for the primary lines to Schedule 25.Is that
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correct?
m sorry, could you repeat that, the number?
Mr. Yankel proposes assigning all 21 miles of
primary lines to Schedule 25.Is that correct?
He proposes a ratio of lines in order to allocate
dollars in the ratio of 21 miles to the total miles.
Okay.Are Schedule 25 customers the only
customers that take service off of 21 or if it's 31 miles of
primary distribution?
No, they are not.
Is it true that there are 10 703, or
approximately 10 percent of all Idaho jurisdictional customers,
served off of these same distribution circuits?
Yes.
Okay.If you were going to do the engineering
study or whatever on this 21 or 31 miles of primary circuit,
would you need to remove the impact of these other 10 , 700
customers that are served off the same wires?
That is one of the contingencies that would still
have to be worked out in coming up with a fair and reasonable
allocation of cost to the 25 customers.
So it's then you say you probably should?
Yes.
Okay.If ten percent of all Idaho customers are
served from this 21 or 31 miles of prime distribution, don'
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you think that one could assume an average cost assumption
could be used?
I really hadn't thought of it that far , no.
Well, what do you think now?
I don't know.I'd have to think about it.
Well , could the reason be that why you think
these lines are more expensive be related to the fact that
they're taking 10 percent of your customers and supplying them
using less than one percent of the primary lines on the
system?
m sorry, I don't follow you.
Okay.Could the reason why you think these ines
are more expensive to be related to the fact that you are
taking 10 percent of your customers and supplying them using
less than one percent of the primary lines in the system?
Well , part of it is the 10 percent of the
customers aren't only on those 20 or those 31 miles.Those
were the number of customers that are fed off of that feeder.
The feeders continue on past the Schedule 25 customers , and
that also includes every customer on every lateral that feeds
off of that feeder because they
- -
that was how they could get
the number of customers' information off of the system.It'
not just in that 30 miles , it's the entire feeder , so it's not
10 percent.
Mr. Yankel's Exhibit 306 is a copy of data
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suppl ied by the Company.Is that correct?
Yes, it is.
It shows that there is just under one mile of
underground primary used by Schedule 25.Is that correct?
That's what that shows, yes.
Okay.Do you agree that there are 808 miles of
underground primary circuits in Idaho?
That sounds about right.It's in my workpapers.
Mr. Yankel would allocate less than one percent
of this to Schedule 25.Is that correct?
That sounds about right.
Okay.The Company's original proposal was to
allocate over ten percent of these primary lines to Schedule
based upon noncoincident peak usage.Is that correct?
Yes, it is.
Assuming all primary underground costs the same,
this would mean that ten percent of the allocation would
translate into 80.8 miles being allocated to Schedule 25.
that correct?
Assuming the math is correct.
Okay.You want to split the difference between
your original proposal and Mr. Yankel' s .Is that correct?
I split the difference from all four categories
because I really don't have a known number that I can apply to
it.
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Okay.In terms of rough numbers, if you take
Mr. Yankel' s one mile of underground primary circui ts and you
have 81 of circuits, splitting the difference results in
allocating approximately 41 miles
- -
would allocate
approximately 41 miles of underground primary being allocated
to Schedule 25.Is that roughly the outcome you had in mind?
I was not doing it in terms of miles, I was
splitting dollars.And from the four accounts that were at
issue here, the Company case allocated $13.9 million in plant.
Mr. Yankel' s cost of service run allocated $696,000 in plant to
those 14 customers.And what I did is took half of that
difference and to make it about $7.3 million to be allocated to
these large industrial customers.
Well , I appreciate your recogni tion that there'
a problem wi th the Company's allocation of costs for
Schedule 21 customers in this area and I appreciate the offer
of a compromise of splitting the difference, but after telling
me what do you see is fair about a proposal of Schedule 25 is
required to pay 41 miles of underground primary when the
Company records show only that they only use one mile of
underground?
That is something that after a study has been
done, it might end up in a future thing where the dollars would
end up on the 364 , 365, with very few dollars on the 366, 367
account , but at this point , I was not prepared to split my
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dollars between the two accounts, or the two sets of accounts,
the overhead and underground.
Well , can you tell me what is fair about
Schedule 25 paying 41 times as much for the underground prlmary
circuits when the Company admits it has no cost data available
at this time to say what those costs are?
Again , it's the same answer.I really didn't
segregate the underground and overhead when I was coming up
wi th the compromi sed pos i t ion.I treated them all the same.
MR . COX:I have no further questions.
COMMISSIONER KJELLANDER:Thank you.
Mr. Ward.
MR. WARD:No questions.Thank you.
COMMISSIONER KJELLANDER:Mr. Woodbury.
MR. WOODBURY:Thank you, Mr. Cha i rman .
CROSS - EXAMINATION
BY MR. WOODBURY:
Ms. Knox , in your rebuttal testimony, you address
Staff's recommended changes in the allocation of underground
storage costs and capaci ty release revenues, and Staff
recommends a change in the allocation used to a winter therm
allocator for underground storage costs and Staff proposed a
different allocator, one created from a combination of winter
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monthly usage and scheduled withdrawals for the capacity
release revenues.And on page 3, you state that Avista
concerned about the lack of consistency and recommends that the
winter therm allocator be used for both.
