20040416Volume XIV Part I.pdf

ORIGINAL
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AUTHORITY
TO INCREASE ITS INTERIM AND BASE
RATES AND CHARGES FOR ELECTRIC
SERVI CE .
) CASE
Idaho PYbllttUtllnl,e Oommle8lonOffio, ofthe SeoreteryReCEiveD
NO. IPC-O3 -
APR f 5 2004
Boise, Idaho
BEFORE
COMMISSIONER MARSHA SMITH (Presiding)
COMMISSIONER PAUL KJELLANDER
COMMISSIONER DENNIS HANSEN
PLACE:Commission Hearing Room
472 West Washington
Boise, Idaho
DATE:April I, 2004
VOLUME XIV - Pages 2418 - 2697
CSB: REpORTING
Constance S.Bucy, CSR No. 187
17688 Allendale Road * Wilder, Idaho 83676
[phone] * [phone]
Email csb~spro.net
\WliimLJi~~TIm;rDl
For the Staff:Lisa Nordstrom, Esq.
and Weldon Stutzman, Esq.
Deputy Attorney Generals
472 West Washington
Boise , Idaho 83720 - 0074
Barton L. Kline, Esq.
and Monica B. Moen, Esq.
Idaho Power Company
Post Office Box 70
Bo is e , Idaho 8 3 7 0 7 - 0 0 7 0
RICHARDSON & 0 I LEARY
by Peter J. Richardson, Esq.
Post Office Box 1849Eagle, Idaho 83616
RACINE , OLSEN , NYE , BUDGE
& BAI LEY
by Randall C. Budge, Esq.
Post Office Box 1391Pocatello, Idaho 83204 -13 91
Lawrence A. Gollomp, Esq.
Assistant General Counsel
U. S. Department of Energy
1000 Independence Ave., SW
Washington , DC 20585
McDEVITT & MILLER
by Dean J. Miller, Esq.
Post Office Box 2564Boise, Idaho 83701
William M. Eddie
Advocates for the West
Post Office Box 1612
Boise , Idaho 83701
GIVENS PURSLEY LLP
by Conley E. Ward, Esq.
Post Office Box 2720
Boise, Idaho 83701-2720
For Idaho Power
Company:
For Industrial Customers
of Idaho Power:
For Idaho Irrigation
Pumpers Association:
For The United States
Department of Energy:
For United Water Idaho
Inc:
For NW Energy Coalition:
For Micron Technology,Inc.
CSB REPORTING
Wilder , Idaho 83676 APPEARANCES
A P P A RA N C E S (Continued)
For Community Action
Partnership Association
0 f I daho and AARP:
Brad M. Purdy, Esq.
Attorney at Law
2019 North 17th StreetBoise, Idaho 83702
For Kroger Company:BOEHM , KURSZ & LOWRY
by Kurt J. Boehm, Esq.
36 E. Seventh Street
Suite 2110Cincinnati , Ohio 45202
CSB REPORTING
Wilder, Idaho
APPEARANCES
83676
WITNESS
Dennis Peseau
(Micron)
Anthony Yankel(Irrigators)
Don Reading
(ICIP)
Pike Teinert
ICIP)
EXAMINATION BY
Mr. Ward (Direct)
Prefiled Direct Testimony
Prefiled Rebuttal TestimonyMr. Richardson (Cross)Ms. Nordstrom (Cross)Mr. Budge (Cross)
Mr. Kline (Cross)
Commissioner Kj ellander
Commissioner Smith
Mr. Ward (Redirect)
Mr. Budge (Direct)
Prefiled Direct Testimony
Prefiled Rebuttal Testimony
Mr. Gollomp (Cross)Mr. Ward (Cross)Mr. Richardson (Cross)
Commissioner Hansen
Commissioner SmithMr. Budge (Redirect)
Mr. Richardson (Direct -Reb)
Prefiled Rebuttal Testimony
Mr. Richardson (Direct-Reb)
Prefiled Rebuttal Testimony
PAGE
2418
2423
2477
2486
2488
2490
2502
2513
2514
2516
2518
2521
2604
2631
2637
2652
2653
2660
2664
2668
2670
2678
2680
CSB REPORTING
Wilder , Idaho INDEX83676
PAGE
Admitted 2696
Admi t t ed 2696
Admitted 2696
Admi t ted 2696
Premarked
Admitted 2696
Premar ked
Admi t ted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
Admi t ted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
Premarked
Admi t ted 2696
NUMBER DESCRIPTION
FOR IDAHO POWER COMPANY:
- 61.
69.
81.
FOR THE INDUSTRIAL CUSTOMERS OF IDAHO POWER:
201.- 208.
209. Request & Response to Request No.
210. Request & Response to Request No.
211. Confidential exhibit , pages 1-
212. Request & Response to Request No.4 8
216.- 217.
FOR THE IDAHO IRRIGATION PUMPERS:
301. Comparison of Trended Values &
302. Class Rate of Returns Based Upon
Different Assumptions
303. Monthly Energy Surplus/Deficiency
Median Water , etc.
304. Monthly Energy Surplus/Deficiency
70th Percentile Water & Load , etc.
CSB REPORTING
Wilder , Idaho 83676 EXHIBITS
(Continued)
NUMBER DESCRIPTION PAGE
FOR THE IDAHO IRRIGATION PUMPERS:(Continued)
305. Average Coincident Peak Data
1999-2002 Premarked
Admi t ted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
PremarkedAdmitted 2696
PremarkedAdmitted 2696
PremarkedAdmitted 2696
PremarkedAdmitted 2696
PremarkedAdmitted 2696
PremarkedAdmitted 2696
Admi t t ed 2696
306. Monthly Peak-hour NW Transmission
Deficit Median Water/Median Load
307. Development of Irrigation Coincident
& Non-Coincident Peaks Based Upon
2003 Normalized Energy
308. Development of Resident Coincident
& Non-Coincident Peaks Based Upon
2003 Normalized Energy
309. Development of Schedule 7 Coincident
& Non-Coincident Peaks Based Upon
2003 Normalized Energy
310. Development of Schedule 9-PrimaryCoincident & Non-Coincident Peaks
Based Upon 2003 Normalized Energy
311. Development of Schedule 9-Secondary
Coincident & Non-Coincident Peaks
Based Upon 2003 Normalized Energy
312. IPC distribution plant
Subfunctionalization for the
Months Ended December 31 , 2002
313. Distribution of Energy Usage After
5 - Years of Growth
FOR NORTHWEST ENERGY COALITION:
605.- 608.
CSB REPORTING
Wilder , Idaho 83676 EXHIBITS
Continued)
NUMBER DESCRIPTION PAGE
Premarked
Admitted 2696
Premarked
Admi t ted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
Premarked
Admi t ted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
Premarked
Admitted 2696
Premarked
Admi t t ed 2696
Admi t ted 2696
Admitted 2696
Admitted 2696
FOR MI CRON TECHNOLOGY , INC.
701. Revised Computation of Dr. Avera IDCF Estimates
702. Revised Computation of Dr. Avera I s
Exhibi t No.
703. Revised Computation of Dr. Avera I s
Exhibi t No.
704. Revised Computation of Dr. Avera I s
Exhibit No. 10
705. PNM Resources , NYSE-PNM
706. IPC Class Cost of Service Study
707. IPC 5 Year Recovery of Deferred
Irrigation Rate Subsidy
708. IPC 5 Year Recovery of Deferred
Irrigation Rate Subsidy
709. IPC 5 Year Recovery of Deferred
Irrigation Rate Subsidy
710. IPC 10 Year Recovery of Deferred
Irrigation Rate Subsidy
711.- 713.
FOR KROGER COMPANY:
901.- 904.
FOR THE PUBLIC:
997.- 999.
CSB REPORTING
Wilder , Idaho 83676 EXHIBITS
BOISE , IDAHO, THURSDAY, APRIL 1 2004 1:30 P. M.
COMMISSIONER SMITH:All right, welcome
back.We'll go back on the record, and now that he'
been sworn , you can call your witness, Mr. Ward.
MR. WARD:Thank you.We call Dr. Peseau
to the stand.
DENNI S E. PESEAU,
produced as a witness at the instance of Micron
Technology, having been first duly sworn, was examined
and testified as follows:
MR. WARD:Notice how quickly he got
there.
DIRECT EXAMINATION
BY MR. WARD:
Dr. Peseau , would you state your name and
address for the record?
Yes.My name is Dennis E. Peseau.
address is 1500 Liberty Street, S., Suite 250 and that'
in Salem, Oregon.
CSB REPORTING
Wilder , Idaho
2418 PESEAU (Di)
Micron Technology83676
And in preparation for this proceeding
today, did you cause to be prepared some prefiled
testimony?
I did.
And turning first to your direct
testimony, do you have any changes or additions to that
CSB REPORTING
Wilder, Idaho
I do.I have three.Beginning on page 2
testimony?
ines 8 , 9 and 10 should be removed.
Okay.
page 1.
COMMISSIONER SMITH:I I m sorry.
MR. KLINE:Which page?
THE WITNESS:It I S indicated as page
COMMISSIONER SMITH:But it's really
THE WITNESS:It's really page 1 , that'
correct.Lines 8 , 9 and 10 should be removed.
background?
Bart.
MR. KLINE:Is that your educational
THE WITNESS:I have been educated,
MR. WARD:
inadvertently failed to attach the resume.
Perhaps I should explain.
change?
BY MR. WARD:Would you give us your next
2419 PESEAU (Di)
Micron Technology83676
Yes.On page 4 , line 22 , I read Mr.
Obenchain's rebuttal and apparently a question asked by
my counsel yesterday and I think I could make this a
little more clear for the record
Denny, would you get a little closer to
the Mike?
Yes.Page 4 , line 22 , the first two words
there are rate base" and after that insert for all new
large plant investments" and then it continues.
Would you give us that again for those who
didn't catch it?
Yes.Between the words "base" and "to"
insert for all new large plant investments.
Okay.
Turning to page 5, line 4 , between the
words "expenses" and "that" should be inserted
associated with its major plant additions " again
associated with its major plant additions.That
concludes my corrections.
Okay, and in connection with your direct
testimony, did you have cause to be prepared Exhibit
Nos. 701 through 708?
Yes.
Okay, with those corrections, if I asked
you the testimony that appears - - the questions that
CSB REPORTING
Wilder , Idaho
2420 PESEAU (Di)
Micron Technology83676
appear in your prefiled testimony today, would your
answers be the same?
They would.
And are those exhibits still true and
correct to the best of your knowledge?
Yes, they are.
MR. WARD:I III make my motion after we
get to the rebuttal , Madam Chair.
BY MR. WARD:Now , Dr. Peseau, did you
also cause to be prepared rebuttal testimony?
I did.
Do you have any additions or corrections
to that testimony?
No.
And did you prepare Exhibits No. 709
through 710 in connection with that testimony?
Yes , I did.
And again, if I asked you the questions
that are contained in your rebuttal testimony today,
would your answers be as given?
They would.
MR. WARD:With that, Madam Chair , I move
that we spread the direct and rebuttal testimony of Dr.
