20081110Micron to IPC 1-4.pdf

GIVE SLEY LLP
lAW OFFICES
601 W. Bannock Street
PO Box 2720, Boise, Idaho 83701
TELEPHONE: [phone]
FACSIMilE: 208 388-1300
WEBSITE: ww.givenspursley.com
Gary G. Allen
Peter G. Barton
Christopher J. Beeson
Clint R. Bolinder
Erik J. Bolinder
Jeremy C. Chou
Willam C. Cole
Michael C. Creamer
Amber N. Dina
Elizabeth M. Donick
Kristin Bjorkman Dunn
Thomas E. Dvorak
Jeffrey C. Fereday
Justin C. Fredin
Martin C. Hendrickson
November 10,2008
Via Hand Delivery
Jean Jewell
Idaho Public Utilties Commission
472 W. Washington
P.O. Box 83720
Boise, ID 83720-0074
Steven J. Hippler
Debora K. Kristensen
Anne C. Kunkel
Jeremy G. ladle
Michaei P. lawrence
Franklin G. lee
David R. Lombardi
John M. Marshall
Kenneth R. McClure
Kelly Greene McConnell
Cynthia A. Melilo
Christopher H. Meyer
L. Edward Miler
Patrick J. Miller
Judson B. Montgomery
Deborah E. Nelson
Kelsey J. Nunez
W. Hugh O'Riordan, lL.M.
Angela M. Reed
Justin A. Steiner
Scott A. Tschirgi, lL.M.
J. Will Varin
Conley E. Ward
Robert B. White
RETIRED
Kenneth L. Pursley
James A. McClure
Raymond D. Givens (1917-2008)
~æ:5..;0rn('m-..m
i::;
o..::(;.'.ç'U1
In the Matter of the Application of Idaho Power Company
Authority to Increase its Rates and Charges for Electric Service
Case No.: IPC-E-08-10
4489-34
Re:
Our File:
Dear Jean:
Enclosed for filing are an original and four (4) copies of Micron Technology,
Inc. 's Responses to Idaho Power Company's First Production Requests, together with
four (4) CDs, which contain the requested documents in response to Production Request
Nos. 3 and 4, in connection with the above-captioned matter.
If you have any questions, please call me.
Si'(reiy, lV~~
clm~
CEW/tma
cc: Service List (w/enclosures)
S:\clients\4489\34\CEW to J Jewell re Response to ¡PC 1st RFP.DOC
..,. iur:r'"nE' I'.... '.' ,-.1f\ V.... ,..,~
ZDOB NOV' 0 PM 3: 46
Conley E. Ward (ISB No. 1683)
GIVENS PURSLEY LLP
601 W. Banock Street
P. O. Box 2720
Boise, ID 83701-2720
Telephone No. [phone]
Fax No. [phone]
cew~givenspursiey.com
IDAHO Pqt?,q¡~~IO¡"~
UT\L\TIES COhl¡rl,.:'i",¡ ','
Attorneys for Micron Technology, Inc.
S:\CLlENTS\4489\34\Micron Rasp to IPC 1st RFP.DOC
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
Case No. IPC-E-08-10
MICRON TECHNOLOGY, INC.'S
RESPONSE TO IDAHO POWER
COMPANY'S FIRST PRODUCTION
REQUEST
COMES NOW Micron Technology, Inc., by and through its attorneys of record, Givens
Pursley LLP, and hereby responds to Idaho Power Company's First Production Request to
Micron Technology, Inc. as follows:
REQUEST NO.1: Please provide copies of testimony and exhibits or comments Dr.
Peseau has prepared and/or presented in utility revenue requirement cases during the past three
years. Testimony and comments presented in cases in which Idaho Power was a par do not
need to be provided.
RESPONSE TO REQUEST NO.1: Copies are attached hereto.
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 1
REQUEST NO.2: Please identify by jurisdiction, case number, and date all utilty
revenue requirement cases in which Dr. Peseau has paricipated, prepared, and/or presented
testimony, exhibits, or comments for the past four years.
RESPONSE TO REQUEST NO.2: Please see the response to Request NO.1. The
jurisdiction and case number are indicated on each filing. Micron does not understad what is
meant by the word "date." Date of case/testimony filing? Date of decision?
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 2
REQUEST NO.3: Please provide copies of all electronic fies, with formulas intact,
that were used or relied on to develop the analyses and/or schedules supporting Dr. Peseau's
testimony.
RESPONSE TO REQUEST NO.3: The requested documents are included in the
attached CD.
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 3
REQUEST NO.4: Please provide copies of all workpapers and supporting documents
Dr. Peseau relied on to support his testimony, exhibits, and any analysis contained therein.
RESPONSE TO REQUEST NO.4: The requested documents are included in the
attached CD.
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 4
DATED this 10th day of November, 2008.
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 5
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 10th day of November, 2008, I caused to be served a
tre and correct copy of the foregoing by the method indicated below, and addressed to the
following:
Jean Jewell
Idaho Public Utilities Commission
472 W. Washington Street
P.O. Box 83720
Boise, ID 83720-0074
U.S. Mail
X Hand Delivered
Overnight Mail
Facsimile
E-Mail
Barton L. Kline
Monica B. Moen
Idaho Power Company
P.O. Box 70
Boise, ID 83707
email: bkline(ßidahopower.com
U.S. Mail
X Hand Delivered
Overnight Mail
Facsimile
E-Mail
John R. Gale
Vice President Regulatory Affairs
Idaho Power Company
P.O. Box 70
Boise, ID 83707
email: rgale(ßidahopower.com
U.S. Mail
X Hand Delivered
Overnight Mail
Facsimile
E-Mail
Peter J. Richardson
Richardson & O'Lear
515 N. 27th Street
Boise, ID 83702
email: peter(ßrichardsonandolear.com
X U.S. Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
Eric L. Olsen
Racine, Olson, Nye, Budge & Bailey
Chartered
P.O. Box 1391
201 E. Center
Pocatello, Idaho 83204-1391
email: rcb(ßracinelaw.net
elo(ßracinelaw.net
X U.S. Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
Anthony Yankel
29814 Lake Road
Bay Vilage, Ohio 44140
email: yankel(ßattbi.com
X U.S. Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 6
Dr. Don Reading X U.S. Mail
6070 Hil Road Hand Delivered
Boise, Idaho 83703 Overnight Mail
email: dreadingtßmindspring.com Facsimile
E-Mail
Lot H. Cooke X U.S. Mail
United States DOE Hand Delivered
1000 Independence Ave. SW Overnight Mail
Washington, DC 20585 Facsimile
E-Mail
Weldon Stutzman U.S. Mail
Neil Price X Hand Delivered
Idaho Public Utilties Commission Overnight Mail
P.O. Box 83720 Facsimile
Boise, Idaho 83720-0074 E-Mail
Michael Kurtz X U.S. Mail
Boehm, Kurtz & Lowr Hand Delivered
36 E. Seventh Street, Suite 1510 Overnight Mail
Cincinnati, OH 45202 Facsimile
E-Mail
The Kroger Co.X U.S. Mail
Att: Corporate Energy Manager (G09)Hand Delivered
1014 Vine Street Overnight Mail
Cincinnati, Ohio 45202 Facsimile
E-Mail
Dwight D. Etheridge X U.S. Mail
Exeter Associates Hand Delivered
5565 Sterrett Place, Suite 310 Overnight Mail
Columbia, MD 21044 Facsimile
E-Mail
Dennis Peseau U.S. Mail
Utility Resources, Inc.Hand Delivered
1500 Libert Street, Suite 250 X Overnight Mail
Salem, OR 97302 Facsimile
X E-Mail
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 7
#
Brad M. Purdy
Attorney at Law
2019 North 17th Street
Boise, Idaho 83702
x U.S. Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
Ken Miler
Snake River Allance
P.O. Box 1731
Boise, Idaho 83701
x U.S. Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
Kevin Higgins
Energy Strategies, LLC
Parkside Towers
215 South State Street, Suite 200
Salt Lake City, Utah 84111
email: khiggins(ßenergystrat.com
x U.S. Mail
Hand Delivered
Overnight Mail
Facsimile
E-Mail
MICRON TECHNOLOGY, INC.'S RESPONSE TO IDAHO POWER COMPANY'S FIRST
PRODUCTION REQUEST - IPC-E-08-10 - PAGE 8
r--.._.......'
HALE LANE
jITTORHIlYS AT LAW
171 f.asl Wnii..nSi- I Soil. 200 ICa,;ll City,lioVlil KIJ01
Telephone (71i)684bDllt '1'..,..ile 11'5)68'.6l1
ww.ll1ldaii.cò.n
. March 19,2007 . :.~
~ ,": ~~
:;.:
~-t:.
Crystal Jackson
Commission Secrary
1150 E. Willam Strt
Carson City, NV 89701
..
:~~ .-..-........ ~:.:
.:.E::;~:..~~.~..."'1._...' ~',~.. '.
i.r.,~t.~):'.:.~_..-"::..
RE: DOCKET NO. 06.11022
r..)c;
. .~
...."(::.,,;." .
Dear Ms. Jacksn
)
Please accept for filing the enclosed original and nine copies of the Direct Testimony of
Deiuis E. Peseau in Phase iv on behalf of Southern Nevada Water Authority in the abovc-
referenced docket.
Should you have any questions regarding this fiing, please contac1 me at [phone].
Sincerely,lA~f!
Fred Schmidl, Esq.
FJS:taw
Enclosures
C:c: Parties of Recrd
HALE LANK PEEK DHNNlsoN...NO IIOWARD
REO oi1'1CE: 5441 Kie. 1.liclSeit flLlo, I RClQ. Ne..,il .9SI111'h_ I11Sj.J7.311O I F..~iRi~. (;75)786.(1711
LAS V¡¡UAS OI'ICi:, 1931Hl.,ar Huah~l',.ay ¡ Fiiunbl'lor II. Ve¡:. ioev agl6~ i i'line 11(2)222-15DD 11'.~i1. (7UJ.)J65-(i/40
:'OJJMAIlCOOIJILRNODOCS\612368\1
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27 Q. WHAT IS THE PURPOSE OF YOUR TESllMONY?
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Docket No. Oø.11022 -.
('.'":'C:~ ,_'1_ r .0.- .;:;
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Diret Testimony of
. Dennis E. Peseau
.r
on behalf of '=4\")o ".\
:;,. .~.. f:'l
Southern Nevada Wate Autority
PLEASE STATE YOUR NAME AND BUSINESS ADDRES.
My name Is Oennrs E. Peseau. My buiness address is 1500 libert Strt S.E.,
, Suite 250, Salem, Oren 97302.
BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
I am President of Utilit Resrces, Inc. The finn consult on a number of econom,
financial. and engineering mattrs for various private and public entites.
ON WHOSE BEHALF. ARE YOU TESnFYNG IN THIS PROCEEDING?
I am testng on behalf of the Soutrn Nevada Water Authri ("SNWAIO) and'it
constitue members.
DOES AnACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND AND
EXPERIENCE?
Yes.
::ODMV'lR\S120821 Page 1
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My testmony in this Phase IV cost of servce and rate desgn porton of Docket No.
, 06-11022 focuses on tw narw cost of servce and rate design issues. Nevada
Power in its certcation and originally-flied cost of servce study has made a
signifnt and Inconsistent change in the manner in whiCh it allocates cost to the
water pumping classes. cOrTpared with the tw prir general rate cases Docket Nos.
01-10001 and 03.10001.
The purpse of my teimony Is to show that the chango made to the cost
allocation is only to the water pumping classes, Is discminatory, unreasonable and
unjust. Correting this change or errr will have an insignifcant effect on all other rate
classes, although the corrction wil measurably affect water pumping clsses.
Correcting Nevada Powes errr will also ensure that the saine consistent oost
alloesrs are us for all rate classs.
Du to the fact that Nevada Por carr its cost of se reults from Its
bundled rate design to distrbution-only or DOS rates, I also propose a small coction
to related DOS rates to time differentiate dean charges.
WHAT RECOMMENDATION DO YOU MAK WITH REPECT TO THE lW COST
OF SERVICE AND RATE DESIGN ISSUES YOU DESCRIBE ABOVE?
In order to eliminate the clearly discriinatory raes prouced by Nevada Power's cost
of service changes only to waer pumping clss, I recommend that 1h Commisn
order the Company to corrct the co allotin to water pumping clsses to:
For the Traditional Bundled Witer Pumping (WP) Rate Schedules:
1. Allocte the cos of distrbuton demand nonrevenue
feeders on the bass of probabilty of peak ("POP") for water
pumping clases, Just as Is done for every other rate class and as
the Commission previously adopte in Docket No. 01..1001;
::OD'iCDOCOD0CS201 Page2 .
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2. Alternatively, the Company should ~cale th
nonrevenue fee, costa on the same basis as it recommended and
the Commision adopted In Docket No. 03-10001, that is, on time
d1rent~ated kws, or the coincident peak demands (probility of
peak) of otherwise applicable class ("OAC").
For Dfstrbutlon OniY Serv lDOS) ClasMs:
3. The DOS rate design should be Imprved to include a
timediffrentiated kW demand chare consistent wit its
ealculaon of time difrentiated nonrevenue feder demand costs
for other demand metred rate schedules.
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12 ÐlSTRIBUTION DEMAND COSTS
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14 Q. WHAT IS THE ISSUE YOU RASE REGARDING THE MANNER IN WHICH NEVADA
POWER PROPOSES' TO ALLOCATE DISTBUTION DEMAND COSTS?
Nevada Power has devlated frm the method for allocatng distributn demand cost
to all waer pumping classes ordered in boh Docket Nos. 01-10001 and 03-19001.
explaIn the technicl aspect of this change below.
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WHAT ARE 'i DISTRBUTION DEMAD COSTS?"
In Nevda Powets Certificaon filing, it provides its revised cost of servce study
(exhibIt-Walsh CertiftIon-2). As has been cutomary. lh cost stdy establishes all
require renues as a functn of disbuon, trnsission and generatin befre
clasIfyg into demand, enrgy and custmer cost funcions.
For reference, the disbuion demand cost category i am concmed wih and
address is th residual distributon cateory of "norevenue feederi. t:age 8 of 55, line
.45, of Exlbit-WaJsh Certlflcaion-2 calculates the marlnaldemand revenues for this
disbutn demand to be $188.8 mUtion.
:;OMA\POOLRNDO1201 Page 3
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As show on page 8 of this exibit, this $188.8 milion fs allocted to On, Mid,
Of and Other demand periods becaus they are caused by probailit of disributin
coincient peak demands by time of use. Depite its cousion In this reard,
Nevada Power makes an unexplained excption here for all WP rate schedules by
allocting these distrbuton demand cost only to WP scheules on a new and
inconsistent basis. This new and unjusted change is not only Inconsiste with
coincint peak aDocation, but is incoistent with the decisions made by the
Commission in both Docket Nos. 01-10001 and 03-1001.
WHAT IS THE EFFECT OF THlS CHAGE PROPOSED BY NEVADA POWER?
This single chane reults in rate propose for the water pumping classes that are
disriminatry, in that only thse classes are allocaed cost in this manner. All other
classes have alloC8tors based on preusly approve cost of servce principles
applied consistently and equally acrss all classe except for water pumpers. The
resulting rates to waer pumpin clsses propos by th Company are unjust and
unreasonable because. as I calculate below, the arbitary chnge propose here
resul in a five-fold Increase In cost allocated to water pumping rate classes. And.
while corrcting this cost aUocation to the water pumpin schedules has no sinifcant
Impa on all other rae schules, Nevada Pos change neverthess relt in
overall water pumping rates being almost 100.l higher than they would be under prior
Commission-ppve co allocatins.
WHAT IS THE HISORY OF THIS ISSUE IN PRIOR GENERAL RATE CASES,
DOCKET NOS. 01-10001 AND 03.10011
On behalf of the SNWA, our firm discove an errr made by Nevada Power in
Docket No. 01-10001 wih reec to Jt cost of servce allocation of distbutn
demand costs for the water pumping (WP) rate schedules.
::ODl\PCDSlLRDOCS\120t Page 4
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The err wa simpl that the Company had elected to us custer usage or
bilin detenninant data, not frm the actal and redily avilable WP usage dat by
time of use. but instead fr what it termed "otherise applrcaJe cJasss "(OAC)
usage data reardles of time of use.
The Commissin reognizd the Company's inconsistency and foun at
Ordering Pararaph 585:
The Commisson finds that the IJroposa1 of the SNWA to
base the scedule LGS-WP and LG8-X-WP classe' energy
BTGRs upon the marginal cost study and not the classes'
o1herwse applicble rates is reasonable and approve.
As a.reult, the WP rate in that case were bas on WP usage data by actal
time of use, not the Copany's proposed metod of using OACs' enrgy or kWh data.
regarless of time of use.
WAS THE SAME ISSUE DELIBERATED IN DOCKET NO. 03-100011
Yes.
WHT WAS THE COMMISSION DECISION ON THIS ISSUE IN DOCKET NO. 03-
100011
The Commrsslon revised its prir decision and found tht Neda Po could
allocate WP demand costs on the basis of the energ data of otherise applicable
classes or "OAC.. Ths decision increased WP raes signifnty over the rates tht
would have reulted if acal WP data had ben use.
SO, IS THE ISSUE YOU RASE IN REGARD TO WP DISTRIBUTION DEMAND
ALOCATION IN THE PRESENT CASE MERELY A REHASH OF THE ISSUE WP
CLSES RASED IN DOCKET NO. 03-100011
No. 'provi thIs history so the Commisn has a frme of referenc for the new
discriminatory approach applie by Nevada Por to the detment of water pumplng
::ODMA\PDOLRND01201 Pag 5
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rae schedules in this case. The issue is ne, as Nevaa Power has not use eiher
of the specif allors approve in the preous general rate~. i also prode,
~ background to carefully demonstrate that in the prent case, Nevaa Power has
inexplicaly deviated frm the very same method on this issue th It argued and won
in Docket No. 03-10001.