Is the allocator recommended by Staff for
capacity release revenues administratively doable by the
Company?
I would assume so.It would require more data
than the straight therm allocation factor.
Is the allocation factor recommended by Staff for
capaci ty release revenues, would that be more accurate than
uslng a winter therm allocator?
I don't know whether - - it's not very different,
they come up with essentially the same number, and so it didn't
make sense to me to add the extra complication when I come up
wi th essentially the same resul ts.
Did you run it both ways?
Yes, I did.
And when you say, "come up with essentially the
same number" --
There was approximately $200 difference when
was run with the two allocation factors compared to just the
one allocation factor that I used to Schedule 1, and then that
$200 was shared across the other customers.
All right.Thank you.
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Mr. Chairman, no furtherMR. WOODBURY:
questions.
COMMISSIONER KJELLANDER:Thank you
Mr. Woodbury.
Are there any questions from members of the
Commi s s ion?
Ready for redirect.
Just a brief follow-on.MR. MEYER:
REDIRECT EXAMINATION
BY MR. MEYER:
Ms. Knox , during your discussion with Counsel for
Coeur Silver Valley concerning their proposal for the direct
assignment of primary distribution plants, there was
considerable discussion about what is or is not presently
known.Isn't that correct?
Yes.
And absent a study, how would
- -
do we have
sufficient information of record in this case to adopt in its
entirety a direct assignment of primary distribution plant?
I do not believe so.
And what sort of things would have to be looked
at in such a study?
Some of the things have already been mentioned.
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Would you just summari ze them for me, please?
Whether there is a connection with the network
which allows backup power from another direction; how
- -
what
type of plant is from here to there, and based on the type of
plant, how much it costs; and what is required to meet the
requirements of these large industrial customers; we need to
look at how the lines are shared with other customers, and
determine a fair way to acknowledge that in the assignment.
And whatever is done has to be
- -
it has to be reasonabl e ,
has to be fair , and we have to be able to replicate it for
future studies.Or if a new Schedule 25 customer would
- -
were
to come on, we would have to be able to get the same type of
analysis for them.Tha t 's --
And, well , absent such a study in the record in
this case, do you think that your proposal to essentially meet
them halfway was a sensible accommodation for purposes of this
cost of service?
I believe it sends the right signal to
Mr. Hirschkorn that makes a change from our original base case
where that one indicated that the Schedule 25 customers
required even more of an increase than residential customers,
both of those classes being the ones that are underearning;
whereas, when we make this change, it reverses that and brings
up the Schedule 25 so they are still below unity, but they
much higher than the residential class.So it gives the
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guideline that the cost of serVlce study is intended to
provide.I think it gives an indication for Mr. Hirschkorn
that is more representative than the original base cost.
Finally, just -- I think you alluded to it, but
just in terms of that one change taken in isolation , what does
that do for that class in terms of unity, moving it from point
two - - help me out here
- -
point --
My rebut tal Exhibi t No.2 9 towards the bot tom of
the page where it says Change No., thi s is how much
difference it makes to change from -- the only change here
the primary distribution plant, moving from our base case to
our compromised posi tion.
Does that serve to increase the rate of return
for Schedule 25 from .25 to .62?
That's the return ratio goes from . 25 to .62.
The rate of return changes from 1.26 to 2.92 percent.So it
more than doubles.
Thank you.
That's all.MR . MEYER:Thank you.
COMMISSIONER KJELLANDER:Thank you.
And I believe that brings us to an opportunity to
say thank you to you, Ms. Knox.
THE WITNESS:Thank you.
(The wi tness left the stand.
COMMISSIONER KJELLANDER:Let's see.We are now
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Was it your intent to maybe squeeze in one more,at 3:30.
Mr. Meyer?
MR . MEYER:We're golng to run out of people,
except for unless we put Mr. Lafferty on, and I think the
desire was not to break his up into two separate days.And
frankly, we don't have the rest of the people here.We don't
have Mr. Hirschkorn.And really it's only, according to' my
estimates, other than Avera and Lafferty, it's Mr. Hirschkorn
who might have maybe an hour of cross.
COMMISSIONER KJELLANDER:Well , I think then in
fairness to all parties and I know that one of the Intervenors
had left today I guess not expecting there to be any additional
names put forward, that maybe it would be best to go ahead and
close down the proceedings for this afternoon and then
reconvene tomorrow morning.We'll shoot for 9: 00 a. m. and
we'll see how far we get through there.
My belief and expectation is that we had two
witnesses -- Mr. Yankel and Mr. Avery (sic) -- that have to go
on Tuesday, and so unless there's an obj ection, probably do
Mr. Avery first and then do Mr. Yankel immediately following,
and then we can fill in from there if that will work.
MR . MEYER:Sure.
COMMISSIONER KJELLANDER:Well then for today
are adjourned with the anticipation that we'll pick up tomorrow
morning at 9:00 a.
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(The hearing adjourned at 3:36 p.
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