Peseau on the record as if read in full and ask that
Exhibit Nos. 701 through 710 be marked for
CSB REPORTING
Wilder , Idaho
2421 PESEAU (Di)
Micron Technology83676
identification.
COMMISSIONER SMITH:If there is no
obj ection, it is so ordered.
(The following prefiled direct and
rebuttal testimony of Dr. Dennis Peseau is spread upon
the record.
CSB REPORTING
Wilder , Idaho
2422 PESEAU (Di)
Micron Technology83676
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Dennis E. Peseau.My business address is
Suite 250, 1500 Liberty Street, S., Salem, Oregon
97302.
BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
I am the President of Utility Resources, Inc.
( "
URI"
) .
URI has consulted on a number of economic
financial and engineering matters for various private and
public entities for more than twenty years.
HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE IDAHO
PUBLIC UTILITIES COMMISSION?
Yes , on many occasions.
FOR WHOM ARE YOU APPEARING IN THIS CASE?
I am appearing on behalf of Micron Technology, Inc
Micron"
) .
WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
Micron has asked me to review Idaho Power Company I
application and make such recommendations to the
Commission as I believe appropriate.
PLEASE PROVIDE A SUMMARY OF THE RECOMMENDATIONS YOU
WILL BE MAKING IN THIS TESTIMONY.
The first part of my testimony addresses two revenue
requirement issues.I will first explain why the
Company I s filing results in a mismatch of revenues and
expenses and
2423
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
suggest two al ternati ve methods of correcting this
mismatch.I will also discuss Idaho Power I s cost of
capital recommendation and point out the ways in which
is overstated.
The second portion of my testimony deals with
Idaho Power I s class cost of service studies and the
Company I S rate spread recommendations.I will propose
some changes to the cost of service study and recommend a
method of eliminating the existing subsidy of the
irrigation class of customers.
BEFORE WE TURN TO THESE ISSUES, ARE THERE ANY
GENERAL OBSERVATIONS YOU WOULD LIKE TO MAKE ABOUT THE
COMPANY'S FILING IN THIS CASE?
Yes.As the Commission is well aware , Idaho Power
used a "hybrid" 2003 test year in this case.That is
the Company used approximately 6 months of actual test
year data and 6 months of estimated or budgeted data.
The Commission has allowed this type of rate case
presentation in the past, although it has generally been
viewed as a second best al ternati ve to be used only when
severe inflation makes "regulatory lag" a serious
problem.I have some reservations about the use of this
methodology in today' s low inflation environment.But my
reason for drawing the Commission I s attention to the
2424
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
hybrid test year is not to protest its use in this case,
but rather to explain how it will complicate the
proceedings and change the nature of the Commission 1 s
deliberations.
HOW DOES A HYBRID TEST YEAR COMPLICATE THE
PROCEEDINGS?
In two ways.First, when actual figures for the
second half of the year are substituted for estimates,
the Staff will have to conduct what amounts to a second
audit to confirm that the changes are appropriately made.
No other party has the resources to conduct this
2425
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3-
trust, but verify " exercise, so it obviously increases
the burden on the Staff , as well as all parties I reliance
on their diligence.
The second complicating factor is that some of
the adjustments proposed by the Staff and Intervenors
cannot be quantified with precision because the "base
case" that we are working with will presumably change
when all the final numbers are in.This is apt to create
some confusion during the hearings, and the Commission
may want to give some thought to how to incorporate into
the evidentiary record the true-up revisions to both the
Company I S base case and the Staff and Intervenors
adj ustments.
Revenue Requirement Issues
LET 1 S TURN NOW TO THE MERITS OF THE CASE.YOU
EARLIER STATED THAT IDAHO POWER 1 S CASE IN CHIEF CONTAINS
A MISMATCH OF REVENUES AND EXPENSES.PLEASE EXPLAIN WHAT
YOU MEAN BY THE WORD "MISMATCH.
Idaho Power calculates its test year revenues in a
straightforward manner.For the first six months of the
test year, actual data is used.proj ections are employed
for the last six months.These proj ections will
ultimately be replaced by actual figures before the close
of the proceedings.Thus, by the end of the proceedings
test year revenues will consist of 2003 actual figures,
2426
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
normalized" for weather and other standard adjustments.
On the other side of the ledger, expenses and
rate base are treated in a much different manner.Again
the Company uses six months of actual data and six months
of proj ect ions.But it then goes on to annualize
operating and maintenance expenses and rate base for all
new large plant investments to year-end levels.
effect, this annualization treats these costs as if
year-end levels had been in effect throughout the test
This is a clear mismatch of revenuesyear.
2427
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
and expenses because revenues are centered" on June 3 0
2003, while rate base and expenses are centered on
December 31 , 2003.
To make this mismatch worse, Idaho Power
further adds allegedly "known and measurable changes" in
rate base and expenses associated with its major plant
additions that it forecasts for the period from January
, 2004 through May 31 , 2004.These adjustments include
rate base additions of $18,165,002 , operating and
maintenance increases of $9,907 923, associated
depreciation increases of $447.375, and an adjustment for
a 2004 increase in depreciation rates totaling
$5,976 270.
The net effect looks very much like a partially
projected test year ending on May 31, 2004 for rate base
and expenses, matched against revenues centered on June
30, 2003.The resulting mismatch overstates Idaho
Power 1 S revenue requirement and is not defensible.
HOW SHOULD THIS MISMATCH BE CORRECTED?
There are basically two alternative remedies
available.The first would be to reverse the annualizing
entries and properly match test year averages on both
sides of the ledger.The second alternative is to
annualize revenues in the same manner as rate base and
expenses.
2428
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3 -
DO YOU HAVE A PREFERENCE BETWEEN THESE TWO
ALTERNATIVES?
On the whole, I think annualizing revenues to 2003
year-end levels is the preferable course for two reasons.
First, it is much simpler to annualize revenues than to
back out Idaho Power I s annualizing adj ustments from
numerous cost and rate base categories.Moreover
annualizing revenues produces a more forward-looking
resul t than reversing the expense and rate base
annualizations.
2429
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
I recognize , however , that when faced with a
similar mismatch problem in the last Idaho Power rate
case, the Commission ordered a reversal of the improper
annualization of expenses.Order No. 25880, pp. 3-
theory this course of action is equally acceptable , but
it poses a greater risk of computational errors just
because of the number of adjustments required.
Consequently, I continue to recommend annualizing
earnings instead.
HAVE YOU CALCULATED AN APPROPRIATE ANNUALIZATION
ADJUSTMENT FOR TEST YEAR REVENUES?
Assuming a revenue growth rate of 4.06%, annualizing
revenues to year-end levels would add $9,731,765 to Idaho
Power I S test year revenues.This provides an accurate
match between revenues and rate base and expenses.
SHOULD IDAHO POWER I S PROPOSED 2004 KNOWN AND
MEASURABLE CHANGES BE ADDED TO THE TEST YEAR BASE CASE?
Onl y in part.Adding known and measurable changes
to a test year base case is a legitimate regulatory tool,
but it must be used with extreme caution because of the
high potential for abuse.Post-test year adjustments
should only be accepted when they are in fact truly known
and measurable.In order to qualify, a proposed
adjustment must be virtually certain to occur , and its
revenue requirement impact must be precisely and reliably
2430
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3 -
quantifiable.
Only one of Idaho Power I s proposed adjustments
meets this test.The 2004 increase in depreciation rates
is in fact certain to occur, and its impact on revenue
requirements can be quantified down to the penny.This
$5,976,220 known and
2431
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
measurable adj ustment should be accepted.The other
proposed adj ustments should be rej ected.
WHAT IS YOUR RATIONALE FOR REJECTING THE REMAINING
ADJUSTMENTS?
The other proposed adjustments fall into two
separate categories.Of the $9,907 923 of known and
measurable changes to operations and maintenance costs,
$5,114,821 is for a 7% incentive pay package to be
implemented in 2004.My understanding is that this
incentive package is over and above normal pay increases,
and is designed as a reward for cost savings to be
realized as a result of extraordinary employee efforts.
The first problem , of course , is that this is
not truly a known change because the incentive will
presumably not be paid if the savings don I t actually
materialize.Furthermore, this type of incentive pay
makes no sense unless it results in savings that exceed
the incentive pay, in which case there is no need to
further reward the Company for a program that will be
essentially self funding.In fact, if the incentive pay
program is successful, the net effect should be a
reduction, rather than an increase, in Idaho Power I
revenue requirement.
Thus, this adjustment fails both elements of
the test.It is far from certain to occur, and its net
2432
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
impact on revenue requirements is impossible to quantify,
and in fact could as easily be positive as negative.
PLEASE EXPLAIN WHY THE REMAINING GROUP OF
ADJUSTMENTS SHOULD BE DISALLOWED.
2433
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
The remaining proposed adjustments are essentially
proj ected or budgeted increases in rate base (with
associated depreciation) and operating and maintenance
expenses.These proj ections fail the known and
measurable test on a number of grounds.
In the first place, they are not sufficiently
certain to occur.I f budgeted figures were deemed
sufficiently reliable for ratemaking purposes, the
Commission would presumable accept a fully proj ected test
But to the best of my knowledge, the Idahoyear.
Commission has never accepted a fully proj ected test year
because of the inherent untrustworthiness of proj ected
figures.
Second, the net revenue requirement impact of
these budgeted 2004 expenditures is unknown because Idaho
Power has focused on only one side of the cost-benefit
equation.Like other businesses, utili ties generally do
not make additional investments or increase their
expenses unless they can generate additional revenues and
profits, either by serving additional customers, or by
cutting costs or increasing margins.There is no reason
to assume this is not the case here.The proj ected
expenditures Idaho Power has identified must be presumed
to generate additional revenues or other benefits that
would offset their costs, in whole or in part.But Idaho
2434
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
Power has made no attempt to identify these offsetting
benefits.Instead , it has focused on only one side of
the ledger.Stated another way, this is another mismatch
problem, where the Company is attempting to recover for
proj ected cost increases while ignoring the increased
revenues that would occur in the corresponding time
frame.This violates one of the most important tenets of
ratemaking, and should be rej ected.
2435
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
YOU EARLIER STATED THAT KNOWN AND MEASURABLE
ADJUSTMENTS SHOULD BE APPROACHED WITH CAUTION BECAUSE OF
THEIR HIGH POTENTIAL FOR ABUSE.WHAT DID YOU MEAN BY
THAT STATEMENT?
One of the obvious problems with known and
measurable changes to test year results is that the
utility has every incentive to identify changes that will
increase its revenue requirement, but no incentive to
ferret out changes that would decrease that revenue
requirement.I am not suggesting that Idaho Power would
deliberately conceal changes that would reduce its
revenue requirement, just that it has no reason to look
for them.
CAN YOU PROVIDE AN EXAMPLE?
Idaho Power I s Exhibit No. 14 calculates theYes.
Company 1 S embedded cost of long-term debt.As that
exhibit shows, one of Idaho Power's nine first mortgage
bonds, a $50,000 000 issue with an effective cost of
54%, is scheduled to come due in March of 2004.
today s cost of capital , Idaho Power can roll this issue
over at a savings of at least 269 basis points.This is
a known and measurable change that will obviously
decrease Idaho Power 1 s cost of capital and revenue
requirement, but the Company failed to include it in its
known and measurable adjustments.