This new method propose for allocating distrbuton ded costs to WP
classes relts in an approximatey fie-fold incrase in demand cots allocated tó thè
Wpcrasse.
HOW DO YOU PROPOSE TO EXPLAN THIS RATHER TECHNICAL ISSUE?
I develop belo tw tales intended to clarl identi the disribution demnd costs at
issue here; to highlight thtaJl othe rate classes. Including residential and LGS
c'as~ are albcte these disbuion demand costs based on a diferent, and
prper, basis; that Nevada Pow no longer use Its' proposed and authorize OAe
- rate frm OAe kilowtt hours approved Docket No. 03-1001; and, finally. that use of
the Commission appred method in Docket No. 03".1001, while higher than use of
actal WP time of use dat, would allocte fer demand costs to WP classs than
Nevada Powts new and unexlained noncolncident metd.
WHAT ARE THE DISTRSunON DEMAND COSTS AT ISSUE HERE?
The dlstrbutlon demand costs at Issue here are calculated by Nevada Power as a
residual after all other fixed and substtion demand investent and facilies
23 investmnt are removed:
24 /III
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27 1/11
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::ODM"'OCLRNOD120tm1 Page 6
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Total New Distributon Plant Investment ($)
less - Demand-Related Substation ($)
less - Non-Demandacilies ($)
les Faclities Investment ($)
equas = Residual DemandDrin Distbut Invesnt ($)
This redual demand-drive Invetment is .smes referrd to by Nevada
Power and others as "non-revenue feder demand." I WILL simply refer to this redual
as distribution demand.
WHAT ARE THE ACCEPTED COSnNG PRINCIPLES FOR ALLOCATING
DISTRIBUTION DEMAND COSTS?
Nevada Powers cost study determines and calculates the exent to which th
demand cost are caused by system peak demands and th probabirtt of when thes
demands occr. After concluding this, the Nevada Power co of sece study then
goes on to calculate prise IIProbabilit of Peak" or POP coincident peak allocaors
used to separate thes demand cost Into the appropriate pea~ mid pek, of peak
and "other" time of use periods. System peak demand allocators are measure by the
POP, or similar measure of coincdent peak demands in Nevada Power's cost stdy.
The Company doe, in fact, allocate costs of dlsñbuton demand o~ the basis of POP
for all rate classes, except for war pumping, as Is shown in Appndix A, Workaper
3, page 23 of 55 in Exhlbit..Walsh eerlfcation-2.
The basis for using such POP demand allocars is usually the reslt of these
demand costs being cause by time-iferentted peak and of.peak cot caustin.
Nevada Powets co study deteined 1h over 90% of the residual disbufon
demand costs are allote to suer peak periods becuse 90% of the probilit of
::OD\P\HOD12081 Page 7
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HOW DOES NEVADA POWER ALLOCATE THESE DEMAND COSTS TO THE WP
CLAES?
Unlike the Doket No. 03-10001 cáse whre Nevada Power reuest and was
authorize to se WP rates on the basis of energ bUllng determinants for otherwse
applicable classs ("OAC"). th Copany In the pl8sent case uses what is rerr to
as a "noncincident load allocator for the WP classs only. Non concln~ peak
demands have no time of use compone. This Is simply 8 sum of customer or class
maidum demands reles of when they ocr.
1 See Exbit Walsh certifcan pae 8 of 65. line 45, raio of "on" to "Totar.
Page 8::ODMA'iLRD0120821
1 Q. WHERE IN NEVADA POR'S TESTIMONY OR COST STUDY IS THIS WP
2 EXCEPTIN IDENTFIED OR EXPLANED?
3 A. Nowhere. The only way in which one can identif this dlscnminatry tratment of the
4 WP dasses is to carelly exmine fonnJae for actal co allocations In the
5 Company Workpers
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HOW DID YOU DETINE THAT THE COMPANY'S NEW WP DISlRBUll0N
DEMAND Au.CATOR HAS A DISPROPORTIONATELY ADVERSe EFFECT ON
THE WP ClES?
I detennlned this by comparing the Company's propo cost allocation to the WP
classs using it new dlsb'butn deman artoca, compare wf th co alltions
that would have reult from using elterthe Doet No. 01-1001 or the Dock No.
03..10001 approve alloctors, as shown:
LGS-2-WPS
lG8-2-WPP
lG5-2-WPT
LG8-:iwps
pop Allo
(#11-10001)
104,92
41,092
KwhScted
OnOAC
(#3-10001)
151.132
40,820
570.58
74,214
PredNCPSced
LGSWPP
9,058
73,107
81,635
192,279
160,54
474,44
Tot 46,866 1,279,191228,183
Index 2.04 5.811.00
::ODMA\PCORNOO\81201 Page 9
1 Q. WHAT DOES THIS TABLE SHOW?
2 A The table compares the difrences in the amount of dJbutlon demand cost
3 allocated to the WP rate class frm th allocars autorl in Docket No. 01-10001,
4 Docket No. 03-10001, and the COmpany's nely propose non.-lnclde (-NCP") allocar,
5 which is no based upon the same time diferentiated allocators used for other classe.
6 For ease of comparin, I index th lowest level of cost as "1- and the higher
7 allocaors are scled accingly. As is evident Nevada Power's new distribution demand
8 allocator (-NCP allocator") Increses the amount of thes di&nbution demand costs
9 dramatcally, up to 550% over th allocation factr previusly used for the WP classes, and
i 0 tht used in the present sty for all oth bundled reail rate c1asss. The WP classes have
.i 1 been unfairfy singl out here, and with an allocator th Is not In accrdance wih the pri
12 system peakallocaors use forWP classes and presently for all other rate classs.
13
14 Q. IS YOUR OBJECTION TO THIS ALOCATOR BASED SOLELY ON THE FACT
is THAT IT SIGNIFICANTLY INCREASES THE AMOUNT OF DEMAND COSTS TO WP
16 CLASES OVER THAT WHICH WOULD RESULT FROM PREVIOUSLY APPROVED
17 DEMAND ALLOCATORS?
18 A. No, althouh higher costs and relting higher rates are always a concern for WP
19 dasses and. for that maer, all Nevaa Poer cuomers. Hover, in th pmsent Insnce,
20 Nevada Powes selecion of an allocar unrelated to peak period demands is no at al
21 cosistent with fts findings that Over 90% of thes dèmand costs occur in the on peak peri.
22 If Nevada Por relly believe In the theoreical superirity of this allocator, then it certinly
23 should have applied It evnhandely to all classes. Agaln, Nevaa Pots proposal with
24 reard to this allocr to WP rate cfasss is discrminatory, unjust and unresonable.
2S
26 Q. DO YOU HAVE A RECOMMENDATION TO MODIFY NEVADA POWER'S COST OF
27 SERVICE STUDY TO CORRECT THE WP SCHEDULES' DISTRIBUTION DEMAND
28 ALOCATOR?
::ODMA\PCDDO\812081 Page 10
i A. Yes. As' summarzed in my opening te~imony. , recommend eier of tw findings
2 by the Comm;ssion that would restore its poor findings. 1n this case the Commission should
3 order Nevada Powr to be costent in this rerd wih the POP allocator used for all non.
4 WP classes by ordering the pertnent POP WP ra class allocators, as it did in Doet No.
S 01.10001. My Exhibit DEP-1 contins the summary of my cost of service study th underiies
6 my remmenatin.
7 In the aitemaive, th Commission should order Nevada Power to use the kwh scled
8 allocator th th Company argue for and was authori to use in Docket No. 03-10001; in
9 other words, assIgn co bas upon alJocrs used for the otherwse applicable clases.
10
11 Q. WOULD THIS LOWERING OF ALLOCATED COSTS TO THE WP SCHEDULES
12 RASE OTHER CLASES; RENUE REQUIREMENTS?
13 A. The retum to use of allocars previousl use in prior dockets for WP scedules
14 would have a very minimal eff on some rae scules. and no ef on other. The
15 maxmum Incrase to any single rae scedule frm this corrtlon tn WP demand allocators
16 is no more than .05 of 1%.
17
18 Q. WHT IS THE AFÆCT ON WP BUNDLE RATES OF REVRTING BACK TO
19 THESE PREIOUSLY AUTHORIZD ALLOCATORS?
20 A. Whie th impact of using my recommended allocolS ~s minimal for other schedules.
21 the impact on th bundled WP rat scedules is large. Taken as a whole. this fix to the
22 distñbuton demand alloesors would reuce the rates for these classe by approximately
23 $600,000. This would change the Company conclusion that WP scedules be at the caP. to
24 no chang over cunent rates.
25 " "
26 III/
27 1/11
28 1111
::OOMA\Pi:\HL.120,Page 11
1 IMPROVE DOS RATE CALCULATION
2
3 Q. WHT IS THE ISSUE YOU RASE WITH RESPECT TO NEVADA POWER'S
4 CALCULATION OF THE PROPOSED DOS RATES?
5 A. Company wiess Mr. Ghigßeri briefly outlines the devlopment of DOS rates in his
6 testimony at Page 26, lines 14-19.
7 If I may paraphrase to my own words wi reec to th distuton (nonre\'nue
8 feeer) demand component: the DOS dibution rate component for the DOS water
9 pumping classes is the same as that developed for the corrsponding bundled water
10 pumping ctass. Thus. the sae noncolncldent scled allocator usd by th Company, and
i 1 critcize by me in th pring pages. pertains to the DOS rate as welL. This is becuse
12 the DOS rates are not subject to a separate marginal cot stdy. bu instead borr frm
13 the bundled co study.
J4
15 Q. WHAT MODIFICATIN DO YOU RECOMMEND BE ORDERED FOR THE
16 DISTRBUTION DEMAND DOS COMPONENT?
17 A. . No additional modicaon to the DOS dlstnbuon is necessary if the Commission
18 require Nevaa Por in It bundled cost of servce study to reurn to one of the tw prior
19 POP or kw scaled allocars. This corrion would as a mattr of corse be picked up In
20 this component of respective WP DOS rates.
21
22 Q. WOULD THIS CHAGE REDUCE DOS RATES?
23 A. Minimally. I calculat th total savlngs from all six WP DOS classes to be
24 $12,OOr. But this corrn would allow the design of bett DOS rates, as r discss
2S next.
26
27 Q. WHAT RATE DESIGN MODIFICATION TO DOS RATES ARE YOU REQUESTING
28 BE MAE IN THESE PROCEEDINGS?
::ODMACDODCS12081 Page 12
i A. Consistent wit the Companys findings In thir cost of serv sty that its
2 disbuton demand raes are hIghly corrlated with time--use ("OU"), the Compan
3 should implement a TOU-DOS demand chrge. rather thn Its proposed fixed rach
4 demand or kw charg.
S
6 Q. PLEAE EXPLAN.
7 A. Nevada Power propos to slmply sum the facilities demand cost for DOS custme
8 wit the distribution demand charges tha, again, have been shwn to be infuenc by
9 coincdent pek loads.
10 A better mean to present cusomers wi meningfl price signals would be to keep
i i the facilities' charges as propoed, but collec the TOU-rlat distbution demand cost of
12 DOS custmers through peak. mid. of and othr ped per kw charges. as is done for
13 bundled tlme-of-use ra scedules. While collecing an equivalent amount of revenue
14 requirement. my propoaJ has the beneft of prviding a furtr incentive to shif demand of
15 peak to lowe cost perids, reucin additonal distributon invtment for Nevaa Power.
16
17 Q. HOW WOULD SUCH TOU DEMAND CHAGES BE CALCULATED FOR THE DOS
18 CLASES?
19 A. All data nessary to compute thes pek and off peak per kw chrges are contained
20 in Nevada Power's cot of servce stdy. These rates are developed and shown In my
21 Exibit DEP-2.
22 These rates are base upon the time of us distnbution demand co~ developed for
23 the OAe classes. Due to the Intptible provisions and rates of present bundled WP
24 classes, the OAC costs are more relevant since OOS rates do not have an Intenuptible
2S feature.
26
27 Q. WOULD THESE nME DFFERENTJATED DOS DISTRIBUTON DEMAND RATE
28 ON EXHISrr DEP..2 BE OF BENEFIT TO NEVADA POWER AND ITS CUSTOMERS?
::ODM'lDOC\8201 Page 13
1 A. Yes. These fates, becuse they are time diffrentiate, provide appropriate. cot-
2 base incentves to move demand to mid and off peak periods. Accing to Nevada
3 Powes cost stdy, significant amounts of new distribution investment could be avoided tht
4 would otherwse be required to prvide peak deman service. Thes time of use raes
5 provie a more effICent usage of present and new distribution investent and all custome
6 save money.
7
8 Q. DOES 11E PRESENT NEVADA POWER PROPOSAl TO CHARGE RATES fOR
9 THIS DISTRIBUTION DEMAND AS IF IT WERE NOT nME DIFFERENTIATED PROVIDE
10 POOR PRICE SIGNALS?
11 A. Ves. At prent. wate pumping operators are insted to make an reasnable
12 efrt to shif its pumping operations away frm Nevada Power's coincident system peak
13 peri. These shifs, of course, allow energy bills to be managed, but also invotve incurrng
14 signifcant distribution cost to keep demand shifed primarily to off peak periods.
is
16 Q. DOES THE RATE DESIGN PROPOSED BY NEVADA POWR REMOVE SOME OF
i 7 THESE COST BENEFITS TO WP, DOS AND 01lER REAIL CUSTOMER CLASSES?
is A. Yes. Again, the Copany's proposal to charge a flat demand charge for these time
19 sensitve demand cots reduces war pumper incenties to manage its demand In the best
20 manner.
21 The time diffrentiated rates I provide in Exhbit DEP-2. white covering the demand
22 cost incurrd by the COmpny, promote effcient usage and coservation.
23
'24 Q. WHAT AR YOUR CONCLUSIONS~
25 A. t have Identied a major change mae by the Company to the methodology it uses to
26 allocte distribution demand costs to bundled WP ra schedules. These change were no
27 idented or discussed anyw in th Copany's filing, and thy contradict the ratinale for
28
::OD'iDOC\Ø12082\1 Page 14
i allocating such cots to alt other rad schedle on the basis of time-CUffereated
2 coincident demands.
3 If adopted, thes rates would not only be discminato and unair, they would case
4 an unjustifed and abrupt rate increase to the WP schedules. but not appreciably reduc rates
5 to any remaining rae classes. I conclude that the Commission should reJeçt the Companys
6 new methodology and retum to eiter of the tw cost allocation methods it previusly
7 adopted. as identied In my summary on page 3 of my testmony.
8 The Commission should also reconize the benefits in carrng this time diferentiation
9 over to th DOS classe by adopting the ,essentally revenue-neutl demand' raes
10 deVeloped on my exhibit OEP-2.
i i Q. DOES THIS CONCLUDE YOUR TESnMONY?
12 A. Yes.
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
::OD'ILRN0D1201 Page 15
AFIRTION
1, De.s E. Pes~ purua to NAC 703.710 herby af that tbe forego prep
temmony was prear by me or uner my diction and is COIIt to the be of my knledge.
Jl i4-.Des E. Pese
Dated: ,/'16 I¿¡/ ~
Atchent 1
Dkl.0611022
VVftnes: D.E. Pesau
Page 1 of3
STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseu has conducted economic and financlal sties for regulated
Industries for the past twenteight years. In 1912t he was employed by Soutern
Califrnia Edison Company as Assciate Economic Analyt, and 1aer as Economic
Analys. His responsibilites included rew of financial testmony, incrmentl co
studies, rae design, ecnometrc estimation of demand elasticities and various areas
In the field of energ and eonomlc groh. Also, he was asked by Edisn Electril
Instit to study and evaluate several proinent energy models as part of the Ad
Hoc Commitee on Economic Groh and Energy Priing.
From 1974 to 1978. Dr. Peseau was employed by the Public Utlity
Commissioner of Oren as Senior Economist. There he conducted a number of
economic and financial studies and prepare tetimony perining to public utilities.
In 1978 Dr. Peseau established the Nortwest offce of Zinder
Companies, Inc. He has since submitted testimony on economic and financil
matters bere state reulary comissions in Alask, California. Idaho, Maryand,
Minnesota. Montana, Nevada, Washington, Wyoming, the Distct of Columbia, the
Bonneville Power Administrtion and the Public Utilties Board of Alber on over one
hundre occions. He has conduced marginal cost and rate design sties and !.
Attment 1
Ok!. 06-11022
Witness: D.E. Pesau
Page2of3
preare testimony on these matters In Alska, California. Idaho, Maryand,
Minnesta, Nevaa, Oren, Washington and in the District of Columbia. He has
also conducted cost an rate studies regarding PURPA issueS in the states of
Alaska, California. Idaho, Montana. Nevada. New York, Washington, and
Washingtn, D.C.
Dr. Pes8au holds B.A., M,A. and Ph.D. degrees in economics.
He has co-authored a book In the field of Industral organizti entitled,
,Size. Profits and Exeive Compen.iation in the larg Coiporation, which devoes
a chapter to regulated industries.
Dr. Peseau has publisd artcles in the followtng professional journls:
Revew of Economics and Statistics, Atlantic Economic Journal, Joyrnal of Financial
ManagemeQ! and Journal of Regional Science. His articles have bee read befor
the Ecometric Society. the Western Economic Association, the Financial
Management Ascition, th RegIonal Scen ASSciation and universities in the
United Krngdom as wel as in the Unit States.
He has guest lere on marginal costng metds in seminars in New
Jersy and California for the Center of Professional Advancement. He has also
guest lecured on cost of capital for the public utJity industr beore the Pacifc COast
Gas and Electric Association, and for the Executive Seminar at the Colgate Darden
Grauate School of Business, Universit of Virginia.