2436
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3 -
I will quantify the amount of this adjustment
in my discussion of cost of capital issues, but my point
here is that Idaho Power obviously did not look very hard
for known and measurable changes that would benefit
ratepayers rather than shareholders, or it would have
included this item in its list of changes.This
naturally makes one wonder what other favorable changes
could be identified if Idaho Power had an incentive to
seek them out.In any event, the one sided nature of the
Company I S incentives is why
2437
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
pointed out there is a high potential for abuse in the
use of known and measurable changes.
PLEASE SUMMARI ZE YOUR TESTIMONY ON REVENUE
REQUIREMENT ISSUES.
Idaho Power I s proposed test year contains a gross
mismatch of revenues and expenses.I recommend remedying
this defect by annualizing revenues to year-end 2003.
This will reduce Idaho Power's requested increase by
$9,731 765.
I further recommend that the Commission rej ect
all of Idaho Power s post-test year adjustments except
the known and measurable increase in depreciation rates.
This reduces the Company's claimed Idaho jurisdictional
revenue requirement by $11 786,222.
Cost of Capital Issues
HAVE YOU REVIEWED DR. WILLIAM AVERA'S TESTIMONY
REGARDING THE COST OF EQUITY FOR IDAHO POWER?
Yes, I have.
WHAT IS YOUR INITIAL IMPRESSION OF THAT TESTIMONY?
Dr. Avera, like most cost of capital witness,
discusses several alternative methods of determining
Idaho Power I s cost of equity.In general , most of these
approaches follow modern cost of capital theories and
methodologies.But his presentation suffers from stale
capital market data and, with the updates I identify
2438
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-03 -
below, his proposed return on equity estimate must fall
dramatically.I also disagree with his general
characterization of the state of the electric utility
industry.
2439
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
lOa
WHY DO YOU DISAGREE WITH DR. AVERA
CHARACTERIZATION OF THE INDUSTRY?
Dr. Avera I s testimony is replete with references to
the electric utility industry s travails-from the
California and Pacific Northwest market crises, to the
Enron meltdown , and more recent problems such as the
blackout in the East and ongoing bat tIes over the
regulation of regional transmission grids.All of these
observations are accurate enough , but taken as a whole,
this unrelenting litany of bad news paints too bleak a
picture of the industry.The fact is that the
overwhelming majority of the nation I s electric utilities
have weathered the recent disasters, and are in the
process of getting "back to basics" and strengthening
their core business.They are doing so in an economic
environment that is nearly ideal for utilities.Interest
rates are hovering just above their post World War
lows, and inflation is virtually nonexistent.Yes, there
are still problems and uncertainties in the industry, but
this is not unique to electric utilities.As the old
Wall Street adage says, all stocks "must cl imb a wall of
worry. "
HAVE THE SHAREHOLDERS OF IDAHO POWER FARED
RELATIVELY WELL IN THIS PAST YEAR?
The calming of energy markets , and the upwardYes.
2440
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
trend in the stock market, has resulted in a rate of
return to Idaho Power shareholders during the past year
of more than 40%, which includes both price appreciation
and dividend yield.While the previous few years
produced some negative returns, the past year has
generally provided a good investment environment.This
suggests the Dr. Avera 1 s doom and gloom outlook for the
industry, and Idaho Power in particular , is not widely
shared by investors.
2441
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11a
TURNING FROM GENERAL OBSERVATIONS TO A MORE SPECIFIC
ANALYSIS, WOULD YOU PLEASE DESCRIBE THE METHODS DR. AVERA
EMPLOYS IN HIS ATTEMPT TO DETERMINE IDAHO POWER I S COST OF
EQUITY?
Dr. Avera uses two basic approaches in his cost of
equity analysis: a discounted cash flow analysis and a
risk premium analysis.For each approach, he offers a
number of variations using alternative analytical
methods.The average of all these approaches is an
indicated cost of equity of 11.0%.This indicated result
is no longer valid.
WHY NOT?
Changing capital markets have changed the inputs to
all of Dr. Avera's analytical methods.This naturally
produces different results than Dr. Avera obtained when
he performed his analysis.The following table shows the
current results and the variation from Dr. Avera I s
original estimates.
Methodology Dr.Avera Updated Difference Exhibi t
DCF 10.10.701
Risk Premium 11.10.702
Risk Premium 10.703
CAPM 11.10.704
Average 11.10.
2442
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
The supporting calculations for this table appear in my
Exhibits Nos. 701 through 704.701 and 703 follow Dr.
Avera 1 S methods exactly with no changes other than
updated numbers.702 contains a correction described
below to make the analysis consistent with Exhibit 703.
704 is revised to reflect the market recovery during the
last half of 2003.
2443
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
12a
PLEASE BRIEFLY EXPLAIN YOUR UPDATES AND REVISIONS TO
DR. AVERA 1 S RATE OF RETURN METHODS.
My updates are each simple and straightforward.Dr.
Avera developed his analyses using capital market
information from last summer, and both debt and equity
markets have improved enormously since that time.
Exhibit 701 takes Dr. Avera's discounted cash flow
("DCF") method and simply plugs in an updated figure for
dividend yield calculation.As shown , changing from the
August 2003 figure used by Dr. Avera to that of February
13, 2004 , reduces his dividend yield from 4.4% to 4.0%.
If I use his excessively high estimated growth rate of
, which I nevertheless accept for the purpose of
Exhibit 701 , his DCF recommendation drops to 10%.
My Exhibit 702 makes one simple correction to
Dr. Avera's "authorized return" risk premium analysis.
Note that on his Exhibit 8 in column (b) he uses the
Average Public Utility Bond Yield in his calculations.
But, on his following exhibit, Exhibit 9, Dr. Avera uses
the yield on single A- rated bond.Most Idaho Power debt
instruments carry the A- rated credit standing.The
whole point of these exercises is to solve for Idaho
Power's risk premium, not that of the average public
utility.Dr. Avera I s substitution biases his estimates
upward, and I have corrected this inconsistency by using
2444
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
A- rated bond yields throughout.Exhibit 702 shows that
updating Dr. Avera's risk premium analysis for a February
5, 2004, A- rated utility bond yield reduces his estimate
of Idaho Power s equity return from 11.2% to 10.59% (the
sum of 5.7% and 4.89% on Exhibit 702) .
My Exhibit 703 replicates Dr. Avera s "realized
return " method exactly, and only updates interest rates
for A- rated bonds from Dr. Avera s August 2003 figure of
79%
2445
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
13a
(Avera, page 62 , line 8) to the current A-rated yields of
7% .This single update reduces his risk premium method
from 10.8% down to 9.71%, as shown on my Exhibit 703.
My Exhibit 704 updates Dr. Avera s capital
asset pricing model (" CAPM") analysis for the recent
changes in interest rates
("
risk- free rate I') and the
market risk premium.The interest rate shown on Avera
Exhibit No. 10 of 5.39% is, as of February 13, 2004,
98% .Dr. Avera's market risk premium , the derivation
for which I disagree, has fallen from 8.85% to 5.64%.
The correct market risk premium to use at this time is,
however, 7.0%, as shown in my Exhibit 704.The sum of
these updates reduces Dr. Avera I S CAPM estimate of equity
return from 11.7% to 10.0%.
ARE THESE THE ONLY CORRECTIONS YOU HAVE TO DR.
AVERA'S ANALYSIS?
No.One of his discounted cash flow ("DCF")
approaches produces unreasonable results and should not
be used by the Commission in any fashion.
PLEASE EXPLAIN WHY THI S DCF METHODOLOGY SHOULD BE
DISCARDED?
As Dr. Avera points out, the basic formula for
computing cost of equity using the discounted cash flow
analysis is relatively simple:
Cost of Equity = Dividend Yield + Growth Rate
2446
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
The initial question is what data is to be used to
determine the values for the dividend yield and growth
rate portions of the equation?
Dr. Avera's DCF methodology relies very heavily
on a reference group of other utilities selected from
Value Line I s western electric utilities group to develop
Idaho Power s cost of equity.Dr. Avera uses the average
4% dividend yield for this group to supply the dividend
yield portion of the equation.(As I explained above
this yield has
2447
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
14a
now fallen to 4.0%.He then uses three separate methods
to estimate the growth rate.The average of analysts
earnings growth proj ections for the electric utility
industry produces a growth rate of 4.6%.His
sustainable growth rate" analysis indicates a growth
rate of 4.7%.Finally, he finds that the 10-year
historical average earnings growth rate for his proxy
group is 7.3 %.Taking these three approaches into
account, he concludes investors currently expect growth
on the order of 5.0 to 7.0 percent for the average firm
in the electric utility proxy group.Avera Direct,
55.Combining the 4.4% dividend yield with the mid point
(6.0%) of his growth estimates produces his DCF cost of
equity estimate of 10.4%.
IS THIS A REASONABLE METHOD OF ESTIMATING IDAHO
POWER'S COST OF EQUITY?
The methodology is not unreasonable, but its
implementation is severely flawed.The most significant
problem stems from Dr. Avera s selection of the utilities
he uses in his analysis.Value Line I s western electric
utility group is actually comprised of 15 companies.
From these companies, Dr. Avera understandably eliminates
those that do not pay a dividend.But he then goes on to
discard firms rated below investment grade by Standard &
Poors, as well as Idaho Power itself.The result is that
2448
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -
his dividend yield group consists of only 8 companies,
and only 6 data points are used in his calculation of
historical growth rates.
WHY IS THIS AN IMPLEMENTATION FLAW?
The first problem with this selection process is
that it high grades the proxy group.The second problem
with this approach is that the group is so small that
there is a serious risk
lDr. Avera refers to the analysts' proj ections in his testimony but
inexplicably does not include them in his final calculations.
2449
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
15a
of sampl ing errors.This is particularly true of Dr.
Avera I s historical growth rate analysis , where he uses
only 6 data points for his calculations.
HOW SHOULD THESE PROBLEMS BE CORRECTED?
The dividend yield portion of the DCF equation can
be improved by adding back the 4 dividend paying
companies that Dr. Avera arbitrarily removed.These 12
companies have an average dividend yield of 3.79%, which
is remarkably close to IDACORP' s actual dividend yield of
9% .
CAN DR. AVERA'S HISTORICAL GROWTH RATE ANALYSIS BE
CURED IN A SIMILAR FASHION?
Unfortunately, no.The boom and bust in energy
trading and the disaster in the California market
produced wildly erratic year to year results in recent
years for most of the electric utilities in the western
Uni ted States.Consequently, most of those in the Value
Line western utilities group have negative 5 and 10-year
growth rates.The five companies with positive growth
rates for both periods are not enough to comprise a valid
sample, and even if they were, they are clearly not
representative of the western electric utility industry
as a whole.
WHY DO YOU SAY THEY ARE NOT REPRESENTATIVE OF THE
WESTERN ELECTRIC UTILITY INDUSTRY?
2450
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
For both the 5 and 10 -year historical calculations,
there are only 6 data entries, and only 5 companies show
posi ti ve growth rates for both periods. This is too small
a sample to be statistically reliable.
Moreover , the sample is not really a sample of
electric utilities.One half of the companies in the
sample derive the maj ori ty of their revenue from
activities other than
2451
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
16a
electrici ty sales.MDU is a diversified conglomerate
invol ved in oil , gas, and coal production, gas
transportation and delivery, and heavy construction.
gets only 12 % of its annual revenues from its electric
utility division.Black Hills is also heavily involved
in energy production and other activities, with only 38%
of its revenues derived from electricity sales.Like
MDU, Black Hills I historic growth rate is heavily
influenced by fossil fuel prices.Finally, Sempra is the
nation I S largest natural gas distributor , with roughly 5
times as many natural gas customers as electric
customers.
The third flaw in Dr. Avera I s historical
average approach is that it is distorted by unusual
earnings fluctuations.To illustrate this point I have
attached the Value Line analysis for PNM Resources as
Exhibit 705.Even a cursory review of this data reveals
that PNM I S growth rate is nothing like the listed 5 and
10 -year averages of 9.5% and 19%, respectively.In fact,
PNM began the 18-year period covered by Value Line's data
array by earning $2.00 per share , the same figure that
is proj ected to earn in 2004!
WHAT DO YOU CONCLUDE FROM THIS ANALYSIS?
My conclusion is that Dr. Avera I s historical average
approach should be discarded in its entirety as
2452
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3-
inherently unreasonable.This leaves two al ternati ve DCF
methods for consideration.Using the corrected 3.
yield figure that I discussed earlier, Dr. Avera I s two
remaining DCF cost of equity estimates are:
1 )Analysts I growth rate -
8% yield + 4.6% growth = 8.
2 )Sustainable growth -
8% yield + 4.7% growth = 8.
DO YOU HAVE AN ESTIMATE OF IDAHO POWER I S COST OF
EQUITY BASED ON YOUR CORRECTIONS TO DR. AVERA I
CALCULATIONS?
Yes.In effect, I am offering five different
approaches that produce cost of equity results
2453
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3-13 17a
that range from 8.4% to 10.6%.The midpoint of this
range is 9.5%.I personally would not use the low end of
this range because I expect interest rates to increase
somewhat in the not too distant future.On the other
hand, an historical perspective and common sense suggest
that the high end of the range is unreasonable even if
interest rates move considerably.
WHAT DO YOU MEAN WHEN YOU REFER TO AN HISTORICAL
PERSPECTIVE?
Proceedings on Idaho Power 1 s last rate case were
conducted in 1994.In the Commission I s January, 1995
order it found that Idaho Power I s cost of equity was 11%.
According to Value Line, the average yield on AAA
corporate bonds during 1994 was 8%, and the earnings
yield (the reciprocal of the 14.2 price to earnings
ratio) for the Dow Jones Industrials was 7%.Barron I S
February 14th edition lists the current yield on an index
of high grade corporate bonds as 5.73% and the Dow Jones
Industrial 1 s earnings yield as a bit below 5%.
Obviously investors I expected earnings on both
bonds and stocks have dropped dramatically since 1994 , by
200 basis points or more based on the bond and earnings
yields cited above.In this environment, Idaho Power I
request for an 11.2 % return on equity, some 20 basis
points higher than the Commission authorized in 1995, is
2454
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3-
unreasonable on its face.
YOU STATED EARLIER THAT YOU WOULD ALSO HAVE A
CORRECTION TO IDAHO POWER I S COST OF DEBT CALCULATION.
HAVE YOU RECALCULATED IDAHO POWER I S EMBEDDED DEBT COSTS
TO REFLECT THE REFINANCING OF THE $50 MILLION FIRST
MORTGAGE BONDS?
2455
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3-18a
Yes.The current A-rated utility bond rate is 5.
as opposed to the 8.54% issuance coming due.Using the
7% and the average level of issuance expense associated
wi th the refinancing, the current embedded cost of debt
for Idaho Power is 5.839%.
Cost of Service Issues
HAVE YOU REVIEWED THE COST OF SERVICE STUDY OFFERED
BY IDAHO POWER IN THIS CASE?
Yes.
WHAT DO YOU CONCLUDE FROM YOUR REVIEW?
In general , I conclude that Idaho Power I s cost of
service study is consistent with sound costing methods
and prior Commission orders, with one very significant
exception.The exception is that Idaho Power witness Ms.
Brilz has modified demand allocators in a manner that not
only departs from prior Commission orders , but departs
from sound economic principles as well.
WHERE HAS MS. BRILZ I S COST STUDY DEPARTED FROM SOUND
ECONOMIC PRINCIPLES?
Economic principles require that the allocation of
costs reflect cost causality, or the degree to which each
class caused or contributed to the costs being allocated.
In a cost of service study, this requires identifying the
main usage factor causing a specific cost, and then
allocating that cost to specific rate classes based on
2456
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-O3 -13
each class I s contribution to that main usage factor.For
example, generation and transmission demand costs are
caused primarily by peak demands at specific times during
the year.But Idaho Power I s cost of service study is
based, in one important particular , on allocators that do
not reflect customer usage factors that cause the costs
being allocated.
2457
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-O3 -19a
CAN YOU IDENTIFY THE SPECIFIC ALLOCATORS USED BY
IDAHO POWER THAT ARE NOT BASED ON SOUND ECONOMIC
PRINCIPLES?
Yes.Idaho Power Company uses generation and
transmission demand allocators that are simple averages
of a weighted 12 CP allocator and an unweighted, or
equal , 12 CP allocator.As a result, the allocations of
generation and transmission demand costs are based in
part on customer demands that do not cause or contribute
to the costs being allocated.The result is that the
Company I S demand allocators attribute excess costs to
off -peak and shoulder load periods of the year.This is
not sound economics and cannot lead to sound ratemaking.
HAS IDAHO POWER COMPANY EVER USED AN AVERAGED
ALLOCATOR BEFORE?
Not for at least two decades.Idaho Power Company
proposed the use of a weighted 12 CP allocator in the
I006-185 case in 1983.In every cost of service study
presented by Idaho Power Company in a rate case since
then until this case, the Company has endorsed and
utilized the weighted 12 CP method for generation and
transmission demand.
DOESN I T MS. BRILZ STATE THAT IDAHO POWER I S COST OF
SERVICE STUDY IS THE "
...
SAME METHODOLOGY AS PREVIOUSLY
FILED BY THE COMPANY IN CASE NO. U-I006-185, CASE NO.
2458
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-03-
I006-265A , AND CASE NO. IPC-94-5 AND USED BY THE
COMMISSION IN THE ALLOCATION OF REVENUE REQUIREMENT AMONG
CUSTOMER CLASSES IN THOSE CASES.
Yes she does.However , I participated in each of
those cases, and Idaho Power used only the weighted 12 CP
to allocate generation demand and transmission costs.
never used a
2459
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-03-20a
simple average of the weighted 12 CP and an unweighted
CP allocator.Ms Brilz I s statement is both misleading
and wrong.
MS. BRILZ ALSO INDICATES THAT THE WEIGHTED 12 CP
METHOD WAS USED BY THE COMMISSION TO ALLOCATE COSTS.DID
THE COMMISSION EVER USE AN AVERAGE OF THE WEIGHTED 12 CP
AND ANY OTHER ALLOCATOR?
No.In those cases cited by Ms. Bril z, the
Commission reviewed several al ternati ve cost of service
studies , including the weighted 12 CP method.In each of
those cases, the Commission endorsed the weighted 12 CP
as the most appropriate cost of service study to use in
allocating costs and setting rates.
Idaho Power first submitted the weighted 12CP
methodology In Case No. U-I006-185.In reviewing that
study, the Commission found:
We find: For the limited purposes for which weuse cost-of-service data in allocation of the
revenue requirement among the customer classes
Idaho Power I s weighted 12 coincident peak study
may be reasonably used to represent costs.Al though there could be improvements in both
W12CP studies presented in this case, the
similarities in the results obtained from both
of them , which were the best cost -of - service
studies presented in this case, show that we
may use the Company's W12CP for the next step
of the rate allocation process.
Order No. 17856, p. 13.
In Case No. U-I006-265A , the Commission again
2460
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03 -
reviewed the weighted 12 CP method presented by the
Company, as well as several other al ternati ve studies
presented by the Company and other parties.It found:
B. The Choice of the Cost-Of-Service Study tobe Used. Idaho Power prepared fivecost -of - service studies: A Weighted Coincident Peak (IPCo WI2CP) study, a 12Coincident Peak (IPCo 12CP) Study, an Average
and Excess Demand (IPCo AED) study, a PositiveExcess Demand (IPCo PED) study, and a Modified
Positive Excess Demand
2461
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03 -21a
(IPCo MPED) study. In addition , the City of
Boise presented two variations of the Company I
W12CP called Boise I and Boise II. FMCpresented a modified weighted 12 coincidentpeak (FMC MWI2CP) study and a 7 coincident peak(FMC 7CP) study. The Staff presented an
alternative weighted 12CP (Staff WI2CP) studyand an unweighted 12CP (Staff UI2CP). The
resul ts of those studies are shown on Table 6on the following page. For the reasons stated
in the following pages of this Order , we will
use the Company I S W12CP as a starting point in
our allocation of revenues among the customerclasses.
Order No. 21365.It is worth noting that, in this
order , the Commission specifically rej ected the
unweighted 12 CP proposed by Staff.
Finally, in the most recent Idaho Power rate
case, the Commission again endorsed use of the weighted
12 CP methodology, not an al ternati ve methodology or some
averaging of different methodologies.
In this case, the Commission was presented with
only one cost -of - service study, a study based
on the W12CP method prepared by the Company,and the IPCo study as modified by Staff. Thetestimony in this case almost universally
supports the use of a W12CP methodology, and
thus we find it appropriate and reasonable to
once again utilize the W12CP methodology to
establish revenue requirement for the customerclasses.
Order No. 21365 , p. 13.
CAN YOU THINK OF ANY REASON THAT IDAHO POWER COMPANY
WOULD CHANGE TO A NEW ALLOCATION METHODOLOGY AFTER USING
THE WEIGHTED 12 CP METHOD FOR SO LONG?
2462
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-13
I can think of no sound reason based on economic
principles.The only other reason I can think of is
based on the actual result that occurs with the new
allocation methods.All classes with the exception of
the irrigation class, Schedule 24 , receive higher
allocations of generation and transmission demand costs
wi th Idaho Power I s new averaged allocator as compared
with the weighted 12 CP allocator.The irrigation class
receives a smaller allocation of generation and
transmission demand costs.This is shown on Ms. Brilz
2463
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-03-22a
Exhibit No. 40.Thus, Idaho Power's averaged allocator
reduces the measured size of the subsidy to the
irrigation class, when in fact the subsidy has grown.
The irrigation subsidy is still extremely large, but
would be even larger if the correctly weighted 12 CP
method were used.I can only assume that Idaho Power
Company made the decision to change allocation methods in
this case to understate the severity of the problem with
irrigation rates.