Atthment 1
Dkt. 0(11 022
Witess: D.E. Pesu
Page3of3
Dr. Peseau and his firm have partcipated with and been members of the
American Economic Association. the Ameñcan Financial Ascition. th Westem
Economic Association. the Atlantic Ecomic Asocation and the Financial
Management Association. He was formerly a member of the Staff Subcommittee on
Economics of the National Asociation of Regulatory Utilit Commissioners.
Dr. Peseau has been President of Utilty Resourcs, Inc. since 1985..
.
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12 FaoCl(pelc.peMo.)13 PrllJ(perkW, peNo.)
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LG$-3S
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38 Fac Chg (pe kW. pe Mo.)
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Checkll:
2,06,211
Margiiii C0 Ba Ri 81CIR8alClsCØlRtueMargal CO ~nue Base Rev-0 -E--F --
$2.478 $178.88 $1.92 $ 138.9
$4,$0.81 $3,$M7
S 20.113 $10.16 $1S,822 $7.89
$2,063 $1.01 $1.603 $0.79
S 373 $0.11 $290 $0.08
$2930 $22766
$2930 $22766
$91 $295.04 $71 $ 229.16
$59 $0.30 $46 $0.23
$48 S 10.25 $379 $7.6i51$0.97 $40 $0.75
$9 $0.08 $7 $0.06
$698 i 64'
$Ð9 $542
$46 $18502 $36 $14372
$1...'$0.3 S 1.119 $0.29
12,$10.3 $9.35 $8.34
$1,21 $1,10 $98 $0.88
$221 $0.11 $172 $0.09
$15.448 $1U99
$15.44 $U.99
S 316 $m.48 $246 $ 22.97
$1.009 $0.25 $784 $0.19
$12,81 $11.06 $9,974 $8.8
S 1.363 $1.14 S 1.059 $0.-
Is 225 $U1 $175 $0.08
1$15,754 i 12,23
$'15.75 $12.2
BlMl Ui~
13,85~7_,m
1,98,010
2,03,133
3,94.008
310
196.e4
47,57
52.68
108,69
2,633,8,335
1,122,311
1.153.534
1.973457
1.7'.,05f,61
1,100.51
1,20.08
Line No.
PeMa-DEP-2
10
11
12
13
14
15
16
18
19
23
24
26
26'I
28
29
30
31
36
"S
38
39
40
41
42
43
44
49
50
51
52
53
54
55
56
57
.. I . .
2
3
4
5
6
1
8
9
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13
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19
20
21
22
23
24
25
26
27
28
PROOF OF SERVICE
I hereby certify that I maled the foregoing Diret Testimony of Dennis E. l)eseau in Phase TV
Cost of Serice and Rate Design in Dkt. 06-11022 on behalf of the Southern Nevada Water Authorit),
via electronic mail and by delivering to the U .8. Post Offce copies thereof, properly addresSl.id for
mailng to th following pens an entities:
Nancy Barker
Nevada Power Compay
6226 W. Saha Ave. MS 3A
Las Vegas, NV 89146
nbarkeieyp.com
Marisa Carena, Rate Analyst
Nevada Power Copay
6100 Neil Road
Reno, NY 895 i i
mcarden~sppc.com
Eric Witkoski, Consumer Advocat
Bureau of Consumer Protection
Oflce ofihe Attorney General
555 E. Washington, #3900
Las Vegas, NV 89101
epwitkoslãag.stte lÐV. us
Chales Radal. Business Mager
IBEW Lol 396
3520 Boulder Highway
Las Vegas, NV 89120
Mark Russell, Esq.
Mirage Hotel and Casina
3400 Las Vegas Blvd. South
Las Vegas, NV 89109
mrusseJi~mimge.com
Donald Brokhyser, Es.
Alcanta &. Kab LLP
1300 SW Fifth Ave.. Ste. 1750
Portland, OR 97201
deMAa-klaw.com
Dan Waite, Esq.
Beckley Singleton, Chtd.
530 Las Vegas Blvd. South
Las Vegas, NV 89101
dwaite(ckleylaw.cQm
::OOMJ\PDOCS\HI.RNODO\l 12179'1
Jan Cohen. Esq.
Public Utilties Commission of Nevada
iOt Covention Center Drive, Suite 250
Las Vegas, NV 89109
jcohen(?puc.state.nv.us
Alaina Burtenshaw
Public Utilties Commisson of Nevada
101 Convention Center Drive, Suile 250
Las Vegas, NV 89109
aburens~puc.sta1c.nv.us
Phil Willamson
Burau of Consumer Prtection
Offce of the Atlorncy General
100 N. Caron Street
Carson City, NY 89701-4717
pjwilliaW.tg.state.nv iUS
Francis J, Mortn, Esq.
IBEW
P.O. Box 370955
Las Vegas, NV 89137
Marta J. Ashcraft
LC\\1s and Roca LLI)
3993 Howard HUges Parkway. Suite 600
Las Veg, NV 89169
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D. George
Th Krger Co.
1014 Vine St., 0-07
Cinciiuati. OH 45202
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Dale Swan
Exele Associates, Jnc.
5565 Sterrett Place, Suite 310
Columbia, MD 21044
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Kur Boeh Esq.2 Michel Kur Es.
Boeh. Kur & Lowr3 36 E. Seventh St.. Ste. 1510
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Dated this 19t day of Marh, 207.
::ODMA\PDOLR12179\ Page 2
Lawrce A. GollompAssistat 0e Counl
Lo H. Cooke, Attrney
U.S. Depent of Ener
1000 Inepence Aveue. SW
Wasington. DC 20685
LawrceGoDorfá.doe
lotcookt.dod.gov
rLõ2~
An employe of HALE LANE PEEK
DENISON. AN HOWARD
HALE LANE
AT'OIlNI!VS AT i.W
m Ed Wilia St I Seii. 200 I Cin Cil)'. NcYim 19101
Telc (775)6l I Fauile t77') 614.6UUI1'- .b11l.wm
Septmber 13, 2006
Crysta Jacksn
Commission iSecre
I 150 E. Wilia Stret
Caron City, NV 89701
RE: SNWA DIRECT TESTIONY DOCKET NO. 06~60S1
Dear Ms. Jackson:
"
pieas~ accept for filing the enclosd original and nine copies of the Direct Testimony of
Dens Peseau on behalf of SNW A in Docket No. 06.0605 i.
Should you have any questions regaring ths filing, please contact me at [phone].
Sincerely,¥1l~
Fred Schmidt Esq.
FJS:taw
Enclosurs
cc: Pares of Reord
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HAL LANE PEEK DENNISON AND HOWAR
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Docket No. 06-06051
Direct Testimony of
Dennis E. Peseau
'.
;: ,"o ::;r,;en .~~en .:."I"-0
on behalf of
Southern Nevada Water Authority
~:: i:'.-''0::';::1":~::oU ,.,òTi:
"' :~'"'.o
:i "0"'~l~cW ;~~(~ý\N :~(1."ö;e ..iPl~SE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Dennis E. Peseau. My business address is 1500 Libert Street S.E.,
Suite 250, Salem, Oregon 97302.
BY! WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
I am President of Utility Resources, Inc. The firm consults on a number of economic,
financial, and engineering matters for various private and public entiies.
oM WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
I a~ testifying on behalf of the Southern Nevada Water Authoriy ("SNWA") and its
cortstiuent members.
DOeS ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND AND
EX~ERIENCE?
Yes.
Wl1AT IS THE PURPOSE OF YOUR TESTIMONY?
,
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Tte purpose of my testimony is to express SNWAls general but cautionary support for
NE!vada Power Company's ("Nevada Power" or '~he Company") filed Integrated
Resource Plan ("IRpU) in the instant docket. The urge for caution that I express below
derives from the enormit of the Company's plan. the very infant or -greenfield" nature
of the bulk of the generation and transmission request, and the capital intensiveness
an~ the long.lead times required to determine the feasibilty of the IRP.
In this regard, I propose that the Commission and parties provide sufcient
support and endorsement for the beginning elements of Nevada Powets filed IRP, but
stap short of the numerous and, in my opinion, premature granting of complete
financial assurances requested by the Company. Specifically, I recommend that the
Cqmmission rule as premature the Company's request for Criical Facilities
designation and instead approve up to $300 milion in the requested preliminary EEC
an~ Intertie studies, to be treated under normal AFUDC accounting (no CWIP) and set
a procedure for eventually issuing a final ruling on Critical Facilites status and related
ac~ountin9 issues at a later dat as the project develops or not.
In the alternative, t recommend that the Commission deny Nevada Power's
re~uest for Critical Facilities designation for the Ely Energy Center ("EEe") and the
50~kV NortlSouth Intertie ("lntertie") unless and until such time as the costs. budget,
¡timing, and rates resulting from completing Phase One can be shown to be
re~sonablei not unduly burdensome, and in the pUblic Interest I discuss these cost
and financial issues below.
WlAT ARE SNWA'S PRIMARY INTERESTS IN THESE PROCEEDINGS?
As Ithe principal water purveyor for the burgeoning southern Nevada economy, the
SNYVA has enormous rnterests in the outcome of this resourc plan case, both as a
ret~i1 electric customer (for DOS and vertically integrated services) and as a
trarasmission customer. The outcome of these and similar proceedings could have a
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sì~nifcant impact on the abilty of the SNWA to continue to economically serve the
water needs of souhern Nevada.
¡ The SNWA has underway its ow water importtion plan, requinng it to be
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setved with energy in eastern Nevada as far north as White Pine County. Regardless
of Ithe eventual shape of its water importtion plan, the SNWA must protect its
customers and control its water pumping costs by developing the best possible
trarsmission and generation options to accommodate its needs. It is critical for SNWA
to ihave the transmission infrastructure to serve its imporation plan in place when
wa~er pumping needs commence.
To this end the SNWA has been developing a transmission plan to meet the
needs of the water pumping requirements associated with its water importtion plan.
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Wl)n the SNWA became aware of Nevada Powts plans last winter to construct
prdposed 500kV lines in the same general area as that planned by the SNWA for its
water importtion project, the SNWA initiated meetings with Nevada Power to discuss
ipOl$sible common interests. At that time, SNWA had atready identified electrical
traijsmission needs in Clark, lincoln, and White Pine Counties as part of its proposed
water importation project. One topic of discussion was the potential to jointly share
ownership of the Nevada Power proposed transmission expansion described in this
filing.
DQES THERE APPEAR TO BE ENOUGH SIMILARITY IN THE TIMING,
CERTAINTY, AND ENGINEERING OF THE INTERnE TO EXPECT THAT A JOINT
OWNERSHIP ARRAGEMENT WOULD MEET SNWA'S CRITICAL TIME PATH?
Wh¡i1e there are some similarities in timing and location, it is not clear that Nevada
Power's (ntertie wil meet the electrical needs of StiA. Most of SNWA's needs in
ea$tern Nevada require a smaller transmission size. The SNWA has, by necessity,
b~n proceding with alternative plans to complete a lesser capacity, 230kV
transmission system of its own, designed to transfer power from Utah to numerous
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SliWA receipt points. The SNWA has a 100MW ownership interet in the
Intermountain Power Project's new coal facilities ("IPP3"). This independent cours by
the SNWA is necessary to assure its ability to complete in a timely fashion the water
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de~ivery system reuired by southern Nevada. Andi while I have not been heavily
in~oived in the ongoing coordination efforts, I have been assured that the SNWA
intends to continue coordinating with Nevada Power in recognition of the needs of
both parties.
HAS THE SNWA CONSIDERED TAKING TSA SERVICE OFF OF THE NEVADA
POWER PROPOSED 500KV LINES RATHER THAN CONSTRUCTING ITS OWN
Li~ES?
Ye~. This is not at all an option satisfactory to the SNWA because of the inabilty to
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us. its low cost capitl to construct the lines, the inabilty to require all cntical
decilines for construction to be'met, and the need for lower voltage service. TSA
ser!ice and its expected higher transmission rates is not considered to be a feasible
opöon to the SNWA. Additionally, SNWA has other public partners with additional
ownership interests in IPP3 wit which it is now coordinating. J provide this
baÇkground to inform the Commission that Nevada Power and SNWA are in continual
dialogue regarding the cordination and cooperation of both parties' proposed
¡tra~smisslon facilities. At this time SNWA's direct involvement in Nevada Power's
Intertia does not appear likely.
iS SNWA REQUESTING THE COMMJSSION TO ORDER NEVADA POWER TO DO
AN¥THING SPECIFIC IN THIS DOCKET TO ACCOMMODAT~ SNWA'S
TRANSMISSION NEEDS ASSOCIATED WITH THE SNWA WATER IMPORTATION
PROJECT?
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N~. SNWA wil continue to discuss possible involvement in the Intertie with Nevadai .Pøwer and commits to also discussing right-of-way and EIS issues with Nevada Power
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as! those issues arise.
WtiAT SPECIFIC CONCLUSIONS HAVE YOU REACHED IN REGARD TO THE IRP,
ENERGY SUPPLY PLAN ("ESP") AND ACTION PLAN FILED BY NEVADA
,
POWER?
A. I conclude tht:
fJn Endorsement
1. Although the preferred plan is not at an the least costly of the plans reviewed, it
provides generation capacity which is eventually needed in the Nevada Power
system and should generally be supported by this Commission. ESP. Acton
Plan Application, pp. 35.37.
Crtical Facilty Designation
2. Any designation of the EEC and Intertie as Critical Facilities or a denial of this
designation is premature at this time and should await more maturity in
development of the plan. A final ruling on this mattr should be deferred until at
least sometime in 2008.
3. The Commission should approve the plan as modifed in its discretion, but allow
AFUDC on construction work in progress ~CWIP), not CWIP in rate base, until
such time as it makes a final determination on Critical Facilties.
4. Nevada Power should be required to clarif rts request for an incentive
return" . . . calculated at 2% above Sierra's authorized weighted return on
equit. . ." (Application, p. 14 of 16, I. 4-5, and elsewher). Specifically, a 2%
weighted return on equity, calculated at a 40% equit ratio, translates to a
requested incentive ROE adder of 5% to the presently allowed equity return.
, Even a' 2% ROE adder to an unweighted ROE amounts to a $935 milion
excess pretax bonus to shareholders over and above it fair rate of return and
should be rejectd.
5. The Commission, in following the recommendation to defer final determination
of whether the EEC and the Intertie are Critical Facilties. or not, should require
certain milestones to have been reached, including. but not limited to, the
grantln~ of a final air permit from the Nevada Department of EnvironmentalProtection, scheduled for January 2008. '
IIIf
till
::ODMIPCDO\HlRNOOOC\5686561
¡Page 5
1 Plin En~orsement
i2 Q. W~AT IS SNWA'S POSITION WITH RESPECT TO NEVADA POWER'S
3 P,OPOSED IRP, ENERGY SUPPLY, AND ACTION PLAN?
4 A. T~e SNWA generally endorses moving forward with the planning and permiting of the
5 E~ Energy Center, related transmission facilities, including the Interte, other
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6 tr~nsmisSion facilities in Clark County, and the approximate 600 MWs of quick start
7 combustion turbines a1 Clark Station. (Application, Items 5, 6, 7, 8.)
8 I The SNWA did not review in detail, and therefore remains silent on, the
9 pr~POSed load and sales forecast and the fuel and energy market forecasts.
!10 (Application, Items 3 and 4.)
!) I i The SNWA oppoes at this time the Company's reuest to have the
i)2 Cqmmission designate Phase One of the EEC and Intertie as Critical Facilties.
i13 (A~plication, Item 9.)
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wltrH RESPECT TO THE EEC. THE INTERTIE, AND THE CLAK STATION
AaDITIONS, WH IS YOUR ENDORSEMENT ONLY "GENERAL"?
iNerada Power should be encouraged to proceed with its extremely ambitious plans
with respect to these facilties. For decades now, the Company has been deficient in
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0wt-generation facilities. The recent additions of the Silverhawk and Lenzie
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ge~eratítig plants. together with the 2,100 MW of requested coal and CT plants, could
Ishilld Nevada Power and it customers from the risk of èapacit cost swings possible
fror any potential future resourc shortges.
I The reason that the SNWA endorsement is cautious is due to the extreme
!umrertinty with respect to any actal building of Phase One of EEC, and the
intardependence of the associated transmission, the Intertie and even the Clark ÇTs.
I
ptE EXPLAIN.
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Q ite some time has elapsed since the completion of major col facilties in the
w stern U.S. and, according to the testimony of Nevada Power, the Company is still
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astessing the viability of various supercritical boiler and emissions contro
1hl10lOgieS (Sims, p. 9, i. 15-18). I am aware of no U.S. projects identical to the
Coripany proposal that have been completed on a commercal,basis in recent years.
i uhderstand that certin tyes of supercritical facilties have been built in Asia. And,
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whr1e the relatively stable nature of the price of coal makes new col facilties
attctve, we are all aware of the potential siting, environmental, and transmissiQn
di4culties associated with large planned coal plants. Today. there exist both strong
Iprdponents and opponents of major new coal generating facilitis. And, while EEC is
reJresented to include u. . . the latest clean-oal tecnologies. . .rr (June 30. 2006,
N~C press release), the siting, water, transmission construction, permiting, and public
en~orsement of the facilty will certainly pose a significant challenge. For these
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re~sons. the SNWA urges the Commission to grant only preliminary approval, but
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reqluire extraordinary updating and progress reports with appropriate' off ramps should
thel project become mired in difculties.
wJy DO YOU CHARCTERIZE PHASE ONE OF EeCI RELATED
~+NSMISSIONt THE INTERTIE, AND THE CLAK CTS AS INTERDEPENDENT?