HAVE YOU DETERMINED HOW THE COST OF SERVICE STUDY
WOULD CHANGE IF THE WEIGHTED 12 CP METHODOLOGY WERE USED
RATHER THAN IDAHO POWER I S NEW AVERAGED 12 CP?
Yes, I have.I used Idaho Power Company I s cost of
service model to reallocate costs using the weighted
CP allocators for generation and transmission costs,
rather than Idaho Power's new averaged 12 CP allocators.
The results of that study are shown in my Exhibit 706.
As is obvious in Exhibit 706 and as I discussed above
the cost of service for all classes other than the
irrigation class are lower in my study compared to the
Company I S, and the cost of service for the irrigation
class is higher.I urge the Commission to stick with its
prior informed conclusions and continue to endorse the
sound and proven weighted 12 CP allocators.
The Irrigator Subsidy Issue
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DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-
WHAT DO YOU MEAN BY THE TERM " SUBSIDY" IN THESE
PROCEED INGS ?
I use the term subsidy to refer to any intentional
consistent and significant underpricing of electricity to
a class of Idaho Power customers, compared with the
actual cost of serving the particular customer class.
The reason I term this shortfall between the rates
2465
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03 -23a
paid and the cost of service a subsidy is because, under
normal ratemaking, any shortfall to a class is made up by
overcharging some or all of the remaining customer
classes.
IS THE SUBSIDY ISSUE RELEVANT TO THESE PARTICULAR
PROCEED INGS?
Yes, very much so.Under Idaho Power's present rate
structure , the irrigation class is being subsidized by
$40.5 million annually.This subsidy is not good for
Idaho and must be addressed in these proceedings.
Allowing it to continue is detrimental to residential
commercial and industrial customers, and, in the long
run , even to the irrigators themselves.
ARE ALL CLASSES OF CUSTOMERS OTHER THAN IRRIGATORS
BEING OVERCHARGED AT PRESENT?
Yes.The following table provides an approximate
breakdown of Idaho Power I s calculated subsidy of $26
million annually that results from its proposed rate
design in this case.It is important to note that this
is the subsidy from other classes even after the
irrigation class is assigned a disproportionate increase
in this case.
2466
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-13
CUSTOMER
CLASS
Residential
Small General
Large General
Lighting
Large Power
Unmetered
St. Lighting
Traffic
Micron
Simplot
DOE
AMOUNT OF
SUBSIDY PAID
$12 100 000
900,000
900 000
500,000
000 000
260,000
400 000
160,000
800 000
280 000
300 000
$25.6 mil1ion
Source:Idaho Power Company Exhibit No. 61.
As the table indicates, all remaining customer
classes under Idaho Power I s proposal are required to pay
portions of the subsidy to the irrigation class.
2467
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-03-24a
DOES IDAHO POWER OFFER A MEANS TO EVENTUALLY END
THIS SUBSIDY?
, and without annual rate cases, the continuing
annual $25.6 million subsidy could go on indefinitely.
DO YOU HAVE A PROPOSAL TO ELIMINATE THE SUBSIDY TO
THE IRRIGATION CLASS?
Yes.One obvious but abrupt means of eliminating
the subsidy would be to raise irrigation rates in this
rate case by the 67.1% required to bring the irrigators
rates in line with the cost of serving that class.Under
this action , all ratepayer classes could be immediately
aligned with their respective costs of service, and Idaho
Power is made whole with respect to its revenue
requirement.However , the same outcome for all
nonirrigation rate classes , and for Idaho Power can be
accomplished in this case without the abrupt 67.
increase to the irrigation class.
PLEASE EXPLAIN YOUR PROPOSAL TO MOVE ALL
NONIRRIGATION RATE CLASSES TO COST OF SERVICE AND
ELIMINATE THE SUBSIDY ONCE AND FOR ALL?
I propose that the Commission in this case adopt a
three step remedial program with respect to rate design:
Set all nonirrigation rate classes' rates equal
to respective costs of service
Raise the irrigation service class I s rate by18.6% (not 25% as proposed by Idaho Power)
2468
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-13
Have Idaho Power establish a deferred
accounting mechanism to both debit all annual
amounts of unrecovered irrigation subsidy for
years and credit for set incremental increasesto the rates of the irrigation class over the
next 5 years, wi th carrying charges onunrecovered balances.
2469
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-03 -25a
HOW WOULD THIS ACCOUNTING MECHANISM WORK?
Idaho Power establishes a deferred regulatory asset
or similar account.When the new rates resulting from
these proceedings go into effect , there would be a
revenue shortfall monthly, which is accumulated and
deferred into the Subsidy Account.The revenue short fall
is the result of (1) setting all nonirrigation rate
classes I rates in these proceedings equal to their
respective costs of service and,(2) raising irrigation
service rates only part way (recall irrigator rates are
far below cost of service) toward cost of service in this
case.The difference between the irrigation service
rates set in this case and the cost of serving this class
becomes a "stranded subsidy" that , unlike the present , is
not charged to other rate classes.Instead , this
stranded subsidy is placed into the Subsidy Account.
In order for this Subsidy Account to be cleared over a
fixed period of years, the irrigation service rate is
raised gradually but automatically in each of a
predetermined number of years.The balances in the
Subsidy Account increase in early years due to the
revenue shortfall , but decrease to zero in later years
with the automatic increases to rates.
CAN YOU PROVIDE A NUMERICAL ILLUSTRATION OF HOW THIS
MECHANISM WOULD WORK?
2470
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-
Yes.My Exhibit 707 uses the correct data in this
case relevant to the Subsidy Account.The exhibi t uses a
year period in which the subsidy problem is eliminated.
As shown , the present subsidy now being paid by
nonirrigation rate classes , before the 25% increase
proposed by Idaho Power , is $40.5 million per year.
Instead of initially raising irrigation service
rates by 25%, my example assumes a lower first year
increase of 18.6%, but raises irrigator rates by an
additional 18.6% in each of the next 4 years as well.
Just as the initial years I increase leaves irrigation
service
2471
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03 -26a
rates below cost of service and increases the Subsidy
Account balances , rates in years 4 and 5 are above cost
of service to begin paying down these balances.
In terminal year 6 , when the Subsidy Account
balances are zero , the irrigation service rate is reduced
by 28.77%, back down to exactly the irrigation service
class cost of service.The result of the whole process
is to transfer the $40.5 million subsidy that is now on
the backs of all other nonirrigation customers into an
interest bearing account administered by Idaho Power.
the end of year 5 the multi -decade rate subsidy problem
will have been eliminated and all customers I rates,
including those of the irrigators, will have been set
equitably at respective costs of service.
ARE THERE OTHER REASONABLE WAYS IN WHICH TO
IMPLEMENT THE SUBSIDY ACCOUNT MECHANISM?
Yes, although I believe that the method expressed in
Exhibit 707 is reasonable.Exhibit 708 provides an
al ternati ve.There I illustrate the equivalent
accounting, but assume a first year increase of 25% to
irrigators, but allow the rate increases and the balances
to be cleared over a period of 10 years.
This accounting mechanism could be implemented
in any number of ways, but the important consideration is
that nonirrigation rate classes are immediately and
2472
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-
permanently relieved of the burden of the subsidy.
Finally, I should point out that reductions in
Idaho Power I s requested rate increase would decrease the
annual increases to the irrigation class.
UNDER YOUR PROPOSED DEFERRED MECHANISM , WOULD IT BE
IMPORTANT TO PROVIDE MAXIMUM ASSURANCE TO IDAHO POWER AND
2473
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-13 27a
THE INVESTMENT COMMUNITY THAT THE COMPANY BEARS NO RISK
OF UNDER COLLECTING THESE BALANCES?
Absolutely.The purpose of this proposal is not to
shift the burden from ratepayers to shareholders the
purpose is to eliminate the burden altogether.To this
end the Commission should make clear in any order that
adopts this mechanism that any underrecovery of Subsidy
Account balances would not be borne by the Company.And
as this mechanism results in the use of Idaho Power
credi t, a return needs to accompany these balances.
WOULD LOAD GROWTH OR LOAD REDUCTION IN THE
IRRIGATION SERVICE CLASS BE TAKEN INTO ACCOUNT IN THE
DEFERRAL ACCOUNTING MECHANISM?
Yes.My exhibits use a fixed level of kilowatt hour
usage of 1.62 billion kwh in the irrigation service
class.My review of Idaho Power I s forecast indicates
that this is a reasonable assumption.Load growth would
tend to clear the balances earlier.Load reduction would
potentially leave positive balances that would be the
responsibili ty of irrigation customers or all ratepayers,
but not Idaho Power.
PLEASE SUMMARIZE YOUR RECOMMENDATIONS WITH REGARD TO
THE IRRIGATION SUBSIDY.
The merits and benefits of setting rates based upon
cost of service have long been recogni zed in Idaho.
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DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03 -
subsidy of the magnitude that is currently flowing to the
irrigation is simply intolerable.I have proposed what
believe to be the least painful alternative for solving
this problem , and I urge its adoption by the Commission.
DOES THI S CONCLUDE YOUR TESTIMONY?
2475
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-03-28a
Yes.
2476
DIRECT TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-13
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Dennis E. Peseau.My business address is
Suite 250 , 1500 Liberty Street , S., Salem, Oregon
97302.
ARE YOU THE SAME DENNIS PESEAU WHO PREVIOUSLY FILED
DIRECT TESTIMONY IN THIS PROCEEDING?
Yes, I am.
WHAT COST OF SERVICE AND RATE DESIGN ISSUES DOES
YOUR REBUTTAL TESTIMONY ADDRESS?
I will briefly address the cost of service and rate
design issues raised by Idaho Irrigation Pumpers
witness , Anthony Yankel.I address his issues only
briefly because his conclusions and recommendations in
regard to cost of service and rate design are so deviant
from every other party in these proceedings.All other
parties, whether or not they agree precisely with Idaho
Power's cost of service studies, recognize the general
reliability of the Company I s studies, as well as the fact
that , with one exception I discussed in my direct
testimony, they follow prior Commission-approved
methodologies.
Mr. Yankel's testimony, on the other hand , professes
confusion about the Company's study to such a degree that
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REBUTTAL TESTIMONY OF DENNIS E. PESEAU
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he claims he has no other choice but to fall back on his
recommendation to raise each customer class I rates by a
uniform average percentage.
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REBUTTAL TESTIMONY OF DENNIS E. PESEAUIPUC Case No. IPC-E- 03 -13
WHAT IS THE REAL ISSUE HERE?
Mr. Yankel is facing the imposing task of having to
deny what is evident and obvious to everyone - that
irrigation pumpers have been receiving huge and growing
rate subsidies for many years.These subsidies have been
paid by residential , commercial , industrial and special
contract customers.From my reading of other parties
testimony, I conclude that all customer classes want this
subsidy to cease and allow such customers I rates to be
based on the respective costs of serving them.
WHAT SPECIFIC PORTIONS OF MR. YANKEL I S TESTIMONY
YOU ADDRESS?
I address his allegations wherein:
Mr. Yankel claims that Idaho Power I
...
cost-of-service study produces erroneous and
unreliable results...(pg 3, lines 4-5) and
Idaho Power I s study has modeling problems
because "
...
the Companyl s cost-of-service model
is little better that a "Black Box
...
(pg 23,
1 i ne s 13 -14) .
Mr. Yanke 1 implies that a differential growth
rate among customer classes is a legitimate
basis for attributing costs of service.
Mr. Yankel' s suggests that returning to a
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REBUTTAL TESTIMONY OF DENNIS E. PESEAU
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distant policy of allocating demand costs on
the basis of an average 12 -CP is somehow
superior to the more recent but longstanding
policy of using a weighted 12 -CP allocator.
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REBUTTAL TESTIMONY OF DENNIS E. PESEAU
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DID YOU FIND THE COMPANY'S COST OF SERVICE MODEL TO
BE EITHER ERRONEOUS AND UNRELIABLE , OR MYSTERIOUS?
No.As I concluded in my direct testimony "
...
general conclude that Idaho Power'cost service
study consistent with sound costing methods and prior
Commisslon orders...(Peseau lines 10).From my
brief review of other parties testimony, all others but
the irrigation pumpers concluded the same.Furthermore,
I disagree with Mr. Yanke I 1 s assertion that Idaho Power I
cost of service study is an unintelligible "Black Box.
I encountered no difficulties in independently changing
assumptions in the Company's model and re-running it to
test its veracity and reasonableness of the results.
WHAT IS THE ISSUE WITH RESPECT TO MR. YANKEL'
TESTIMONY ON DIFFERENTIAL GROWTH RATES AMONG IDAHO
POWER I S CUSTOMER CLASSES?
On page 21 , lines 4-18 of Mr. Yankel's testimony, he
suggests that irrigation loads are not "
...
fueling the need
for a rate increase...While it may be tempting to
attribute blame for rate increases on relative customer
grow rates, it is not valid to do so.Customers that
place demands on Idaho Power's system disproportionately
in high-cost peak load periods cause higher costs to be
incurred whether or not the particular class is growing.
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Any new capital expenditures made by Idaho Power , in
the course of its cost of service study, are allocated
according to the relative customer demands by season.
Irrigation loads contribute relatively more to coincident
system peak due to their concentration of demand in the
high cost summer season.
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REBUTTAL TESTIMONY OF DENNIS E. PESEAU
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MR. YANKEL PROPOSES ON PAGE 3, LINES 6 - 8 OF HIS
TESTIMONY THAT THE COMMISSION USE AN AVERAGE 12 -
ALLOCATOR BECAUSE AN AVERAGE 12 -CP ALLOCATOR IS USED IN
THE COMPANY'S JURISDICTIONAL STUDY.DOES CONSISTENCY
REQUIRE THIS?
, absolutely not.The average 12 -CP allocator
referenced in the jurisdictional study is often required
by FERC.But even at FERC , after a jurisdictional
separation is made, the actual allocation of transmission
demand costs are required to be made on any number of CP
allocators , including a l-CP,, 3-, 4-CP or other
coincident peak basis.I recently filed testimony before
FERC where a 4 -CP transmission cost allocator is proposed
in spite of a 12 -CP jurisdictional allocator.
Further , I recommend that this Commission remain
wi th the weighted 12 -CP on the basis of merit and not
defer this important issue to FERC.
DO YOU HAVE ANY OTHER NEW OBSERVATIONS ABOUT THE
IRRIGATION SERVICE ISSUES?
I am offering two exhibits that explain how my
proposed deferred regulatory asset or Subsidy Account
would work if the Commission accepted the Staff'
proposed revenue requirement in this case.
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WOULD YOU PLEASE EXPLAIN THE TWO EXHIBITS?
Exhibit 709 summarizes the effects of a 5-year
recovery of this account.Irrigation customers would
experience a 15% increase in the first year and 13.21%
each year thereafter , until reaching parity.Exhibit 710
contains the same calculations with a 10
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REBUTTAL TESTIMONY OF DENNIS E. PESEAU
IPUC Case No. IPC-E-03-13
year deferral.In this alternative, the initial 15%
increase would be followed by annual 6.11% increases.
DOES THI S CONCLUDE YOUR TESTIMONY?
Yes.
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(The following proceedings were had in
open hearing.
MR. WARD:And with that , Dr. Peseau is
available for cross-examination.
COMMISSIONER SMITH:Thank you.
COMMISSIONER SMITH:Mr. Purdy and Mr.
Eddie have waived their right.Mr. Gollomp.
MR. GOLLOMP:No questions.
COMMISSIONER SMITH:Mr. Miller
Mr. Richardson.
MR. RICHARDSON:Just a couple
Madam Chairman.
CROSS - EXAMINATION
BY MR. RI CHARDSON :
Dr. Peseau, on page 13 of your direct
testimony, beginning on line 5 , you state that my exhibit
701 takes Dr. Avera's discounted cash flow method and
simply plugs in an updated figure for dividend yield.
you see that?
What page is that on?m sorry.
I believe that I s page 13 at line
Yes , that's correct.
So you updated the dividend yield , but you
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didn I t adj ust the growth rate and I think that Dr. Avera
was critical of that fact in his testimony, was he not?
Yes , he was.
And if dividend yield goes down , is it
necessarily so that the growth rate increases?
No.In fact, I subsequently did update
the growth rate and the average growth rate went down as
well.There I S not a one-to-one or even an inverse
relationship there at all.It's based on what happens in
the stock market and investor expectations.
Earlier in this proceeding while Dr. Avera
was on the stand , you were not here, but I asked him some
questions about your attorney' s ~ross-examination
exhibit , which is Exhibit No. 713 , which is actually an
update of Dr. Avera's Exhibit No., specifically I asked
about Exhibit 713 I s showing of PNM I s historical growth
rate at 19 percent.Are you familiar with that issue?
Yes , I am.
And I asked whether PNM I S growth rate
might be unrelated to PNM's utility operations and maybe
suggested it might be a result of its unregulated forays
into the wholesale markets during the energy crisis, but
looking at Dr. Avera's testimony, I think he said it was
nonsensical for you to remove this from the historical
approach; is that accurate?
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, in other proceedings we I ve introduced
articles , academic articles , that have demonstrated
empirically that the best estimate of near term growth is
broker expectations and not history.Of course , if I'
going to formulate an opinion about growth prospects of a
company, I I m going to know what happened in the past, but
it's wrong to then weight that with my expectation using
that, so it I S really double counting if you use
historical growth rates twice.
MR. RICHARDSON:Thank you,
Madam Chai rman .Tha ti s a II I have.
COMMISSIONER SMITH:Thank you
Mr. Richardson.
How about the Staff?
MS. NORDSTROM:Yes , thank you.
CROSS - EXAMINATION
BY MS. NORDSTROM:
Good afternoon.On page 5, line 11 , you
state, "The resulting mismatch overstates Idaho Power I
revenue requirement and is not defensible.Have you
evaluated Idaho Power I s rebuttal testimony on this
topic?
Yes.
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COMMISSIONER SMITH:I I m sorry, I didn I
find that.Are you in the direct or the rebuttal?
MS. NORDSTROM:I believe I was in the
direct.
COMMISSIONER SMITH:Okay.
MR. WARD:And I need the reference again
counsel.
MR. STUTZMAN:Page 5, lines 11 and 12.
COMMISSIONER SMITH:All right , thank
you.
BY MS. NORDSTROM:Have you evaluated
Idaho Power's rebuttal testimony on this topic?
Yes , I have.
Do you accept Idaho Power I
characterizations that there are no additional revenues
or expense reductions and therefore , no mismatch
exists?
No, I don't agree with that.
Why not?
Well , to the extent we attempt to adjust
an expense or rate base item and we fail to take into
account the fact that that's added to serve growth or
improve reliability, whatever the issue is , there will
, relatively speaking, there will be an overstatement
of normalized costs and expenses relative to normalized
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revenues.I mean, we're simply adjusting one part of the
equation and not the other.
On page 7 , you discuss Idaho Power'
incentive pay package and recommend that this adjustment
be rej ected.It appears that your rationale is similar
to Staff I s position , except that you believe the
incentive pay program should be self - funding because the
resul tant savings should exceed the incentive pay.
you agree with this characterization of your position?
Yes.
MS. NORDSTROM:Thank you.No further
questions.
COMMISSIONER SMITH:Mr. Budge.
MR. BUDGE:Just a few , if I may.Thank
you.
CROSS-EXAMINATION
BY MR. BUDGE:
Dr. Peseau , did you have an opportunity to
look at the Figure 10 in the irrigators' rebuttal
testimony that graphically depicted the load growth on
the system since the last case?
I did.It's been --
I can give you one if you don I t have one.
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Would you please?
MR. BUDGE:Sure.May I approach?
COMMISSIONER SMITH:Certainly.
(Mr. Budge approached the witness.
BY MR. BUDGE:That Figure 10 appears to
be a two-part exhibit.The top part is depicting the
load growth over the past 10 years by customer class
graphically and the bottom part depicts it on a monthly
basis by customers of percentage , do you see that?
Yes.
And at least in terms of megawatt-hours of
growth , it appears that the growth of Micron's use is
almost as great as the entire Schedule 19 large power
service , would you agree?
Pretty close.
And something in excess of hal f of the
growth of the entire residential class on Schedule
That appears to be pretty close.
Does the Micron contract have
interruptibility provisions?
, I don't believe so.
Do you know whether or not Micron
participants in any demand side management programs at
the current time?
I recall attending a meeting a few years
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back on that subject and I think it was at Micron , but
ve lost track.I wasn't representing Micron, so the
answer is I don I t know.
Has Micron been an advocate in the past of
investment by the Company that improves reliability?
They and others, yes.
And would you agree that that comes at a
cost?
Generally, yes.
If I understand your recommendation with
respect to what I s been characterized as the irrigation
subsidy, you are also , like other witnesses, recommending
a rather systematic move to full cost of service over a
period of five years; is that correct?
, at the end of my direct testimony,
indicate that as an example , I used five years, another
example I used ten years.You know , I think that's a
matter to settle among the parties to do something that'
reasonable.There's nothing magic --
Excuse me, your basic belief is that that
should be the end goal is to get the irrigators in some
period of time to full cost of service?
Yes , and whatever that cost of service is.
If we develop changes, such as time of use rates or
something like that and the cost of service changes , I
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think we need to review that.I didn't do that.
wanted to give an accounting example of how the mechanics
worked and so it looks I ike I'm saying at the end of
five, at the end of ten it has to be done to full cost of
service.Well , cost of service can change over time and
we want to be sensitive and be fair about that, but I
think - - I just think it's time to enact something
systematic and I think this does it and it brings
immediate relief to all the parties who have been
carrying this for the last 25 years.
And once the irrigators arrive at that
evasive goal of full cost of service, do you advocate
that that then be the guiding light that is followed in
setting rates from that point forward?
I think to the extent that the Commission
has in the past.Now , the irrigators have been accepted
for years for one reason or another of not going to full
cost of service , but typically, the rest of the classes
are set generally, typically by the Company very close to
the cost of service and I would recommend that rates be
based upon and I don't ever want to say that there I s
nothing else to consider , that all rates have to exactly
equal, but it's a laudable goal and I think it helps
everyone out.