Tht IRP planning process evaluates the totality of the existing electric system,
tog ther with all of the proposed preferre and alternative plan additons. The need
and optimality of each component is crucially dependent on the succsful
pletion of each and all other proposed facilties. Without knowledge of the
pletion of. say, the preferrd plan as proposed, there is no expectation that the
pro ect is economic (has lowest present worth of revenue requirements, PWRR).
For example, the demise of either the ECC or the Intertie individually would reuire
co plete rethinking of the remaining project. And, due to the need to economically fill
Ne ada Power's load duration curves, loss of either the EEC or the Intertie would call
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question the feasibilty of the Clark Station CIs. versus perhaps the more efficient
hnology of combined cycle CTs. These considerations underscore the need for
ely updates, status report. and possible alterations of the preferred plan.
o THE UNCERTAINTIES YOU HAVE REFERENCED REQUIRE CHANGES TO
T E GENERATION ADDITIONS SECTION (VOL. 1, PAGE 35) OF THE RESOURCE
. With the exception of the request for Critical Facilties designation. I don't believe
th t the requested ESP and Action Plan require changes for my proposal to require
fre uent status updates. Nevada Powets reuest for approval for up to $300 milion
th(1 ugh 2008, qualified by its successful receipt of its air permit should allow Nevada
forward unless and until any subsequent plan obstacles are
W AT ISSUES DO YOU HAVE WITH RESPECT TO NEVADA POWER'S REQUEST
T HAVE THE COMMISSION DESIGNATE PHASE ONE OF THE EEe AND THE
IN ERTlE AS CRITICAL FACILITIES?
Un er NAC 704.9484, i understand that Nevada Powe may request that a facilit of
th utilit be designated as a Crical Facility. I also understand that the Commission,
up n such a reuest, may determine whether to designate suc a facilit as criicaL. In
its ~rder in Docket 04-6030, the commis, sion approved a' similar request by Nevada
Po~er to designate the (now-named) Lenzie Energy Facilty as a Critical Facility.
Th issue I raise in regard to the Company's request for Criical Facilit designation for
the EEC and Intertie facilties is that at the present time it is simply not possible to
co clude that these proposed facilities may meet any of the purposes listed in
par graphs (a) to (e) of the code. The facilities should not, therefore, be designated
ritical at this point. Such a finding would be premature at best.
Page 8S\LRNOD0C66561
Q.Y DO YOU CONCLUDE THAT THE EEC AND INTERTIE FACILITIES CANNOT
2 W BE FOUND TO COMPLY WITH PARAGRAPHS (AHE) OF NAC 104.94841
3 A.T ese paragraph set the standards of:
4 (a Protecting reliabilty;
5 (b Promoting diversity of supply and demand side sources;
6 (c)Developing renewable energy resources;
7 (d Fulfllng specific statutory mandates;
8 (e Promoting retail price stabilty;
9 (f)Any combination of paragraphs (a) to (e), inclusive.
10 Given the greenfield nature of these proposed facilties. the lack of a definitive
11 10 ation to site the EEC, an undetermined and unproven new emissions control
12 te hnology, uncertin water supply , permitting activities stil in process. and
13 co siderable lead times necessary to bring such coal facilities into commercial
14 op ration, no meaningful conclusions can be reached at this time with regard to the
15 de ree, if any, to which the EEC and Interte may eventually enhance system
16 reU bilit, diversit of resources or price stabilty to the Nevada Power system.
17
18 Q.E YOU INDICATING THAT THE EEC AND INTERTIE WILL NOT BE BUILT?
19 A.No As I have stated, the SNWA support the continued study and potential
20 de elopment of these facilties.But, in stark contrast to the Len¡ie facilty that was
21 we I underway and partally constructed and purchased at a large discount to market
22 pri s for new constructon. the EEC and Intertie are stil in the very early, or
23 "gr;enfield" stage of development
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25 Q.W Y DO YOU CHARACTERIZE THE EEC AND INTERTIE AS BEING IN A VERY
26 LY OR "GREENFIELD" STAGE OF DEVELOPMENT?
27 A.Is the same characterization used by Nevada Power (Sims, p. 3, I. 16-19).Also,
28 a ording to Nevada Power witness David Sims, Nevada Power and Sierra Pacific
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ha e together expended only $1 millon in .. . . . preliminary development costs and
st dies on the project. . ," (Sims, p. 10, i. 19-20.)
Thus, to date, only .027% of the expected project costs have been expended,
this on preliminary development. According to Mr. Sims. some of the preliminary
-Identifcation of two potential sites (p. 3, I. 7)
-Review for "greenfield" development of coal generation (p. 3. I, 19)
-Participating in two studies to assess the viabilty of new emissions control
technologies (p. 7. i. 17-18)
-Overcoming the fact that the "only proven process" for reducing C02
emissions would consume roughly one-third of a p'lants power output
and increase the cost of its electricit by 60..00f. (Cite)
Nevada Power; to its credit, candidly admits to the infancy of the study and
de elopment of the EEC facility. At present. there are no site, air permits, water,
p en technologies, emissions plan, fuel supplies, and transporttion or definitive
ap rovals fer the EEC. In my opinion, there is no basis for concluding at this time that
the EEC and Intertie are in any way critical among the numerous supply plans
revewed and analyzed. The Commission should postpone it determination of
eri calit and await the attinment of milestones prior to maltng this decision.
AT TYPE OF MILESTONES MIGHT THE COMMISSION REQUIRE?
dition to awaiting the engineering and design to take shape. the awarding of a
fin I air permit by the Nevada Departent of Environmental Protection (estimated
Ja uary 2008), the final EIS (estimated May 2008), and the BlM Record of Decision
(e imated July 2008) would be good indicators of whether the actual project is
f'
Also, a report from Bums & McDonnell indicating whether it has or has not been
abl to determine from it study whether the various supercritical boiler and emissions
tee nologies, and site constructabilty are viable would be very useful (Sims, p. 9, i.
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1 -29). After this it may be possible, with at least some degree of confidence, to begin
to predict whether and when these facilities are likely to add reliability, diverity and
pr ce stabilit to the Nevada Power system and its customers.
IF THE COMMISSION CHOOSES TO DEFER ITS DETERMINATION REGARDING
T E REQUEST FOR CRITICAL FACILITY DESIGNATION, HOW DO YOU
R COMMEND THAT EXENDITURES ON THESE FACILITIES BE ACCOUNTED
F R?
I 11 commend that, prior to final Critical Facilities designation, all such expenditures be
tre ted for accounting purposes consistent with current accounting methods. The
ex enditures would earn AFUDC, but not CWiP in rate base at this time. Thus, upon
an eventual future designation as Critical Facilties, only expenditures subsequent to
th determination would be eligible for favorable treatment and then only if granted at
Ui t time by the Commission.
E YOU GENERALLY IN FAVOR OF ALLOWING CWIP IN RATE BASE?
No not generally. In my opinion, awaitng a final determination of rate base tratment
un il faciliies are clearly Mused and useful" has been a superior form of regulatory
tre tment for new construction.
SE EXPLAIN.
arguments against a regulatory convention granting CWIP in rate base are not
to Nevada. In the instant proceedings, however, the uncertainty, magnitude and
pre iminary nature of the propos plan argue furter for not allowing CWIP in rate
ba e at this time. The primary shortcomings of Nevada Power's request for CWIP in
rat base at this time are twofold. One, the long lead time, coupled with the
pre iminary status and accompanying completion risk of the project at this time. would
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si nifiQantly raise present customers' rates far in advance of any genuine èxpectation
of the ¡'use and usefulness" of the preferred plan.
Secndly, the Commission should always attempt to align i to the extent
p ssiblei the benefits of resource additions with the customers receiving such benefi.
U der the Company's preferred plan, the long and probable lengthening of the
s gested lead times to reach commercial operation of Phase One of the EEC and
rtie, would necessitate significantly higher raes in the next several years to be
bo e by customers prior to commercializatin. Corrspondingly, the rates to
cu tamers consuming energy from the date of commercialization and extnding over
th life of the EEC and 'ntertie projects would be lower. The accounting convention of
A U DC better aligns project costs with customers enjoying the benefits of the projects.
arguments I have just cited are not meant to argue absolutely against the granting
WIP in rate base, as NAC 704.9484 clearly allows this consideration, but instead
to point out the serious objections of granting the reques1 so far in advance of the
re sonabJe knowledge of the success of the proposed projects.
T ARE YOUR ISSUES WITH RESPECT TO NEVADA POWERIS REQUEST
FRAN INCENTIVE RETURN ON EQUITY FOR THE EEC AND THE INTERTJE?
Th primary issue I raise with respe to the Company's requested 2% ROE adder is
exceìve burden it plelces on ratepayers, especially in light of the fact that the
pr ferred plan with EEC and the Intertie is not the least cost of plans analyzed by
,
Ne ada Powr.
First, however, there is a need for clarification with respect to the Company's
2o/ ROE adder request.
W AT CLARIFICATION 00 YOU SEEK WITH RESPECT TO THE COMPANY'S
REQUEST FOR A 2% ROE ADDER?
::ODMA\PCO CS\lLRNOOOCS\566656\1 Page 12
A.In at least three places in its fiing, Nevada Power requests an ROE incentive
2 ret rn ".. . calculated at 2% above Nevada Powets authorized weighted return on
3 eq Ity" (Application, p. 14, I. 5-6; Yackira direct, p. 14, i. 15-16; Vol. 1 ESP, p. 36,1'4)
4 (e ph as is added).
5 The term "weighted return on equity" in cost of capital parlance indicates that
6 Company is reuesting far more than a simple addition of 2% to its authonzed
7 eq it return of 10.25%. The authorized 10.25% equity return is an unwighted equity
8 ret m. To reach an overall allowd rate of return on capital, the unweìghted equity
9 ret m is multiplied by the equity ratio and added to the unweighted debt cost multiplied
10 by the debt ratio.The reason that the issue of whether the Company really is
11 reuesting a 2% adder to the weighted equity return is so important is because a 2%
12 eqiit return added to the authori wehled equit rern ecua grats the
13 Co pany the equivalent of a 5-6% ROE adder.
14
15 Q.
16 A.My Exhibit 1 (DEP-1) demonstrates the signifcant difference betwen adding a 2%¡-
17 R E adder to the authorized unweighted return and adding a 2% ROE adder to the
i 8 aut orlzed weighted equit return.For clarity of example, the comparison is made
19 as uming a 10.25% authorized equity return, 7% debt costs, and a 57/43% debt-
20 eq ity to capital ratio. As shown in the exhibit, if the requested 2% ROE incentive is
21 ad ed to the weighted return (the 4.41%) As literally requested by Nevada Power, the
22 res It is to actually grant shareholders a 14.9% overall equity reurn.
23
24 Q.01 YOU ATrEMPT TO CLAIFY THIS ISSUE WITH NEVADA POWER?
25 A.Ya . In response to SNWA-1, the Company indicated that it would apply the 2% ROE
26 ad er to the unweìghted return on equity. ' I atach a copy of this response as Exhibit 2
27 (0 P-2).Since the Company filing stil indicates 1hat the 2% ROE adder is to be
28
Page 13
2
3
4 Q.
5
6 A.
1
8 Q.
9
10
11
12 A.
13
14
15
16
17
18
19
20
21 Q.
22
23 A.
24
25
26
27
28
ad ed to the weighted return on equity, my testimony above is intended to note this
in nsistency and clarify the intent and extent of the ROE incentive adder.
H W WAS THE 2"0 ROE ADDER TREATED WITH RESPECT TO THE INCENTIVE
R URN ON THE LENZIE ENERGY FACILITY IN DOKET 04-6030?
2% ROE adderwas added to the unweighted equity return (Order. Page 23).
A SUMING THAT NEVADA POWER'S REQUESTED 2% EQUITY RETURN
IN ENTIVE IS MEANT TO BE ADDED TO THE AUTHORIZED UNWEIGHTED
EdulTY RETURN OF 10.25%, WHY DO YOU CHARACTERIZE THE 2% AS
~CESSIVE?
If lIowed, the requested 2% incentive adder on the unweighted equity return will
pr vide investors with a $935 million bonus in nominal dollars over the life of the
pr 1ectl If the Company's request is for the adder to be on the weighted equity return,
th t bonus is Increase to approximately $2.1 billon. And, at the same time, the
ad itons of the Lenzie and Silverhawk plants, together with the completion of more
th n $4 bilion in new generation, transmission, and DSM facilities (Vol. II, Action Plan,
Ta Ie AP-1) wil greatly increase the present level of rate base of Nevada Power and
p vide investors with growing returns.
DO YOU SAY THAT NEVADA POWER'S REQUESTED 2% ROE BONUS
Wi L-PROVIDE INVESTORS WITH $935 MILLION IN ADDITIONAL PROFITS?.
Th essentials of this calculation are shown in Exhibit 3 (DEP--). The budgeted
e enditures for the EEC and Intertie investment are capitalized and given the
ad itonal 2% ROE adder over the life of the assets.
Exhibit 3 (DEP-3) calculates a totl incentive-related revenue reuirement over
the lives of the assets of $935.024,000 (for 100%), 80% of which is propose to be
ch rged to Nevada Power customers.
::OOMA\FC CS\LRNOOOCS\5666561 Page 14
i Q.
2
3 A.
4
5
6
7 Q.
8 A.
9
10
11
12
13
14
15
16
17
18 Q.
19 A.
20
21
22
23
24
25
26
27
28
Y DO YOU CHARACTERIZE THE $935 MILLION INCENTIVE BONUS TO
IN ESTORS AS EXCESSIVE?
Fi t, and perhaps foremost, the propose new EEC and Intertie facilities, while a
w Icome change from exposure to market power, wil already be a boon to investors
wi hout a $935 millon bonus.
In ecnt years, Nevada Power investors have been disadvantaged by the Company's
la k of generation resource additions dating back to the early 1990s. I realiz that
ada. like a number of other states, had an interlude where the advent of market
petrtion required a pause in utility generation additions. As a result, the bulk of the
pany's revenue requirement in the last decade and a half has bee comprised of
sig iñeant expenses upon which investors earn no money. Relativ to many other
et ctic utlities, Nevada Power's preference for market purchases, combined wit
sig ifcantly depreciated existing generation facilitie, has made the Company less
aU active in terms of investors' earn¡ngs base.
IS HE LACK OF CAPITAL INTENSIVENESS CHANGING FOR NEVADA POWER?
Ye , very much so. And again, this is a good thing. for the'most part, for both the
Co pany's shareholders and its customers, if rates can be kept from increasing
un ecessarily. The requested 2% ROE incentive adder is entirely unnecessary.
Nevada Power's rate 'base in 2005, according to the filing in Docket No. 06-
16, was $2.3 billon. Upon copletion of the proposed EEC, the Intertie, and other
tra smisslon facilities, the Company's rate base could easily be $6 or 7 bilion, or 3
tim s the 2005 leveL. In my opinion, the recent positive financial strides experience
by evada Power and the favorable increses in earnings assets just noted will allow
the Company to reach investment grade status very soon and does not reuire the
ad ¡tiona i $935 milion incentive.
Page 15
1 Q. H VE INVESTOR INSTITUTIONS RECOGNIZED THE POSITIVE INVESTMENT
2 A D GROWING ASSET OUTLOOK FOR NEVADA POWER?
3 A. Y, s. For example, on September 11, 2006, Deutsche Bank upgraded SPR frm a
4 ho d to a buy recommendation, increasing it stock price target from $14.50 to $16.50
5 as a result of infratructre growh. My Exhibit 4 (DEP4) contains excerpts from
6 pr 88 releases on this topic.
7
8 Q. A E THERE OTHER REASONS WHY YOU CONSIDER THE COMPANrS
R QUESTED 2% ROe ADDER EXCESSIVE?
Ya. No one should forget that the last few years have arguably been as difcult for
Ne ada Powets customers as it has been for its shareholders.
In 1999, for example, Nevada Power retail rates were relatively low compared
other western electrics. Today, Nevada Power's rates rank among the highest in
the West, exceeded only by the most expensive Califrnia electrics, as cleany
iIu trated in the Supplemental Testimony of Company witness Anthony J. Karr.
Given this, the rapidly increasing earnings base being experienced by the
pany, and the fact that management is just doing it job in building adequate
res urces to serve its load, customers ought not be burdened with also paying greater
pro its to shareholders.
9
10 A,
II
12
13
14
15
16
17
18
19
20
21 Q.
22
23 A.
24
25
26
27
28
IS NEVADA POWER'S REQUESTED PREFERRED PLAN THE LEAST COST
AM NG THE NUMEROUS PLANS IT ANALYZeD?
No, a number of the plans analyzed by the Company have lower lifetime costs. As
su marized in Technical Appendix II. Supply Side Book at least four of the alternative
pIa. s analyed by Nevada Power have lower costs than the preferred plan. These are
Ca eNos. 13. 15,4 and 12.
::ODMA\PCDO S\HLRNODOS\56\1 Page 16
i Q.
2
3 A.
4
5
6
7
8
9
10
II
12 Q.
13 A.
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
THE FOREGOING FACTS REGARDING THE MORE EXPENSIVE REQUESTED
EFERRED PLAN ARGUE FOR REJECTION OF NEVADA POWER'S REQUEST?
, as I have stated, despite the fact that the preferred plan is more costly than others,
th SNWA supports at least the initial pursuit of the plan.
My criticism in this regard is that Nevada Powr's requested $935 milion
ex ess burde" on this plan is on top of an analysis that even absent this bonus, the
pr ferrd plan is considerably more expensive than several alternatives. This, and
co sideraton of the preferred plan's clear benefits for shareholders, lead me to
co elude that in fairness to customers, at no penalty to shareholders, the Nevada
P wer request for the 2% ROE adder be denied at this time.