Dr. Peseau , I believe you were a witness
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on behalf of Potlatch in the Avista or Washington Water
Power case that was concluded in 1999 , Case WWP-E-98-11.
I represented Potlatch in 1999.I'll
accept that docket number.
And I don I t expect you to recall , but I
suppose you did see the Commission Order 28097 that was
issued at the conclusion of that case?
m sure I did.
And on page 27 , the Commission in its
Order states , and I quote as follows:Cost of
service"in fact , let me retract that.This was in
response to some of your testimony on behalf of Potlatch
that characterized cost of service studies as the balance
of art and economic principles, I think was your
testimony, do you still believe that is true of cost of
service studies today, that they should be viewed
somewhat as a balance of art and economic principles?
, I think that's true.Experts can have
real legitimate differences, but I don't think it's a
50-50 balance.I think we've come a long way in the last
25 years about understanding loss of load probabilities
probability of peaks, you know , proper weights to
attribute and allocate costs, but I don't think I've ever
said , nor do I think I can , that we'll get to the final
perfect method any time soon.It just won1 t happen.
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And in that Washington Water Power case
we're discussing, I believe you did advocate a lCP
methodology for cost allocation; is that correct?
It's been too long ago, too many rate
cases since.That would depend upon the Avista system
and the loss of load probability that would occur, but it
wouldn I t surprise me.
The Commission discusses on page 26 of
that Order addressing Potlatch I s proposed use of the
single peak allocator lCP as opposed to a monthly
allocator 12CP.That would seem to indicate that that
was what Potlatch was advocating and I was assuming you
were probably the advocating witness.
Yeah , the reason I'm struggling is that a
weighted 12CP can be essentially a 1 or 2 or 3CP just
depending on the weights and I don't know in the context
in which I was speaking.I may have been observing that
the bulk of the probability of more capacity being needed
was in a single summer or winter month and that would
have shown either by that recommendation or by an actual
weighting of the 12CPs.I just don't know.
I understand, and I don I t have your exact
testimony, so I don I t mean to mischaracterize.
certainly making some inferences from what I thought was
the case in the Order, but in any event , with respect to
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what you just testified to , a weighted 12CP can be
something different, would that be in the case if the
allocators were zero in several months as is proposed by
the Company in this case?
That's correct.
So in essence , as to the half the Company
proposes to allocate based on the weighted 12CP months
since they have only five months weighted in essence
becomes a 5CP?
That 1 S correct, although it's correct to
use a weighted coincident peak allocator; whereas, the
outcome, as you I ve mentioned , will be to attribute a lot
of the cost allocation to one or more months, but that'
an empirical thing that you check each and every time
because systems do change and a 5CP in one period a few
years later might be a 4CP or something similar.
In response to the various arguments in
that Potlatch case, Washington Water Case, regarding
which methodology was appropriate, the Commission settled
the issue by stating on page 27
, "
Cost of service
however , is only one of many factors to be considered by
this Commission in tariff design.There is no required
correlation. Are you advocating that that particular
policy is fated to be changed here in going forward?
No.The only qualification is the
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Commission needs to consider what it needs to consider to
make a good decision but would hope that the point
departure would good cost service study and then
we have ba s i s from which to make changes that would not
be arbitrary but perhaps necessary.
I had one other line of questions maybe
just to clarify in my own mind what you did.I f you
could turn to your Exhibit 706, I just want to understand
how you did that.If I understand it correctly, you in
fact - - excuse me, are you there yet?I apologize.
I am.
Is Exhibit 706 the results of your cost of
service study based on utilizing only the weighted 12CP
method the Company proposed and eliminating the 12CP and
the averaging?
That's correct, with the 12 allocators
that were a blend by Ms. Brilz were replaced with the
purely weighted coincident peak used in the last case.
And this was a run that you actually did
based on that weighted 12CP utilizing the Company'
computer program?
Yes, absent , I should qualify that, absent
completely redoing the jurisdictional part of it, but
essentially yes.
I was trying to understand , you made a
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statement on page 23, line 10 to 15 of your testimony,
that you basically stated that under your method , which I
was assuming you re referring to your cost of service
run, Exhibit 706 , that everyone is better off except for
the irrigators.
Yes , I recall saying that.
And so under your study, the rate of
return that would have been shown , as you did on line
217 , should be something higher for each of those
customer classes than would be depicted on the Company'
cost of service run which was their Exhibit 39; is that
correct?By better off , their cost of service would go
down and their rate of return would go up?
I'd have to see it, but go ahead and I'll
see if I can respond.
Gi ve you a chance to change your
testimony?
Yeah, I'll run for cover.
Well , and just to speed this exercise
along, rather than have you pull the Company's Exhibit 39
up, which I have in front of me, I'll just review it and
let you accept the numbers, if you would, subj ect
check, so when I look in your Exhibi t 706 down to the
line 217 , rate of return
What page is that?
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This is your Exhibit 706, page 1.
Okay.m there.
Okay; so if we looked at the rate of
return line , which is 217 , and moved over to the
residential class under column B , you show a rate of
return of 6.132; correct?
Yes.
And if you'd accept, subj ect to check, if
I do the same under the Company's Exhibit 39, they show
as would be expected , a lower rate of return of 5.616,
and if we move over to general service, column C, you
show a rate of return of 5.162 percent , do you see
that?
Yes.
And the Company showed a somewhat lower
rate , 5.008 as one would expect; correct?
Yes.
Now , I ask you to go , if you would
please , to column F , area lighting, and your run of the
Company s cost of service study shows a rate of return of
70.414 , do you see that?
That's correct.
And when I go to the Company's run, it
also shows a lessor rate of return of 69.734 percent.
Now , the question I have for you is why there would be a
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change to the rate of return for area lighting when in
fact no generation or transmission demand is allocated to
that particular area lighting class under the Company'
method?
I can only guess that it's an overhead or
a general plant allocation that does that.I don't know
and Ms. Brilz in her rebuttal of me points out that she
does agree with my statement that all other classes, but
sitting here without the workpapers, I couldn't tell you
whether it was
Well , let me ask it this way:I think we
established with the Company that there was zero
generation and transmission allocated to area lighting
under their cost of service study methodology, both the
weighted and the unweighted.
Okay.
And if there was zero allocated under your
study and you continued to have a zero allocator on your
half , the weighted 12CP , wouldn't one have expected there
to be no change in the rate of return on area lighting?
If all components of costs are allocated
independently, one would expect that, but as long as
there are j oint and common costs that have to be
allocated in a non
- -
in a fashion that's not directly
attributed to generation or transmission
or energy, for
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example, then there will be other costs, but again , I'd
have to have more to verify it.
But if the allocators are zero, zero times
zero under either methodology should not reflect any
change in the rate of return of area lighting unless
there's some flaw in the computer itself.
, you allocate generation demand costs
on kilowatts and you allocate other costs on the basis of
kilowatt-hours and those would not be , if I understand
your logic , those would not be directly allocated to here
because they aren't, but there are other costs that are
allocated on the basis of labor , of labor and wages, and
numerous other factors that would be attributed
independently of generation and transmission.
So despite the zero allocators under
either run , we could get a different result?
Well , the zero allocators are for a
different bucket dollars.They are common
- -
you
know the office building for Idaho Power has to be
collected and it'not collected on the basis kilowatt
consumption or kilowatt-hour consumption.It's on the
basis of labor or some other factor and those do get
allocated to all classes.
MR. BUDGE:Thank you, Dr. Peseau.I ha ve
no further questions.
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COMMISSIONER SMITH:Thank you.
Questions from the Company.
MR. KLINE:I do have some questions.
Thank you, Madam Chairman.
CROSS-EXAMINATION
BY MR. KLINE:
Just to make sure I understand on the
changes that you made to your testimony on the stand
Dr. Peseau , on pages 4 and 5, is it my understanding you
made those changes in direct response to the rebuttal
testimony of Mr. Obenchain , Company witness Obenchain?
thought I heard that was why it was being done.
Well , I guess Mr. Ward asked some
quest ions that
- -
don'know how to characteri ze my
counsel
- -
that indicated that maybe he was under the
lmpression that the Company had done this with all plant
additions and that's not the case.If you look at my
numbers , they're taken from Exhibits, what , 16, 17 and
18, I think, which are clearly labeled maj or plant
additions , so it's not all the investment.
Okay, and that's the reason for the
adj ustment?
Yes.
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Would you agree with me that Micron is a
company that demands and expects a high degree of service
and reliability just as a result of the nature of what
they produce out there?
I believe that I s correct.
They're certainly not an interruptible
customer; correct?
Right.
On page 2 of your testimony, lines, I'
specifically looking at lines , 17 and 18 , you talk about
the purpose of your direct testimony and you indicate
that Micron asked you to review the Company's application
and make such recommendations as I believe appropriate.
Did you discuss the recommendations in your testimony
wi th any Micron executives or Micron personnel?
Yes.Early on typically for a client
we'll make a quick review and perhaps write a memorandum
of potential issues and discuss it and we did that.
Okay, did they express any reservations as
to the effect of your recommendations on the
irrigators?
m sure we spent quite a bit of time
it's a tough one and we went over the history and our
recommendation was that we stick with the cost of service
standard and given the long time span since the last rate
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case that things were just not going to get better unless
there was a systematic means, but it's a difficult issue
of course, any prolonged subsidy is , but it was
discussed.
And in this case you are recommending that
the Company not be given the annualizing adjustments that
it has requested or that it not be permitted to make the
known and measurable changes that it has requested with
respect to these large investments that have been made;
am I accurately characterizing your testimony?
I think that's close, Mr. Kline.I simply
think that there's a bit too much of a mismatch.
sympathetic to rigidity of test years and the fact that
something significant can happen and it can either be
done as you I ve proposed or it could be done by coming in
sooner for a rate case and I understand that's not a lot
of fun , but the adj ustments I make or I propose, either
of two, that is, to take those out and center those
expenses with the revenues of the test year or bring the
revenues forward as I I ve done.
The specific items that make up the
annualizing adjustments and the known and measurable
changes , certainly we believe, Idaho Power believes, that
they are being performed in order to increase the
reliabili ty of the system and I think we I ve already
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established that Micron is a customer that really depends
an awful lot on system reliability, did you discuss your
recommendations with respect to those kinds of
reliability investments with Micron as well?
Not in the sense I think your question
goes to.We're not proposing that the Company not be
able to earn on a prudent investment and I have no reason
to believe that these aren't prudent expenditures.It'
just a matter of how far do you go out anticipating
outside of a test year on one side of the equation and
ignore the robust growth in revenues and customers that
you're experiencing, so it I S not a matter of discouraging
the Company.Neither my client or I would propose that
you start cutting corners on reliability at all.Tha ti
important to all customers and especially Micron , but it
doesn't go to the reliability issue.It just goes to the
matching or attempted matching of revenues and
expenses.
All right.I'd like to spend a few
minutes talking now about your proposal to set up a
deferral and regulatory asset to address the, you call it
the, irrigation subsidy, so I III use that term, that I s
his term , that I s not mine.Do you believe that a
regulatory commission can make a determination in a
general revenue requirement proceeding that a utility is
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entitled to additional revenue and then not fund that
revenue , but then simply defer the revenue for collection
at a later date?