P EAE SUMMARIZE YOUR CONCLUSIONS
Th SNWA generally endorses the proposed IRP. At this stage, however, there
cl arly exist numerous elements to be studied and analyzd before full approval
sh uld be granted by the Commission. Specifc and frquent updates and progress
re orts $hould be required to be provided by the Company as a means of confirming
viabilty and feasibilty of the proposed resource plan, Energy Supply Plan. and
a ociated Action Plan.
The Commission, in my opinion, lacks any significant information at this time
re arding how useful and "critical" the propose plan wil eventually be. As a reult, a
ju icious step would be to postpone and defer any requested ruling on Critical
Fa ilities status until at least sometime in 2008.
Any conclusions on the approval of, or extent of any favorable accounting and
eq jty return incentives, should also be postponed and evaluated again later in lîght of
balance between customer and shareholder interests.
::OOMA\PCD C$LfUOOCS68~1 Page 17
AFIRTfON
I. mis E. Peseau, purt to NAC 703.710 hereby af tht the foregoing prpar
testimony as preed by me or under my dirction and is correct to the best of my knowlede.
/J. .~W&nenE:Peseau --
Dated: 1- ~$ - D 42
Page 18
Attchmenl1
Dkt. 06.08051
Witness: D. E. Peseau
Page 1 of3
STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseaù has conducted economic and financial studies for regulated
industri for the past twenty-eight years. In 1972, he was employed by Southern
Edison Company as Associate Economic Analyst. and later as Economic
Analyst. is responsibiJitls included review of financial testimony, incremental cost
in the fiel of energy and economic growh. Also, he was asked by Edison Electrcal
study and evaluate several prominent energy models as part of the Ad
itteeon Economic Growh and Energy Pricing.
From 1974 to 1978, Dr. Peseau was employed by the Public Utilty
studies, te design, econometric; estimation of demand elasticities and various areas
Commiss oner of Oregon as Senior Economist. There he conducted a number of
economi and financial studies and prepared testimony pertaining to public utlities.
In 1978 Dr. Peseau established the Nortwest offce of Zinder
Compani 8, Inc. He has since submited testimony on economic and financial
matters b fore state regulatory commissions in Alaska, Californía, Idaho, Maryland~
i Montana, Nevada. Washington, Wyoming. the District of Columbia, the
Power Administration and the Public Utilties Board of Alberta on over one
hundred ceasions. He has ~onducted marginal cost and rate design studies and
Atachment 1
Okt.0606051
Witness: D.E. Peseau
Page2of3
testimony on these matters in Alaska, California, Idaho, Maryand,
, Nevada, Oregon, Washington and in the Distrit of Columbia. He has
also co dueled cost and rate studies regarding PURPA issues in the states of
Idaho, Montana, Nevada, New York, Washington, andAlaska,
Washin
Dr. Peseau holds B.A., M.A. and Ph.D. degres in economics.
He has co-authored a book in the field of Industrial organiztion entitled,
Size Pii fits and Executive Com
a chapte to regulated industrie.
Dr. Peseau has published artcles in the following professional journals:
f Economics and Statistics, Atlantic Economic Journal, Journal of Financial
Mana e ent, and Journal of Regional Scjence. His articles have been read before
the Eco ometric Society, the Western Economic Association, the Financial
Manage ent Association, the Regional Science Association and universities in the
UnitedK ngdom as well as in the United States.
He has guest lectured on marginal costing methods in seminars in New
Jersey a d California for the Center of Professional Advancement. He has also
guest Ie ured on cost of capital for the public utilty industry before the Pacific Coast
Gas and ElectricAssociation, and for the Executive Seminar at the Colgate Darden
Graduat School of Business, Universit of Virginia.
Attment 1
Dkt.066051
Witness: D.E. Peseau
Page 3 Òf3
Dr. Peseau and his firm have participated with and been members ofthe
America Economic Asociation. the American Financial Association, the Western
Econom c AS$ociation, the Atlantic Economic Association and the Financial
Manage ent Association. He was formerl a member of the Staff Subcommittee on
Economics of the National Association of Regulatory Utility Commissioners.
Dr. Peseau has ben President of Utilty Resources, Inc. since 1985.
Dkt lJD6051
Peseau DIrect Tesmony
Exhibit DEP.1
Page 1 of1
N~da Power Company
, E eç of 2% ROE Incent on Weighted and Unweløhted Equity Rctum
Sourc
Debt
Preer Equit
Common EquIt
Marglnal Cost of cetar. Ba
Unwhted
CO
7.00%
0.00%
L . '9.60%1
Tota 8.65%
arlnal cos of calt. 2% ROE IncetN Added to Weighted Equity CostUnwht Weighte
Cost Wei ht Cost'
7.00% 57.0% 3.99%
0.00% 0.00 0.00%
15.25% 43.00%1 ø.5G%1
Sou
OébtPrefei Eqt
COmmo EquIty
Tot 10.55%
alQnal Cot of capi ~2% ROE In'*ti added 10 Unweht EQUly CotUnweghted WejglitøCo We ht Cost
7.00 57.0% 3.99%
0.00% 0.00% 0.00%
12.60%1 . 43.rJO% 6.42%
SOlrc
Dèb
Pr EquityCo Eqult)
Totl 9.41%
Dkt. 06-051
Peseau Testimony
Exhibit DEP-2
Nevada Power Company
RESPONSE TO INFORMATION REQUEST
DOCK NO.:06-6051
SNWA1
REQUEST DATE:8123/2006
RESPONDER:Karr, Tony
Please onfirm that Nevada Power Company ("NPC") intends, as is stated In Yackira
Direct, . 14, i. 15-16 and p. 36, ESP, Vol. I, to request an incentive return ". . .
calcutat d at 2% above Nevada Power's authoñzed weighted return on equit. . . .ri or is
the requ st for 2% above its unwighted return on equity? Please provide a detailed
exampl of the calculation of the incentive retum as reuesed by Nevada Power for
eventua cost recver.
CONFI ENlAl (yes or no): No.
Nevada ower Company would apply the requested lncentive ROE of 2.00% to the
unweigh ed return on equit. Assuming the authorized ROE is equal to the cost of capital
of 10.60*, (used in this filing), the unweighted equity component will equal 12.60%.
The rna inal weighted cost of capital with the ROE incentive would total 9.41%. This is
an ¡nere se of 86 basis point from the total weighted cost of capitl of 8.55% used in
the filing
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Okt. 066051
Peseau Testimony
Exhibi OEP.4, 1 of 2
~BûSì · Mar~ ets · Analyst News · TechnQIQgy News. press Releases · By Indystr · My PortoUo News
Sien a Pacific Resources upped at
Deul sche Bank MarktWatch
6:11:1 AM i: 9/11/2006
LONCON (MarketWatch) -- Deutsche Bank
UpgTe ded electric uttlty Sierra Pacific
Resoi rces (SB) to buy from hold and raised
its pr ce target to $16.50 from $14,50, citing
requi oed infrastructre growth In Its Las
Vega and Surrounding Nevada service
terrlt rles.
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Dkt. 06-oS051
Peseau Dir Testimony.__Exhbll.DEI?-4_ . _..
Page 2 of2
SUbJec: Reuters. - UPDATE i-RESEARCH ALERT-Deutsche Bank uP91'des Siera PaCific - Mon Sep 11, 2006
, 11;46,6 ET
.:il"if
UPDATE i.RES ReM ALeRT-Dutche Bank upgrades Sierr Pacific
Mon Sep 11, 200611:46 AM eT
(Changes sourç.
Set 11 (Reuter) - eut Bank on Monday raised its rating on Sierr Pacc Resurcs oCRP .N~ to ~buy from "hold" and
increase its 12-mo th prlce taret by $2 to $16.50.
In a researc note t e brokere sai the upgrade was based on Its updated work on the utilit owners required infrstruur
growth in its Las V as and surrounding Nevada llervce terriories.
'Te "prerre" Ely nery Centr pulvriied co integrated resurc ptn is the lor cos and most atractiv generaion
developnt prora for ratepayrs over the tong term, compared to higher co and voati1 naural gas fired generan, the
brorage said.
This, 8101' with the otentlal for eriical faility status, has the adde benefit of additionl gain and value creation for
siiareholders, It arJd .
Share of the comp ny ro over 2 percnt to $14.70 in moring tre on the New voi Stoc Exchange. (Reporting by Swta
Singh and John Tila in BangaJre)
......... ._.. "" ...._-_..... ....__.......... ...--........_-_.--..._...._-_...... -_...._-- -_. --'-' _.-_..... --_..- ......_.. --_..._- ....._.
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o Copyright Reuters 20061 rlght re&&ived. Users may dowload and prit exract of content from this webte for their own
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Quotes and other d a are provided fo your peonal informatin onl, and are not Intended for trading purposes. Reutel", the
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9112/2006
2
3
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27
28
PROOF OF SERVICt:
I ereby certify that I served the foregoing Direct Testimony of Denis E. Pescau on behalf of
SNW A' Docket 06.06051 by sending via electnic mail to the following addresses and by
delivcrn to the U.S. Post Ofce copies thereof, prperly addressd for mailng and postage pre-paid
to the fol owing persns:
D uglas Brooks, Esq.
Si rr Pacifc Power Company
P. . Box 98910
6 26 West Sahar Avenue
L Vegas, Nevada 89151
d oak .com
Sta CouneJ
Public Utilties Commission of Nevada
1 i 50 E. Willam Street
Carson City, NV 89701-3109 '
ut1inge~puc.stte.nv .us
Alaina Burlenshaw
Public Utilties Commission
101 Convention Center Drive, Suite 250
Las Vegas, NV 89109
aburts~puc.state.nv .us
P ul Stuhff
B au of Conser Protetion
555 E. Washington Street, Ste. 3900
Vegas, NV 89101
tuhff(gag.state.nv.us
Nancy Barker
Nevada Power Company
6226 W. Sahar Ave.. MS3A
Las Vegas, NV 89146
nbaker(gevp.com
Kathleen M. Drakulich, Esq.
Kummer Kaempfer Bonner. et al.
3800 Howar Hughes Parkway, 7th Floor
La Vegas. NV 89109.0907
kdrakulich~kkbr.com
e Stransky, Senior Engineer
u of Consmer Protection
N. Caron Street
on City, NV 89701
trs(sag.state.nv.us
E est K. Nielsen, Esq.
W hoe County Senior law Project
11 5 E. Ninth Stre
R 0, NV 89512
en elsen~ashoecounty.us
Willam Bible
Nevada Resort Association
3773 Howard Hughes Parkway, Ste. 320 N
Las Vegas, NV 89109
bbible~nevadaresons.org
E. eif Reid, Esq.
Le is and Roca LLP
S3 S Kietze Lane, Suite 220
Re 0, NV 89511
Ire d~ir1aw.com
Steven D. King, Asst. City Attorney
City of Fallon
P.O. Box 1203
Fallon. NY 89407
:;ODMA\PCD CS\Hl.RNODOQ,'\66(j70\1 Page i of2
Bi 1 Kockenmeìste. Esq.
P. . Box 71583
no, NY 89570
Jb sk6(charer.net
Mara J. Ashcra, Esq,
Lewi an Roca LLP
3993 Howar Huges Parkway, Ste. 600
Las Vegas, NV 89169
Mashcra:lrlaw.com
D uglas Davie
W llhead Electnc Company
65 Bercut Drive, Ste. C
S iamento, CA 95814
Patrick V. Fagan, Esq.
P.O. Box 646
Carson City, NV 89702
pfaga(IaUisonmackenzie.com
Michael J. Bertran, CPA
Energy Control Systems, Inc.
so I S. Carn Street, Ste. 206
Caron City, NV 8970 i
D vid Lloyd
S TO Power Company, L.P.
c/ NRG Energy, Inc.
1819 Aston Ave., Suite 105
C lsba, CA 92008
M KJefeker
L Vegas Cogeneration II, LLC
35 Indiana St., Suite 400
Olden. CO 80401
Mar Russell, Geeral Counsel
Mirage Hotel and Casino
3400 La Vegas Blvd. South
Las Vegas mr 89109
Chip Little
Mirat Americas, Inc.
I 15S Perimeter Center West
Atlanta, GA 30338
Scott Carer
L8 Power Development LLC
Two Tower Center, 20th Floor
East Bruwick, N.J. 08816
TED this i 3th day of September, 2006.
_~. :J14;"An employee of HALE LANE PEEK
DENNSON AND HOWARD
::ODMA\PC HLIlNODOS\66670\J Page 2 of2
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26
BEFORE TH PUBLIC UTILITIES COMMSSION OF NEVADA
2
3
oCl
4 Investigati n to analyz the strgts and weakess )
of mana cost of seice studies, embedded cost )
5 of servce s dies, the reconcilation process and )
how they j pact rate classes. )6 )
SOUTIRN NEVADA WATER AUTORI'S
REPLY COMMENTS ON MARGINAL AND EMBEDDED COSTING
PREPARED BY DR. DENIS PESEAU
, i
-,
Dkt. 06-05007 ,.f
~ :1".~....
\J''
SO THRN NEV ADA WATER AUTHORITY (USNW N'), puruat to NAC chpter 703
and the Req est for Comments in this docket datd May 3 i, 2006, hereby submits its Reply Conuents
to the Pu lie Utilties Commssion of Nevada (UCommission") regarg cost of service
metbodolog es.
Sumar Conclusons
11 uly 17,2006 opening comments of Nevada Power Compay ("NPC") and Sierr Pacific
Power Com any ("Sier"), the Burau of Consumer Protection, PUCN Staf, and Soutern Nev
Watr Auth rity regarding marnal and embedded cost of service studies ar in substtial general
agrment.
Key onclusions incIude:
1.Marina costs should continue to be a priar basis for estimag cost and
Nevada.
2. Some ty of equi-propOI1ional scaling of marginal costs to revenue
requirements should be continued, whether to overl revenue requiment or individual
fuctions.
3. The revenue requirent should continue to be fuctionalized pror to marginal
cost reconcil tion.
27 1111
28 1111
::ODMA\P LRNOOO\5SS270\1 Page i of5
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4. The use of inverse elasticity to allocate costs has been correctly dismissed by the
2 Commissic n in the pas due to the lack of credible elascity studies both for customer classes an
3 demand, er ergy, and customer cos categories.
4 Oif erences suraced with respect to:
5 i.Whether embedded cost of service stdies nee to be taen all the way to the
6 individua customer class levels, as opposed to only fictions.
7 2.Whether or not, and the bas by whch, the "next generaing unit' afects
8 margial capacity cost calculations.
3. Whther or not, and the extent to which, maginal caacity costs can differ frm
those of the least costly peakng unt.
DISCUSSION
A. Usefulness of Embeded Cost Stuies
Th opening comments of SNW A supported the fdin of embedded costs broken down to
fwctions. fhe SNW A sees no nee to continue such sties disagegated and clasifed to the
customer cIa ss leveL. Ther is a theorecal shortcoming of historica embedded cost classification an
aJlocation fa tors (e.g. maximum, peak and averge deds) compard with marginal cost factors.
Seco dIy, embedded cost of serice studies taen to the custome clas level pree that the
historical co t and reur mix of a utlity provides reasnale prce going forw. The SNW A
concludes th t the marginal cost of serice studies tyically conducted in Nevada provide superior
20 pricing infon iation to conser.
21 B."Next Generating Unit"
22 There is some confuion surounding the estiate of geeration capacity cost and the "next
23 generating UJ 'f' in the utilties' resource plan. TIs confusion appea to stem from the Jack of a
24 carful distini tion between "long~ru" and "short-ru" maginal costs.
25 Nevada ha always adhered principaly to Long-RlU Incrental Costs (LRIC). This concept
26 is,adttedh. purely a theoretical constct, full of convenient assumptions (e.g. instaous
27 adjustment 01 all factors of production). LRIC is the basis for the peaker method of estimting
28 generation ma ginaJ costs and the ''NRA Method" used in Nevada. Under this method, the utility and
;;ODMA\PCJXIH RNODSISSS270\¡Page 2 ofS
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the entire nterconnectd electrca grd is assw to be In peect equilbriwn at aU times. In such
instaces, with no excesses or shortes of capacity allowed, the marginal cos of caacity mus
necesl be equa to the cost of a peaker. Ths, of coure, holds only beuse of the convenent
assumptio s. With no allowance for shortges, excesses, or suboptimal generating unit mixes,
marinal pacity cost never dep above or below th pea cost regarless of the cost of the actu
next unit
All the above conclusons chage dratically un mainal cong prnciples that ar not
purly and eoretically "long-ru." Car must be ta not to mix concept of "long-ru" and shrter~
tenn mar' al cost. Under the latt, marginal capacity cost of genertion ca move radicaly upwad
Matematically. shorter~tenn magina cost mus be modeied caefully with'
capacity expanon and prouction cost models. Under such circumstances, the actul
umstances of th utiity detere the main caity cost In such ca, the fuel
savings by actu more effcient new plants ca be a credt or offset to capacity cost potentily
reulting in arginal capaity costs lower th a peer. Or, convery. in times of
region capacity
shortages. fown-out and black-out give rise to so-alled "shortge costs" of capacity that ca
the margina cost of a peaker.
Th potential for wide swings in magi caity costs, and reting swings in customer-
class revenu requirements, ha Jed may state regulatory jwisdietions, including Nevada, to remain
ru incrmenta or marina costing metods.
CONCLUSION
NW A addrsse the followig. more specific, reks of other paes:
i. Th Companes' conclusion is coiret tht th marinal cost of genertion,
under Nev 's application of long ru marginal cost is not infuenced by the next unt to be
24, built. (Sie evada opeg comments, p. 4. Jins 2-16)
2S 2.The Companes' arguments that there is a logica consisteny in seartely
26 reconcilng d strbution marginal cost but luÌping Into one category all remainig costs, is
27 incorrct.'le the SNW A does not in this case oppose the Companes' proposal, the iss of
28' 1III
LRNODOS\S$270\J Page 3 of5
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28
reconciln unbundled funetonatize costs should be made on a case-by-cas bais as a mean
to avoid 'ntention subsidies. (p. 3, lines 8-24) As a genera mater, the reoncilig of costs
accordin 0 the total of all fuctions will best reect marginal cos. The reonciling of cost
individua functions bettr reflects embedded costs.
3.The Bep's comments regag the netting of fuel savings and/or market prce
from the c st of a peakng unit (p. 3) is not appropriate under Nevada t s purly long ru costing.
When we swne tht al generation is always in exact equilibrium, there can be no additional
fuel saving or maret price discrpancies.
4. The discussion of Hoover B is not appropriate for reonciling marginal cost.
Hoover B ower is the cheapet reure on Nevda Powers sysem an therefore would never
be on th m gin or influence the marginal cost study.
RE PECTFLL Y SUBMITT ths 31st day of July, 2006.
BY:.:~~
FRD SCHMIDT
Hale Lae Peek Dennson and Howa
777 Eat Wiliam Street, Suite 200
Carson City, NV 89701
[phone]
and
CHAS K. HAUSER
Gener Counsel, SNWA
1001 S. Valley View Blvd.
La Vegas, NY 89153
[phone]
Attrneys for the SOUTHE NEADA
WATER AUTHORIY
::ODMA\PDOS RNODQs\SS270\1 Page 4 of5
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PROOF OF SERVICE
I h reby cert that I maled the foregoing Souther Nevada Water Authority's Reply
Comments on Marginal and embedded Costing in Doket 06-5007 by deliveg via U.S.P.S. copies
perly addrsse for mailing to the following persons: .
La ise Uttinger, Assisant Staff COWlsel
Pub ic Utilities Commisson of Nevadai i 5 E. Wilia Stret
on City, NV 89701-3109
utti geg(gpuc.state.nv.us
Wil . am Staley
Sen or Deputy Attorney Gener
Bur au of Conswner Protection
100 . Carson Strt
C n City, NY 89701.4717
wbs ane~.state.nv.us
ths 31 st day of July, 2006.
::ODMA\P LRNODO\SSS270\1 Page S ofS
Alaina Burensbw
Public Utilities Commssion
101 Convention Center Dr., #250
La Vega NY 8910'9
abuns(!uc.state.nv.us
Elibet Ellot
Assistt Sta Counl
Nevada Powe Compay/SPPCo.
6100 Neil Road
Reno, NY 8951 1
bellot~pc.com
. ;:
, .' . ./". ..
C 'i.~.r l:: li ~,til.cTeresa A. Wilia
:;. ~- ~.~ .-.
¡
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BEFORE mE PUBLIC UTILITIES COMMISSION OF NEVADA
2
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Investigati( n to anyz the strengts and weaksses )
of marnal cost of service studies, embeded cost ')
of service s udies, the reconcilaHon process and )
how they iii pact rae clas. )
)
SOUTER NEVADA WA 'fR AUTHORITY'S
COMMENS ON MARGINAL AND EMBEDDED COSTIG
PREPARD BY DR. DENNIS lESEAU
Die 06-05007
r'..~u
SOL THERN NEVADA WATER AUTHORI ("SNWA"). puruat to NAC chapter 703
and the Req lIest for Comments in ths daçket dated May 25. 2006, heby submits its Comments to the
Public Utili ies Commisson of Nevaa ("Commission') regaring cos of servce methodologies.
INODUCTION
The oooaUed "Arab oil embaro" of the early 19708 had a dramatic impact on the cost and
rates of elec trc utilties thrughout the world. In the U.S., ths embago, and the subsequent ru-up in
the pnces 0 most fossil fuels, chaged the histoncal predictailty of these utilties' growt rates
costs, and re "enue requiements.
The chages to the utilities' cost enviroiuent and sl to new and vared genertion
technologies had the effect of heightenig utilties', reguators', and customers' interests in
rateing. A major study in 1973 designed to carfully define cert raemang and rate setg
principles ci. Jminate in the National Association of Regulatory Utility Commioner' (''NARUC'')
pubIication I leetric Utiltv Cost Allocation Manual. In subseuent stdies conducted in the mid to late
i 970s, joint effort of regulators and publicly and pnvateJy own,ed electrc utilties ("te E~RI
studies") res lilted in several volums of costng and ratemag studies designed to captue the
changing an time-differentiated natue of the costs in th electrc utilty industr. These and
subseuent s :udies led many regulatory jusdctions including Nevad to begin endorsing rate tht
were in some degre based on economic or margina costs.
1111
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Ena tment of the national Public UtiUties Regulatory Policies Act of 1978 ("PUR A")
2 ifeant new reuireents on private utilties to compile and record cost and other data
3 necessa t better set customer rates.
4 Tension Between Embedded and Marginal Cost Raes
5 A culiar tenson has arsen, and remains today, between "accounting costs" and "economic
cost" for r temaking. These tenns are often describe as rates bas on embeded cost compared
on marginal coss.
ehate arse initially because of the statutory requirement to begin the ratemag proess
\U of revenues, the revenue requiement that does indeed reflect those costs expeted to
y the utilty. The revenue requirement wil generally reflect the normal accunting costs,
both capital and varable, pretly being incud by the utilty. These costs ar embedded. tht is,
averaed ov r the varous fuel and other expees, and over varous generating and other investent in
place, perh ps adjused or "noimalize" to the test year. These varous cost ca then be
fuctionaJi d. clasfied, and allocate to vaous customer classes on the bais of these actu
averaged or mbeded cost.
But, as economists often stss. historical cost-baed rates may not provide reasnable
cusomer rat s or "price signals." A price signal, it is argued, is necessar to provide incentive for
customers to consume according to the cost strctue facing the utilty in a going-forwar bass, not on
20 How ver, as is made apparent by the issues posed by the Commssion for consideration in this
21 docket, est ating forwar-looking cost requires. in some cass, signficant depa frm pas
22 recorded co ts, thereby reuiring assup1ions and forecass. The comments made her by the
23 Soutern Ne ada Water Authority do n01 attempt to define and explan the nuaces of the embeded
24 and marginal costing methods, but instead provide a context for the prsent metods of rateakng in
25 Nevada and, a gènera matter, to encourage a continuance of ratemaking tht is closely aligned with
26 vaid margin i cost estImates.
27 //11
28 /111
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A. ,Functionalizing Marginal and Embedded Cost to Revenue Reqrement
Fun tionaizin the total revenue requireen involves dividing the tota costs into genertion,
tranmissio:1, and distribution cost or fuons. Under embeded cost of servce, thes fuions ar
larely alre dy presribed under th FERC Uniform System of Acçounts. Since the embedded cost
process bei ins with th allowed revenue requireen setting cutomer rates accordg to these
fuctions, llthough complicate provides a somewhat strghtforar bas for coDeetng the
prescribed r venue requirment.
Mar dn cost of service stuies look to the cost of the new or nex increments of generatig
plants,. ssion, and vOllage-fferentiated distrbution seices. The margi or increenta
cost of ii generation, trsmission, and distrbution wil not, in geera, equal the utiUty's revenue
reuirement and therefore will have to be "reconciled" or sced upar or downwa to equal th
revenue req irement. Varous ecnomic theories and models demonste the suerior "effcienies"
of baving J ates reflect the presnt cost increments of geeration, trisson an distbution
facilties.
Th i 'ommssion ha for deces adopted marinal cost stdies tht fictionaize costs ma
up revenue equient accoring to maal cost that ar scaled or reconciled to averge or
embeded c( st. The SNW A stongly endorses ths pre and recommends th the Commisson
continue the DoHey.
B. Guidelines for Marginal Generat Unit
As di cusd above, cost fuctonaHzed to generation win, in a marginal cost stdy~ be bas
upon the nex increent of generating facilties. In practce the "next" generatig increment could be
a combustioJ tubine (now us in Nevada), a combined-cycle facilty, vaous tys of coal plants,
renewables, ~ nd refubishment to exist plants, among others.
The s gnificance of the choice of marinl genting unt is larely in the "classification" of
generation cuts ino deman (capacity) and ene. And. because differet custoer classes have
different usaBe patterns, aT "load factrs", different classifications of relative demd an energy costs
will bear diff rently on respectve cusmer classes' sha oftota revenue reirements.
1/11
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For nearly the decades ths Commission has adopted the "NERA Methd" of selectig th
2 mainal g nerating unit. TIs method essentially assumes tht. in equilibriwn, the next generng
3 unit will a natul gas-fired combuson tubine. Thus, generion cos have be clasifed in
4 Nevada to emand and energy on the basis of the relatve capacity and energy costs of a combustion
5 tubine.ger, more effcient generation technologies generally have a high capacity or demand
cost compo ent than does a cobuson tubine, but are mor fuel effcient (have a lower heat rate),
therby res ting in ful savings over which the higher additiona capacity costs ca be jusfied.
Linea and imlar matematcal progrng models have been develope to more precisely assess
the econo ics of what actuly should be th "next or incrementa generation unit." Th oriy
advantage r using the NERA Method is that it is relatively sÙDple to compute and is arguably
accurate en ugh for ratemaldng. Given the contuing rapid grwt of both Nev utilities, it may be
o consder or fuer stdy other available methods more consistent with the Specific
ctristics and load bales of Nevada's utilities.resure c
improvements are now available that allow more preise choices of "the next"
't. However, the modeling effort in suh esimates beome more çomplicated and may
not be wort the effort. 11 SNW A is avalable to elaborate on tls issue in upcoming workshops.
For t e present, the SNW A contiues to support the past Commission decisions to base rates on
the cost c1as ification reulting frm a combuson turbine marginal unt.
19 C.Usin Margi Cost of Servce to Set Genera Rates
20 As it ha in the past, the Commisson should continue to base cusmer clas rate on mana
21 cost-bad rates provide a clear, but not exact. dircton for providing apprriate cost
22 responsibil and price signs for making consupton decisions and invesents in ener effcient
23 equipmet. arinal cost-basd rates also provide the Commission with a meas of how equitable
24 are the rela ve cusmer class raes. When compard with resptive costs, cla rates allow
25 identification and gradua elimination of interclass subsidies.
26 Mar at cost.based rates aJso provide the means by wluch costs ca be seasonaly
27 Moving towad seaonally-differntiated BTER rates, for example. would reduce or
28 eed for Nevada electrc utiJties to fice the BTER swner revenue shortfals caused
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nt averaging of the high sumer fuel an purha power costs with th lower non-
suer fu i and purchased power costs. The SNW A rased this issue in Nevad Powe's recnt
DEAA c ,Docket 06-01016, and th Company proposed that the ise be fuer reviewed outide
Nev da Power's BTER marinal costs have be shown to var signficantly by seasn. Thse
costs shaul, therefore, be reflected in seona raes for pur of equity. effciency; and price
signals. A propriate seasonalization of the BTER would also reuce anomalies frm the averge
BTER. incl ding th need in cern instances to chage negative BTE rate to some clases be~use
these sae clases were set too high.
D. Filng of Embedded Cost Stues in the Generl Rate Case (QRÇ)
A fi ing of a detaled embeded cost stdy as suport for the pret Statement 0 cost studies
filed in a g neraJ rate case could be ver usefuL. Presntly. the functionaJized marnal costs ar
reflected in ine Compaies' Sttement O. However, the c~paabie fuctionaized embede costs.
from which the reconciled cost are derived. ar not ditly available. Includig ths ast of
embedded c st results in each general rate cas could provide a bas for checking the reasonableness
of the utility s embeded cost allocations.
E. Usefness of Embeed Cost Study
Emb ded cost studies could be usful to reconcile margial cost back to th overal gener
revenue req irment of the utilties. Furermore, th embeded cost studies could indicae the
reasnablen ss or not of the utilties' fuctionalization and clasifcation of the acl average or test
year coss.
1//
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CONCLUSION
S A continues to support the use of marginal costs in deriving the actl rates of customer
classes. A explained above, SNW A also believes there may be some value in having Nevada's
utilties dev lop and present embedded cost studies as a mean of comparson. SNWA is intered in
contiuig t paricipate in tls docket and requests that it be added to the service list.
RES ECTFLLY SUBMmED ths 17th day of July, 200.
BY;7~~FRE SCHMT
Hae Lae Peek Dennson and Howd
777 Ea Willam Street, Suite 200
Carson City, NY 89701
(775) 6846000
an
CHAES K. HAUSER
Genera Counsel, SNW A
1001 s. Valley View Blvd.
La Vegas, NV 89153
[phone]
Attorneys for the SOUTERN NEVADA
WATER AUTIORITY
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PROOF OF SERVICE
by cer that I maled th forgoing Souther Nevada Water Authority's Comments oD
d embedded Costin ii Docket 06~05007 by delivering via U.S.P.S. copies therof,
properly ad esed for mailing to the followig peons:
8ta Counsel
Public Utilties Commission of Nevada
1 15 E. Wiliam Stret
n City, NY 89701-3109
this 17ui day of July, 2006.
AJai Burenhaw
Public Utilities Commssion
i 0 1 Covention Ceter Dr., #250
Las Vega, NV 89109
aburs~e.stae.nv.us
a¿Aku)¿L.øo" )Tersa A. Wilias
::ODMA\P LRNODOS\S2493\J Page 7 of?
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2
BEFORE TH PUBLIC UTS COMMSION OF NEV JIA
~R~O~ åiv ~F~g
NOV.. 2 2Ð
DEN~AlE LANE PEEKISON AND HOWARD
3 Investigaon to review proesses, theories
and metQdologies tht may be us to
4 esablish just and reasonable rates in general
rate casesl
)
) Docket No. 05-7048
)
)
)
SOUTERN NEVADA WATE AUTORIS COMMNTS
REGARING RATE MAKG MECHANISMS
SQUTHERN NEVADA WATER AUlHORIY (USNW A''), pursant to NAC chapter 703
and the Rl'ques for Comments in this doket dated Augu 26, 200S, hereby submts its Comments to
the Publip Utilities Commssion of Nevada ("Coission'') regag prcesses theoes. and
methodolc¡gíes that may be used to establish just and reaonable rates in genera rate cases puant to
i
Secon 7 pfSente Bil ("S.Bj 238.
INTRODUCTON
oR August 26. 200S, the Public Utilties Commison of Neva ("Commsson") reuesed
comien~ on a number of raemakng issues designated as Docke No. 05-7048. The Commission
dicte tie comments to avoid generl dion of the issues so the intrduction below is limited
!
!
an prvided solely as a mean to intrduce the most coon teclmcaJ points contaied in the
specific q,estions rased in the Commision's Reques for Comments.
~ thre topics for comment raed by the Comsson ad the conceptually simple, but
!
practicall)j more diffcult. ta of matchig th utiltys likely test year revenues to its likely costs.!
IProperly ~onstrted either an adjused, nonnze hionca tes year or a nea-ten futue test ye
can be eqnally effective as a mea to match cost and reenue over the peod in which rates ar to
be in effeq. Factors affectig th acurcy of eith adjustd 1ustoricaJ or fut test ye ar:
· Pr~ision of the basline or becluark cost and revenue ination;I ,· Pntcision of the assumptions peraig to cusmer grwt investment grwt load grwth
and the incremental cost st and revenues associate with each; and
· Prqcisìon of and the lengt of projections or foreasts for individual cost and revenue
i
caigores.
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COMMENS ON SPECIIC COMMISSION TOPICS
1.Ratemaldg mechaDisms tbat will allow for the consideratiD of customer growth,
infrastcture growth and load grwth durig perods when rate ar to be iu effect
Ratemakng mechansms to deal with thes issues reuire a distiction betee fixed and
varable costs. Fixed costs and the reover of them in the face of customer, invetment, and loa
grwth reuir the estimation of mana or incrental cost and comparson of same to reenues.
Varable costs rere consdertion of a mechasm capable of varg or at least tracking and
accounting for these cost independeny of cusmer, investent and load grwth. The following
points discuss ths distition an the fact th the Commssion over tie has deat wen with thes
challenges.
. Use of a futur test period for setng base tarff energy rate (UBTER") costs and use of deferd
acounting for fuel and purchas power costs is suffcient to deal with grwt in fuel and
purchas power cost dur the perod when rates ar to be in effect No other mechanism is
necesar for that major rate component.
. Mechas to dea with cos and rae components other than fuel and purhad power, are
only neces if increnta cost is grter th increenal reenue for cuom and loa
growt investent durg the period rates will be in effect. If increnta cost is close to
incrental revenue, then grwt wil generate suffcient revenues to off th non-ful and
purha power costs caused by cusmer and load' growt. The evidence for Nevada
suggests tht increenta cost is not suffciently grater than incremental reenue so as to caue
any major eangs shortfal for Nevda Power. In fa the Commsson alady minmizes
the chance of tl occurg by allowing the use of an end-or-perod rate base and a subseuent
certfication peod for updating revenue reuirement.
24 . Even though incemental reenue and cost may be reasnably close for normal rate bas and
25 expense increaes caused by grwt, the lwnpy natu of soe utilty invesents such as
26 major power plant, trsmission Jines, and substation additions Inay cause futu revenue to fall
27 short of the incremental revenu~ requireent associated with fue rate base adc:itions. Those
28 Ulque types of capita addition are easily identified and able to be mitigated by such vehicles
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as AFC, CW, recording of regulato asse, etc. These mechansms have been us by
the Commison in the past when unusal and large capital adtions are under conction but
not ye providing serice to raepaye.
· If the Commssion detemnes that adtional meaur ar necesar to alleviate the potential
problems of growt the Commission could also consder a fonn of defer accounting and
cost rever for cost shortfals for major investents so tht the cost of delay in recover can
be regnze.