Sure.
So in other words , let I s suppose Idaho
Power comes in sometime in the future to seek revenue
requirement associated with its Bennett Mountain plant
, 60 million bucks , do you believe the Commission could
order Idaho Power to say this is the revenue requirement
that we have determined should be associated with the
Bennett Mountain plant and we're going to order that
that's what you should earn , that's what you should
recei ve
Okay.
But we I re not going to give it to you
we're going to defer it and we're going to give it to you
over 10 years or whatever in the future , do you think
that is permissible or logical?
I don't know if it would be or not.It'
not my proposal and it's not what the Commission would
do.In terms of when you bring a plant , let's call it
generating plant , into commercial operation and it I s
entered into rate base and that plant costs you $100
million , the Commission can say that was a good
investment , but it doesn't say you collect the $100
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million.
I understand.
It's amortized, you know , your fixed
charge rates over the life of that asset.Another
example would be the decision made in 2002 by the Nevada
Public Utilities Commission that granted Nevada Power
$450 million in expenses during the crisis and said
you I re granted $450 million, but you'll recover
approximately $150 million per year for the next three
years and that went into a regulatory asset account and
earned a fair rate of return.
Don't you think there's a difference
between deferring expenses and deferring revenues?
I heard your question regarding revenue
before and I guess I don I t understand it.Any allowance
by the Commission that allows you to recover is an asset
and we can call it revenues or we can call it a plant and
if you're allowed to recoup that cost and earn a return
on it over a specified period , then you're not damaged.
I intentionally made the proposal what
thought would be neutral in the sense that it would cost
you nothing, but attractive in some sense in that it
would be an asset that you would be made whole on just as
you would any other plant and I think I said in my
testimony, I wasn't trying to transfer the subsidy now
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paid by customers to shareholders.I think that would be
unfair.I think shareholders should be as indifferent to
that asset as they would be to a physical plant asset.
Obviously, there's a difference between
revenues, non-cash revenues which would be associated
with a deferred revenue stream, and cash revenues
associated with a revenue requirement that's determined
by the Commission.
m not so sure there is a difference.
may, as you well may, like $1.00 today rather than a
$1.10 next year , I mean , that's a time preference of
money that we may have , but as long as I was given what
think is a fair return on that, I don't see any
difference.Regulatory assets are established for many
things and I think as long as the principle is adhered to
that the Company is not damaged and in fact , earns as
well on that asset as it does any other asset it chooses
to invest in.It's fair to shareholders.
Okay, on page 27 of your testimony, I'
looking specifically at line 6, you talk about putting
the - - an interest bearing account to be administered by
Idaho Power, do you see that?I think you're talking
about the deferral amount; correct?
Yes.
And then over on the next page, on page
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, line 7 , you talk about a return needs to accompany
these balances.Do you distinguish between interest and
return here or is that just semantics?And the follow-
question is what is the return you're recommending?
Okay, what I had in mind is the fact that
there are two different streams of revenue associated
wi th my proposal.One is the return to Idaho Power of
funding, going out and covering the shortfall , because my
proposal says that non-irrigation customers don't have to
overpay or pay more than their cost of service anymore,
they pay their cost of service, and irrigators aren'
brought to their full cost of service for some period of
time , five to ten years, but that irrigation rates are
raised systematically annually, so we've got an outflow
of capital , at least in the first few years, by Idaho
Power to raise enough to cover, in a sense , to make
itself whole.It needs a full rate of return on that.
The interest reference really went to in
year one and thereafter , irrigators I rates would be
raised over the rate decided in this case.That
additional revenue I was assuming would -- you know , the
Company would do something wi th it smart to try to earn
and that's all I meant by that.
Okay.Again , I think you may have
answered this, but I want to be really, really sure
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page 26,line says " Idaho Power establishes
deferred regulatory asset or similar account.
isn'regulatory asset,doesn'do us much good.
mean , is it just again semantics or are you really
meaning it's a deferred regulatory asset?
I do mean it should be a deferred
regulatory asset, but I didn't know frankly, if that was
the smartest way and had you had a different take on
that, I was just covering myself with similar account.
I guess I'd also like to ask a few
questions about the mechanics of this deferral account.
How would you propose that we compute the monthly amount
of the revenue shortfall that's going to go into this
account?
That would be the difference between the
cost of service rate by irrigators and the rate , the
lower rate, set in this case.
Okay, and so the lower rate set wouldn'
be a filed rate or it wouldn't be a cost of service rate,
it would be one that would be computed and then
mul tiplied by the monthly irrigation usage; is that how
you would do it?
That is how the example was done.
And then in computing that, would you
assume a static irrigation load throughout?
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Wilder , Idaho
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The example I use assumes that because
there's not a lot of load growth there , but that'
strictly for convenience.It would be based upon actual
consumption, so if loads grow , things get paid down more
quickly.If load shrinks , then there I s a shortfall that
under my proposal has to be made up by all customers or
irrigation or someone other than the Company.
So you could be -- well , I'
anticipating - - strike that.Now , would it be your
intention that if the , if there was an intervening
general revenue requirement case , let I s say the
Commission adopted your 10-year proposal and periodically
the Company came in for general revenue requirement
cases , would that cause a change in what's in the
deferral account or would it change the assumptions
you're making in the deferral account or how would you
expect that would work?
The subsequent - - it wouldn't change the
account balances , but it would change the going forward
rate of accumulation of paydown because at the end of a
general case , the cost of service study would change and
the rates coming out of that would change and there would
be a need to adj ust the systematic increase to the
irrigation class.
And, of course , one of the concerns you'd
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Wilder, Idaho
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have to have about a deferral accounting like this is
what happens if , as Mr. Budge client's testimony has
indicated , that this would drive irrigators out of
business , would it be your intention that as - - let's say
that did occur and the irrigation customers paying this
increased irrigation rate were to drop, would they keep
picking up the additional slack or would that then be
somehow allocated to the other customers?
I didn't address
- -
other than refer to
the fact it had to be looked at , I didn I t make a
proposal.I think it's fair to
- -
I think other
customers rather than having to pay the entire subsidy as
they are or have been , it may be fair to spread some of
that burden of a shrinking class amongst all, but I think
that's something that a subsequent session could get to,
but again , it's a potential for a problem.You know , if
you believe in demand elasticity at all , loads could
shrink and the Company can't be left holding the bag by a
bad assumption at the start that loads aren I t going to
shrink.If they do , it needs to be accommodated.
MR. KLINE:One second.
(Pause in proceedings.
BY MR. KLINE:One last question,
Dr. Peseau.Doesn't the investment community view
non-cash assets or non-cash - - yeah , non-cash assets
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deferred assets differently than actual receipt of cash
by the utility to pay its bills , those kinds of things?
That I S probably true, but I don't believe
that that accurately describes what we're doing here.
This is an assurance to the investment community that
you're going to collect monies that you've raised , plus a
return.I haven't absorbed that thought of yours.
regulatory asset and I would encourage the Commission if
they were to go for something to make it very, very clear
that it's no different than any other prudent investment
and that the return would be authorized and allowed.
MR. KLINE:That 1 S all I have.
COMMISSIONER SMITH:Commissioner
Kj ellander.
EXAMINATION
BY COMMI S S IONER KJELLANDER:
Dr. Peseau , just a point of clarification.
There was a discussion about Micron and its concerns
about reliability.As a point of clarification , isn'
Micron's issue related to reliability really more of a
fine subset of reliability and doesn't it really deal
with power quality?Don I t they have very, very different
issues , especially in terms of expense and who should
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pay?
Yes, they demand and pay for and
contribute a different - - to different types of
investment because they require - - they either pay Idaho
Power to install it or they have it installed themselves.
That's different than saying something that all customers
want an adequate generation supply with an adequate
reserve margin so that the lights don't go out.I mean
that's a different level.The consequences of lights
going out temporarily may not be as great to the average
customer as the lights going out at Micron , but yeah
they have a much higher sensitivity to reliability than
most.
COMMISSIONER KJELLANDER:Okay, thank
you.
EXAMINATION
BY COMMI S S lONER SMI TH :
And I guess I just wanted to get your
thoughts about there's been some discussion or inference
in the questions that have been asked that the spot we
find ourselves in now where the irrigation class seems to
be out of adj ustment a lot further than any other class
was because of past Commission decisions, and it occurred
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to me and I think that Dr. Power testified this morning,
part of the problem was we've only looked at it every
years because that's when there's been a rate case , so
should the Commission be asking the Company to do cost of
service studies on a periodic basis with or without a
rate case just to kind of take the temperature along the
way to see how we're doing given that customers' usage
shifts wi thin classes or between classes and investment
comes on and maybe we should take a little more active
part in having periodic reviews of cost of service even
if the Company doesn't need a rate increase?
That was my first inclination in
developing the testimony and under any systematic means
of reducing the subsidy, whether it's mine or some of the
others , it is important.The best example is with a PCA
which you have here and in some jurisdictions, they have
a PCA every year which is spread on a kilowatt-hour basis
even though energy costs are not 100 percent energy
related and then moves in a general rate case to move
people towards cost of service , but you only do that
every five years, then there's an opportunity if energy
costs have been going up, power costs have been going up
that they're allocated on an energy basis.
In Nevada the commission said , wait a
minute , we took a big step last time , five years ago , and
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now you're saying we're further off , everyone was saying
that , and it was because energy costs were allocated on a
different basis in the interim, so it is necessary,
think, under any means to make sure that things don'
change one way or the other, just as a matter of
fairness.
Well , what's the proper interval?
Because costs were changing so rapidly in
Nevada , cost of service was done for awhile as part of
the deferred case annually, so it was already set.Yeah
that's tough.I would say in a system like this that'
not changing dramatically in terms of mixes , you know
maybe three years, two or three years.
COMMI S S lONER SMI TH :Thank you.
Do you have redirect, Mr. Ward?
REDIRECT EXAMINATION
BY MR. WARD:
Just to follow up on that thought, Doctor,
if you know , are there jurisdictions that basically
review revenue requirement as well as cost of service by
rule every so often?
Nevada after the move to competition sort
of imploded in 2000 , 2001 went to an every other year
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general rate case.
You were asked a question about
disallowing known and measurable changes.You did not
propose disallowance of all of the known and measurable
changes Idaho Power proposed , did you?Specifically, did
you agree that the new depreciation rates of some
6 million, that amounted to some $6 million , in increase
should be approved and accepted?
Yes.
MR. WARD:That's all I have.
COMMISSIONER SMITH:Thank you , Mr. Ward.
COMMISSIONER SMITH:And thank you
Dr. Peseau.
THE WITNESS:Thank you.
COMMISSIONER SMITH:I assume you would
like to have him excused.
MR. WARD:Please.
COMMISSIONER SMITH:If there is no
objection , he will be excused.
(The witness left the stand.
COMMISSIONER SMITH:I think we're ready
for Mr. Budge.
There's been a request for a brief break
so we'll come back in nine minutes.
(Recess. )
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