2. Mechanisms by which the State or Nevada ca trausitioD away from the historical
test year for purpes of ratemaking.
· The State of Nevad ha in plac anuiber of policies tht provide mea to avoid the stenes
of purly mstorical tes yea. The quetion is whethe these measur are adequate in light of
customer gr, cost esalaton and geer infttion. A major advantage of
using a histrical
tes yea as an intial point of depar and reference is th the costs an reenues ar known
and meaurble. Trantiong to a fully fi test ye relac known and measurable dat
for predctions of cost an reenues. Th rases a whole rage of chalenge includig the
ådditional step of prarg foreasts of all tet year cost and reue components for reenue
requireent detnation, an th issue of how fo mayor may not be used in cusmer
clas cost allocaion and rate deign Th incre the rate cae parcipaton costs of all
pares neces to evaluae the prictions of test year co and reenue. In addition, it
increes the num of contesed issues in rate cas becuse of use of prections rar th
actual data
· Whle it may see tht matching cost and reenues for the period rates wil be in efect is
extrely desrale, it is not always a necessar condtin. In fact, jf unt costs ar reonably
constant, raes set using an adjusted hiorica tes ye will be neay identical to raes baed on
a futu test yea. hi suh a cae, use of a historica test year win not caue eags shortfalls.
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Only mismatches betwee increenta cost and increntaJ reenue cause shortls. J And, whie
updated incrementaJ generon, trmisson and distbution sysem cost stdies ar always
necessar, past experence in Nevada ha Dot identified a sigrcant mismatch beee
incrmenta cost and revenue.
· The desird reult of using actul cost and reenue data and allowing a reasonable opportity
to ea the allowed rate of retm can be accomplished with adjusted historic numbers. Known,
meaable, and reasonably estle rae base additions and expense changes can be easily
reognized without rertng to us of a full futu test year. This is oft acomplished by
usng known and measurble costs with out of perod adjusmients. Revenue requirement
impacts of major rate base adtions and exense changes that can be prcted with a high
degree of ceraity ca be prfonned into tes yea revenue reuireent to reuce the chance of
eangs shortfalls. The State of Idao handles such matrs with out of perod adjustents.
The State onowa also uses a hybrid apprach that begis with a historical test ye and maks
adjustments for cerain major events prcted to occur afer the test perod.
3. Exmples of future test ye and/or other rorward-lookiDii rate mag
mecbanis.
· The State of Idao's use of out of perod adjustment for reasble known and meaable
major rae base and exse changes has, alrady bee referenced above. Ida incorprates
into the historical test ye res of opetions, the esmate rate ba and exense chages of
signficant and knwn item for a perod beyod the en of the tet year. Idao also require
utilities to include reenue generatig and expense reducing elements in tes year reults when
utilities elec to include out of period adjusents in rate cases.
· A recent sury condct for preentation to the Iowa Utities Board indicatd that
approximatey 30 states use a historical tes perod and an addition six sttes us a hybrd
approach beginning with a historical perod, but allowing adjusent with futu, preicted
i For exle, iflast year a bu produce 10 un at a cost, iD nlasonlc profit, ofS1OO and on th
basis deided to chae S 10 per unt for next ye, it would not suer an shls if th inem cos of adtion
unts wa 510, the sa as last ye. If it sold is unts in th ye, it would gener revemes,of$ISO and in cost of
$150. Ony ¡fth inl cos were substantlly grate th $10 per unt wo it sufer shrts.
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info.m'tion. A copy of the reort, which was prepar by the Iowa Utilities Board in response
to a reuet frm its state legislat, is ated as Exbit A.
· If the Commission detenne that it is approat to consider events occurg durng the
perod when rates wiJ be in effect the SN A recommens tht raer tha begiing with
fully forecased data and reults of operations th know and meaurble data frm a
histcal perod shoul be the bais for establishing benchmark cost and rcenue da
Histrical test year data could then be adjuste for major, known and accurely preictable
nea futu events such as is done in Ida and Iowa an seerl other staes tht us a hybrid
test yea.
RESPECTLY SUBMlD this 31st da,
BY:
THale Lane P Denon an How
m Eas William Str, Suite 200
Car City, NY 89701
[phone]Attomeyfor
SOU'NEADA WATER AUTORI
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PROOF OF SERVICE
2 I hery cerify that I maled the foregoing Soutcm Nevada Water Authrity's Comments
3 Regarng Rate Makng Mechansm in Doket 05-7048 by deliverg via U.S.P .S. copies tler~
4 propelyadsed for mailing to th followig pe:
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Staf Counl
Public Utilities Commsion of Nev
i 150 E. Willi Street
Caron City, NY 89701-3109
Ala Burenshaw
Public Utilities Commison
101 Convtion Center Drve Suite 250
La Vegas, NV 89109
Adrana Escobar-Chos. Conumer Advocate
Burau of Consumer Protecon
555 E. Wasn Ave., Suite 390
Las Vega NY 89101
Collee Rice
Nevada Power Company
6226 West Sahar Avenue
La Vega, Nev 89151
Date this 311t day of Octobe, 2005.
V:\LEOAL\Pl! 5cre: Commss\Dkat 0$708\Cmi.ooPage 6 of 6
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1
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BEFORE THE PUBLIC lmLITIS COMMSION OF NEVADA
3 Investigation to reiew processes, theories
and methodologies tht may be used to
4 establish just and reasonable rates in general
rate cases.
)
) Docket No. 05-7048
)
)
)
SOUTHRN NEVADA WATER AUTORITY'S SUPPLEMENTAL
COMMENTS REGARDING RATE MAKIG MECHAISMS
5
6
7
8 SOUTIERN NEVADA WATER AUTORITY ("SNWA"), pursuat to NAC chapter 703
9 and the Request for Comments in this docket dated December 15, 2005, hereby submits its
Supplemental Comments to the Public Utilties Commssion of Nevada ("Commission") regardig
processes, theories, and methodologies tht may be used to establish just and reasonable rates in
general rate cases puruant to Section 7 of Senate Bil ("S.B") 238.
INODUCTION
The Commission's proactive assessment of alternative ratemang mechaisms is timely in
light of Sierra Pacific Resources recent anouncement of its planed $3 billon investent in new
generation and transmission facilties, in addition to the recent purchases of the Silverhawk and Lenze
plants in southern Nevada and the Tracy Combined Cycle Project planed in nortern Nevada.
In light of these planed investments, the challenge facing the Commission is to continue
practices tht most accurately balance the utilties' revenues and costs over the perod in which rates
ar to be in effect. After decades of meetig astonishing grwt, primarily throug outside power
purchaes, the electrc utilties, paricularly Nevada Power Company, propose to more than double rate
base and trition to principally generating operating çompanes over the next few year. Thus, a
reassessment of the processes, theories, and methodologies currently used in Nevada is timely.
COMMENTS ON SPECIFIC COMMISSION TOPICS
In its comments of October 31, 2005 in ths docket, the SNWA stressed the importce of
distinguishig between fixed and variable cost considerations when assessing any of the alternative
test year ratemaking mecha'nisms (see SNW A, p. 2-3, 1. 7). The utilities' ratio of fixed to variable
costs appe as if it may change dramatically in the near futur. For puroses of ensurng cost
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recovery of variable costs in an accute and timely maer, the SNWA contiues to support the
present OEAA mechanism. The specific comments below pertaining to the four alternatives posed by
the Commssion in the second Request for Comments in this docket date December 15, 2005 are,
therefore, priarly aimed at fied cost, genera rate cae considertions.
With regard to the four alterntive ratemakng methodologies identified by the CommisiolL
SNW A offers the following observations:
I. Alterntive 1: Full future tes year
a. Ths methodology has the potential to reflect growt in cost of servce, but is also most
likely to misrepresent cost of service beause of the need to forecast every element of rate
base, expenses and load, and the reting uncertaity. Improvement in accuracy is
uncertin and unikely.
b. Ths alternative is the least cost effective because of the need for all pares to forecat and
evaluae ever component of cost of service and load. Increased cost and effort does not
necessarily increase effectiveness because of the anticipated increased uncertainty resuting
frm forecast error. Empirical evidence regaring the accuracy of key variables suh as
intere rates and prices is not encouraging.
c. Ths methodology incrases the burden and impose a fiscal impact on state and local
agencies (includig SNW A and others) because of the need to ftly evaluate all forecast
components of the futu test period. This methodology also necessitates paricipation in
extensive legislative and admistrtive proceedings required to develop the new
methodology. We also anticipate increased electrc rates for state and local agencies from
the fist application due to the uncertainty referred to above.
d. A ful futue test year requis the most changes in proceures and mechanisms because of
the need for a totaly new ratemaking mechansm and the need for more thorough anysis
of all rate case elements and forecats.
II. Altertive 2: Adjust 12 month historic test year for known and measurable data up to 7
months forwar.
a. Ths methodology has the potential to reflect growt because of adjustment for 7 months of
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da beond lle filig dae for known and meale ites. This meodlogy is Òios
likely to misrepresent cost of service than Alterntive 1 because it is based on 12 months of
actu data which wil reduce unceaity.
b. This alternative is generally cost effective because it is based on current and known
methods with a requirement to only anyz reasonably known and measurable chages for
7 months beyond the filing date.
c. This methodology is least likely to have any major impact on state and loca agencies
because of minma changes frm curnt ratemag mechansms. The mechansm merely
updates the curnt cercation process by several additiona month.
d. Since ths alternatve is similar to curnt raemakg with minima chages it would
require few changes in procedur and mechas. The most obvious problem would he
the need to identify new procedures for the timing of the updated inormation related to the
discovery and heang schedule. Some additiona stdas would have to be developed to
determine what is reasonably known and meaurable but yet to be experenced data (\,
Alternative 3: Adjust 12 month historic test year for known and measurble data for the peod ~
,
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when rates ar in effect. ,~ ::
a Ths methodology also has the potential to reflect growt, but requires less precise.-
~estimates for adjustments by virte of the indefinite time fre for" . . . the period rates ar
in effect. II The more distat the time fre, the more liely there will be a cost/revenue
discrepancy either for shaholders or customers. If the interal between rate ca filings is
short, ths concern lessens.
h. Ths alternative is cost ineffective compar with Alterntives 2 and 4, but is probably
more cost effective thn Alternative 1.
c. The cost impac on state and local agencies is likely to be less than Alternative 1 because
the uncertinty of solely futue forecasts are tempered with a base of historic informtion.
However, the need to review and evaluate a ful historic perod and a ful futue period may
be more costly for review and wil clealy iiicrease costs for rate case parcipation over
Alternve 2.
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d. Ths alterntive requires some additiona framework and gudelines to determine the
"perod rates are in effect" (Le. which porton of the one or two yea rates rema in effect)
and how to identify future data which is "reasonably known and measurable".
iv. Alternative 4: Most recent 12 months with adjustments up to period rates in effect.
a-d. The SNW A's comments on ths methodology are the same as for Alterative 2 above.
Although this method is called a "historic test year" and Alterntive 2 is caed a "futu te
year", the altertive methodologies ar identical in the Commssion's notice. Alternative 2
calls for adjusments up to seven month beyond the filing date which, given the suspension
peod of 2 1 0 days now contaied at NRS 704.110, is the same perod as the point up toC i/when new rates will be placed into effect as described in Alternative 4. If the SOmmssion
intended to solicit comments on another period different frm Alterntive 2, SNW A wil be
glad to provide adtional comments at the workshop on February 7, 2006.
In response to topic 2 requesting an opinion on the legislation, procedurs, and mechansm
necessar to authorize and implement the altertive ratemang methodology alternatives, the SNW A
offers the following genera opinions. SN A has not offered specific sttutory or reguation lague
for any of the above alternatives at ths point in the proceeding because SNW A prefers the stat quo
methodology which has been in place for a substantial period of time and requires no chages to
curent law.
If the Commssion does adopt any of the alternatives above (except for Alternative 2 applied to
natura gas utilties, given the statutory change already adopted by the 2005 Nevad Legislatue in S.B.
256), NR 704.110 must be rewritten because it cuently limits utilities to an historic test period
which may only be updated with information up to six months afer the end of that period. If any form
of futue test year is desired, a substantial rewrte of NRS 704. i i 0 will be required. If only an update
to the historic period is made several months beyond the curent system or up to the tie rates take
effect, then only a smaller revision to NRS 704.110, as it curently reads, is required. If any of the
alternatives identified by the Commission in ths docket ar to be implemented, a lengty ruemakg
to rewrte the schedules and filing requiments in NAC Chapter 703.2201, et seq. wil be necessar.
28 II11
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CONCLUSION
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Growt ha the potential to complicate the effort to set rates that accurately reflect cost of
service. As discussed in more detal in the prior SNW A comments, the relationship between
'5generation and trmission incremental costs and incremental revenues (rates) determine.- whether
grwt is revenue or cost enhcing. The chances of this happening in Nevada !Uay be reuced
because of the use of essentially a futu test period for fuel cost. For example, it is clear frm recent
DEAA filings that use of a future test year doesn't necessarly reflect futu cost of servce, otherwse
DEAA balances would be smal, which they are not. We should not assume tht a more'extended
futu test year applied in a general rate proceedig will accommodate growt and more accurtely
reflect cost of service simply by basing rates on forecasts of all rate case elements, or that growth wil
necessarily have a predictable positive or negative impact on earings.
In Nevada there is no clear evidence, aside from fuel and purchaed power cost (which are
already based on a futu test year), that incremental cost is grwing considerably more rapidly th
incrementa revenue. It is not clear at al tht rate payers or shaeholders would benefit by basing rates
on a fuly forecasted cost of service because that would dramatically increase all paries' costs of
evaluating rate cass and would introduce a grat deal more Wlcei1inty in the process which may not
even reflect growt any more acurately than an- historic tes year.
Given the added cost, the grater uncernty, and the added buren on the process, it seems
much more cost effective to begin with the most recent historic test yea data available and then mae
adjusents for major, reasonably known, and measable rate case elements for a short period of time
into the futue. This can be accomplished with minima chages to curent processes and procedurs,
miimal added burden on all rate case parcipats, and at min added cost. In addition, sice
these major known and measurable future events are the most liely to cause futu cost of serice to
deviate frm curent cost of service, growth is adequately accommodated. To the extent that major
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plat addtions may fall outside the test year, the electrc utilties' should consider the more effcient
coure of filing timelier rate cases, since they are only obligated to fie every two year but are entitled
to file more frequently in interm periods if necessa.
RESPECTFLL Y SUBMITD this 17th day of Januar, 2006.
BY:
FRED SCHMIDT
Hae Lane Peek Dennson and Howard
777 Eat Wiliam Stret Suite 200
Carson City, NY 89701
[phone]
Attorney for
SOUTHERN NEVADA WATE AUTHORITY
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PROOF OF SERVICE
I herby certfy that I mailed the foregoing Southern Nevada Water Authority's Supplementa
Comments Regardin Rate Mang Mechansms in Docket 05-7048 by delivering via U.S.P.S. copies
thereof, properly addrssed for maling to the followig persons:
Staff Counsel
Public Utilities Commssion of Nevada
1150 E. Wiliam Street
Caron City, NY 89701-3109
Alain Burenshaw
Public Utiities Commission
101 Convention Center Drive, Suite 250
La Vegas, NV 89109
Ernext Figueroa
Burau of Conser Protetion
555 E. Wasington Ave., Suite 3900
La Vegas, NV 89101
edfiguo(fag.state.nv. us
Chad Duval
Moss Adams LLP
3121 W. March lane, Ste. 100
Stockton, CA 95219
cha.duval(fmossdams.com
Connie Silveir
Sierr Pacific Power Company
6100 Neil Road
Reno, NY 89511
csilveira(fsppc.com
Dan Foley
SBC Nevada Bell General Attorney
P.O. Box i 1010
645 E. Plumb Lane, Room B132
Reno, NV 89520
Debra Jacobson
Southwest Gas Corp.
5241 Spring Mountai Road
Las Vegas, NV 89150
Debra.J acobson(fswgas.com
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1 Eric Heath
2
Sprit of Nevada
330 S. Valley View Boulevar
3 Las Vegas, NV 89107
eric.s.heath~spritcom
4
Karen Petersn
5 Allson, Mackenze, et al.
P.O. Box 646
6 Cason City, NV 89702
7 kpterson(?llsonmackenzie.com
8 Kathleen Drakulich
Kumer Kaempfer, et aL.
9 5250 S. Virginia Stret, Suite 220
io 10
Reno, NV 89520
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11 Linda Stinar+' 0... t-
Sprit of Nevada
1 =i 0\1200 00.: \l 330 S. Valley View Blvd.
i: G 'g 13 Las Vegas, NV 89107,2 ~ ~
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14
Linda.c.stiar(ßl.sprint.com
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15 Shawn Elicegui.l-'"ßr.U Lionel Sawyer & Collin
~~ g 16 1100 Ban of America PlazaI) 0 ~50 W. Libery Stret, Suite 1100
3~u 17 Reno, NY 89501
v t-selicegu~lioneisawyer.com
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19 Steve Luhertozzi
Sky Rach Watr Service Corp.
20 2235 Sanders Rd.
Nortbrook, IL 60062
21
22
Timothy Shuba
Goodwi Procter LLP
23 901 New York Ave. N.W.
WashingDn, D.C. 20001
24 tshuba(goodwinprocter.com
25 Dated this i 7th day of Januar, 2006.
26
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BEFORE THE PUBLIC UTLmES COMMSSION OF NEVADA
Investigation to review processes, theories
and metodologies tht may be used to
esblish just and reonable rates in genera
rate cases.
)
) Docket No. 05-7048
)
)
)
,
v:)J/ý
SOUTRN NEVADA WATER AUTORITY'S REPLY
COMMENTS REGARDING RATE MAG MECHAISMS
SOUTHERN NEVADA WATER AUTHORI ("SNWA"), pursuant to NAC chapter 703
and the Request for Comments in ths docket date December 15, 2005, hereby submts its Reply
Comments to the Public Utilties Commssion of Nevada ("Coimission") regang processes,
theories, and methodologies that may be used to establish jus and reasonable rate in general rate
caes puruant to Section 7 of Senate Bil ("S.B") 238.
INTRODUCTION
The reply comments contained herein ar intended to synthesize the Southern Nevada Water
Authority's ("SNW A") general position with positions on rate mag mechansms presented by other
pares on Januar 17, 2006. As made clear by the sum and substace of the comments to date, a
single, clea, specific application of a test year methodology wil be diffcult to attin.
The SNW A noneteless continues to support the general objectve espoused by it, the utilties,
and indirectly by other pares that the test year constrt should be intende to strke a balance
beten costs and revenues over the near term. The SNW A ha offered its view on test year
parculars designed to balance costs and revenues in its previous two rounds ofwrtten comments.
Whle the comments reveal a clea division between the recommendations of the utilities and
other pares on the value of the four alternatives designted by this Commssion, there appeas to be
consens tht a fuly forecasted test yea (Alternative 1) is the most costly and most contentious of the
alterntives. It is most costly because it would represent a completely new forecast paradigm for
estimating costs and the estimated test year costs would undoubtedly be higher th test year costs
estimated under Alternatves 2-4. Having said this, the SNW A is also of the opiiúon that a completely
28 III1
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Draft SNW A 1130/06 Test Year Comments
INTRODUCTION
The reply conuents contained herein are intended to synthesize the Southern
Nevada Water Authority's general position on the issues and positions on rate makg
mechanisms presented by paries on January 17,2006. As made clear by the su and
substance of the comments to date, a single, clear specific application of a test year
methodOlOgy wil be diffcult to atin.
The SNW A nonetheless contiues to support the general objective espoused by it,
the utilities and indiectly by other partes, that. the test year consruct should be intended
to stre a balance between costs and revenues over the near ter. The SNW A has
offered its view on test year partculars designed to balance costs and reenues in its
previous two rounds of wrtten comments.
While the comments reveal a clear division between the recommendations of the
utilties and other pares on the value of the 4 alternatives designated by this
Commission, there appeared to be consensus tht a fully forecast test year (Alternative 1)
is the most costly and most contentions of the alternatives. It is most costly because it
would represent a completely new forecast paradigm for estimating costs and the
estimated test year costs would widoubtedIy be higher th test year costs estimated
under Alternatives 2-4. Having said this, the SNWA is also of the opinion that a
completely historic and wiadjusted test year is also likely to be an inaccurate mechasm
if near term significant cost events are occurng.
ABIDING RATE MAG PRINCIPLES
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1 historic and unadjusted test year is also likely to be an inaccurate mechanism if nea ter significant
2 cost events are about to occur.
ABIDING RATE MAKIG PRICIPLES
The SNW A proposes that ths Commssion consider the following principles in assessing
alterntives to test year mechanisms:
· Both fully historic and fully futu test year mechanisms ar most inaccurate in times of rapid
growt and growth events (such as major capital investment).
· Modified, forward looking historical-based tes years are most accurate in periods of rapid
growt and growth events, so long as rate cases are fied timely and regularly, and updates are
made for both costs and revenues.
For these reasns, the SNWA strongly recommends that the Commission, utilties, and other
pares work cooperatively and intentionally to devise a te year mechanism based upon historical
data, but adjusted for near-term likely events beyond the rate case test year. The SNWA is ready,
wiling, and able to work with the Commission and other pares to define the appropriate adjustment
period and the pareters for recognzig likely events.
CONCLUSION
The SNW A maes ths recommendation largely becaus of the significant chages and
challenges facing the Commssion, utilties and rate payers in Nevada. As discussed in the SNW A
supplemental comments, the electric utilties' recently anounced plans to expend $3 bilion for new
generation and trsmission facilties, over and above the Silverhawk, Lenzie and Tracy plants alread
underway, is likely to drastically alter the present cost structue of those electric utilties. With
unprecedented changes in costs, especially the changing mtío of fixed to variable costs, the SNWA
C:\Docuinents and ,Settings\Dennis Peseau\Desktop\HLRNODOCS-#51 0991-v I-SNW A_Reply- Comments_Dkt_OS-7048Juture _leslj'ar.DOC
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The SNW A proposes that this Commission consider the following priciples in
assessing alternatives to test year mechanisms:
· Both fuly historic and fully futue test year mechansms ar most inaccurate in
times of rapid growt and growt events (such as major caital investment)
· Modified, forward looking historical-bas test years are most accurate in periods
of rapid growt and growth events, so long as rate cases are filed timely.
For these reasons, the SNW A strongly recommends that the Commssion, utilities and
other pares work cooperatively and intentionaly to devise a test year mechasm
based upon historical data, but adjusted for likely events 7-12 months beyond the rate
case filing data.
CONCLUDING REMARKS
The SNWA makes this recommendation largely because of the significant
changes and challenges facing the Commission, utilities and rate payers in Nevada.
As discussed in the SNW A supplementa comments, the utilties recently anounced
plan to expend $3 bilion for new generation and trmission facilties, over and
above the Silverhawk, Lenzie and Tracy plants already underway will drastically alter
the utilities preent cost strctue. With unprecedented changes in costs, especially
the chaging ratio of fixed to variable costs, it is best to look at rea and anticipated
rather than forecast changes. i
i In its prior comments the SNW A has stresse the need to focus on incremental generation, trasmission
and related costs in assessing the balance of costs and revenues. References to year experiences of the fewother jurisdictions attempting future test years is unlikely to be valuable under the circmstances facing
growth in Nevada.
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1 believes it is best to look at real and anticipated information in conjunction with actu experience,
2 rather than rely solely on forecasted or estimated changes. i
3 RESPECTFULL Y SUBMITTED thi 30th day of Januar, 2006.
4
5 BY:
FR SCHMIDT
Hale Lane Peek Dennson and Howad
777 East Willam Street, Suite 200
Caron City, NV 89701
[phone]
Attorney for
SOUTRN NEVADA WA 'fR AUTHORITY
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i In its prior comments tlie SNW A has recognize and stressed the need to focus on incremental generation,
transmission, and related costs in assessing the balance of costs and revenues. References to the experiences of the few
other jurisdictions which employ futur test year methodology is unlikely to be valuable to that focus under the unique
circumstances facing growt in Nevaa. It is also worrisome for customers to note that Nevada's neighbor, California,
which has implemented a full future test year for ratemakng, according to the data submitted by Sierra PacìfclNevaci
Power clearly has the highest electric utility rates in the Western United States. As Nevada has learned from tlie Western
Energy Crisis during the last decade, following California's lead in utilty regulation, while appealing in theoiy,can prve
VerY costly,
C:\Documeif iid Settings\Dennis Peseaiiktop\HLRNOOOCS-#S I 0991-v I-SNW A_Reply_ Comments_Dkt_OS- 7048 Juiunuest"'ca.DOC
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PROOF OF SERVICE2
3
I hereby certfy tht I mailed the foregoing Southern Nevada Water Authority's Supplemental
Comments Regarding Rate Making Mechansms in Docket 05.7048 by deliverig via U.S.P.S.copies4
thereof, properly addressed for mailing to the following persons:
5
Willam Staey Alaina Burenshaw6Public Utilties Commssion of Nevada Public Utilties Commission
7 i 150 E. Wiliam Stret 101 Convention Center Dr., #250
Caron City, NY 89701-3109 Las Vegas, NV 89109
8 Ernext Figueroa Chad Duval
9 Burau of Consumer Protection Moss Adams LLP
~o
555 E. Washington Ave., Suite 3900 3121 W. March Lane, Ste. 100
10 Las Vegas, NY 89101 Stockton,.CA 95219floedgur~ag.state.nv. us chad.duval~mossadam.comON..1llI!o... t"COD1e Silveira Dan Foley ¡ :: Ct 12i: 00 Sierra Pacific Power Company SBC Nevada Bell General Attorneyg t'~13 6100 Neil Road P.O. Box 11010(Ig (1.~ ;:Reno, NV 89511 645 E. Plumb Lane, Room B132i: 4)
o eZ 14 csilveira~sppc.com Reno, NY 89520O.~ t:
15.i-...Debra Jacobson Eric Heath0;' Uo~ i:
Southwest Gas Corp.Sprint of Nevada ii .. 0 16OJ fI ~5241 Spring Mountain Road 330 S. Valley View Boulevard~ PJ U 17 Las Vegas, NV 89150 Las Vegas, NV 89107.. t"o t"Debra.Jacobsoni§swgas.com eric.s.heath~sprint.com'ã t"18::Karen Peterson Kathleen Drakulich19Allison, Mackenzie, et al.Kumer Kaempfer, et al.
20 P.O. Box 646 5250 S. Virginia Street, Suite 220
Carson City, NY 89702 Reno, NY 89520
21 kpeterson~aIlsonmackenzie.com kdrakulic~br.com
22 Linda Stinar Shawn Elicegui
23 Sprint of Nevada Lionel Sawyer & Collin
330 S. Valley View Blvd.1 100 Ban of America Plaz
24 Las Vegas, NV 89107 50 W. Libert Stret, Suite 1100Linda.c.stinar~aii.sprint.com Reno, NV 89501
25 selicegui~lionelsawyer.com
26
27
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C:\Documents and Sellings\Dennis Peseau\Deslop\HLRNODOCS4tS i 091.v I.SN:v A_Reply- Comments_ Dkt_OS-7048Juture_tetyear.DO
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Steve Lubertozzi
2 Sky Ranch Water Service Corp.
3 2235 Sanders Rd.
Northbrook, IL 60062
4
Timothy Shuba
5 Goodwin Procter LLP
901 New York Ave. N.W.
6 Wasington, D.C. 20001
7 tshuba(fgoodwinprocter.com
8 Dated ths 30th day of Januar, 2006.
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::ODMA'lClOCODOIS2:i86il
ATRNEYS AT LAW
m Ea Wi6a Sl I Silc 20 I Qi. City. Newcl 89701T.lopho (15) fill I fainl. (77S) 6801
..ow .lleliam
Marh 7, 2006
Cryta Jackson'
Commssion Secretar
lISO E. Wiliam Street
Caron City, NV 89701
RE: SNWA DIRCT TESTIMONY DOCKET NO. 06.01016
Dear Ms. Jackson;
Please accept for filing the enclosed original and nine copies of the Direct
Testimony of Dennis Pesau on behalf of SNW A in Docket No. 06-01016.
Should you have any questions regaing this fiing, plêae contact me at (775)
684..OOO.
:Zk~~
Fred Schmidt, Esq.
FJS:taw
Enclosu
cc: Paries of Record
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BEFORE THE PUBUC UTILITIES COMMISSION OF NEVADA
Docket No. 06-01016
Direct Testimony of
Dennis E. Peseu
on behalf of
Southern Nevada Water Authority
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Dennis E. Peseau. My business address is 1500 libert Street S.E.,
Suite 250. .Salem, Oreon 97302.
BY WHOM AND IN WHAT CAPACIT ARE YOU EMPLOYED?
1 am President of Utility Resources, Inc. The finn consults on a numbe of economic,
financial, and engineering matrs for vanous private and public entities.
'Q_":".o - 'J
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING? en "~i::::: , .n. ,.~ .~.=
I am testifng on behalf of the Southem Nevada Water Authority ("SNW~ll) :~n"t its, ...;:.... ir: .constituent members. '-0 : :,':"e-.. ¡,-".'M.. .; ;:
~ :~1- ..,
DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUN A~D
EXPERIENCE?
Yes.
WHAT IS THE SUBJECT OF YOUR TESTIMONY?
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The subject of my teimony pertins to both the level and the design of Nevada
Powr Company's ("Company") proposed Base Tariff Energy Rate t'BTER") In these
proceedings. Docket No. 06-10106. The Company's Application in these prodings
seeks a combined reidential and non-reidential BTER designed to recover an
annualized revenue increase of $264.1 milion. which includes both BTER and OEM
synchronization. In its subsequent BTER update in this docket, filed February 241
. 2006, the Company reduced its request to $137.7 milion. The former requeste
increase of $264.1 mimon is based on Nevada Power's use of a December 28, 2005
price forecast. The update to the BTER was based on a forecast made only a month
later, January 27,2006. This large reduction in requested revenue demonstrates the
significant impacts and vanaton inherent in even near-term market energy price
forecats.
WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
The purpose of my testmony is twfold:
1. To demonstrate that implementation of a seasonal BTER, instead of an annual
BTER, is at present necessary to relieve customers of exces carrying charges,
to relieve Nevada Powr of its chronic summer BTER revenue shortlls, and to
reuce the excessive debt financing and credit rating stress promoted by an
annualized BTER; and
2. To demonstrate that the continued decrease in forecast energy prices from the
time of the Company's BTER update will provide an easy transition to a
seasonally~based BTER.
WHAT CONCLUSIONS AND RECOMMENDATIONS DO YOU MAKE?
My conclusions lead to the following recommendations:
1. A seasonally-based BTER that tracks Nevada Power's higher summer fuel and
purcased power costs, and lower non-summer costs. should be implemented.
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2. A seasonally-based BTER would provide customers with price that more
accurately reflect their consumption decisions, and therefore promote beter
conservation decisions at times when costs are high.
3. A seasonally-based BTER, implemented in time for this summer season, would
reduce or eíiminate Nevada Powers need for an additional $200 milion in debt
financing this summer.
4. A seasonally-based BTER would permanently reduce a significant amount of
debt necesary to finance the prdictble summer BTER revenue shortalls.
$. The reduction in financing facilitted by a sesonally-based BTER would relieve
customers of milions of dollars in additional carryng charges.
6. The Commission should leave the annual average BTER reflected in current
rates essentially unchanged for the next year, because fuel and purchased
power prices have dropped dramatically since Nevada Power's February 24,
2006 update. However, by implementing a seasonally based summer BTER,
the rate to be implemented commencing May 1, 2006 should be about
$O.062/k, or about the same rate reflected in the February 24,2006 update
filing by Nevada Power.
PRESENT BTER STRUCTURE
WHAT 15 THE ISSUE WITH RESPECT TO THE PRESENT STRUCTURE OF THE
BTER?
The first issue I raIse is the same whether the BTER Is calculated using either a set of
his10ncal or forecasted data. As amended NAC 704.130 now provides, Nevada Power
has offered both historicl and forecasted prices. In either case, th BTER is
estimated by averaging monthly price Information into a single rate for each of the
reidential and non.residential categories.
T~~. ay~ra9~s. reflec a compression .of high prices of fuel and purchased power
faced and paid by Nevada Power in the summer, wih the lower price$ paid in shoulder
and winter months. An average BTER is not designed to cover the Company's high
::ODMA\PCOOCS\LROOOCS\2.\1 Page 3
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2. A seasonally-based BTER would provide customers with prices that more
accurately reflect their consumption decisions, and therefore promote better
conservation decisions at times when cots are high.
3. A seasonally-base BTER. implemented in time for this summer season, would
reduce or éíiminate Nevada Powts need for an additional $200 milion in debt
financing this summer.
4. A seasonally-based BTER would permanently reduce a significant amount of
debt necesary to finance the predictble summer BTER revenue shortalls.
5. The reduction in financing facilitted by a seasonally-based BTER would relieve
customers of milions of dollars in additional carrying charges.
6. The Commission should leave the annual average BTER reflecte in currnt
rates essentially unchanged for the next year, because fuel and purchased
power prices have dropped dramatically since Nevada Powets February 24,
2006 update. However, by implementing a seasnally based summer BTER.
the rate to be implemented commencing May 1, 2006 should be abut
$O.062/kwh, or about the same rate refleced in the February 24,2006 update
filing by Nevada Power.
PRESENT BTER STRUCTURE
WHA.T IS THE ISSUE WITH RESPECT TO THE PRESENT STRUCTURE OF THE
BTER?
The first issue I raise is the same wheher the BTER is calculated using either a set of
historical or forecasted data. As amended NAC 704.130 now provides, Nevada Power
has ofred both historical and forecasted prices. In either ea. the BTER is
estimated by averaging monthly price information into a single rate for each of the
residential and non-residential categories.
The averages reflect a compression of high price of fuel and purchased power
faced and paid by Nevada Power in the summer, wi the lowe prices paid in shoulder
and winter months. An average BTER is not designe to cover the Company's high
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2. A seasonally-based BTER would provide customers with prics that more
accurately reflect their consumption decision, and therefore promote better
conservation decisions at times when costs are high.
3. A seasonally-based BTER. implemented in time for this summer season, would
reduce or éÎiminate Nevada Powets need for an additional $200 milion in debt
financing this summer.
4. A seasonally-based BTER would permanently reduce a significant amount of
debt necessary to finance the predictable summer BTER revenue shortalls.
5. The reduction in financing faciltated by a seasonally-based BTER would relieve
customers of milions of dollars in- additional carrying charges.
6. The Commission should leave the annual average BTER reflected in current
rate essentially unchanged for the next year, because fuel and purchased
'power prices have dropped dramatically since Nevada Power's February 24,
2006 update. However, by implementing a seasonally based sumrner BTER.
the rate to be implemented commencing, May 1, 2006 should be about
$O.062/kw, or about the same rate refleced in the February 24, 2006 updat
filing by Nevada Power.
PRESENT BTER STRUCTURE
WHAT 1S THE ISSUE WITH RESPECT TO THE PRESENT STRUCTURE OF THE
BTER?
The first issue I raise is the same whher the BTER is calculated using either a set of
historical or forested data. As amended NAC 704.130 now provides, Nevada Power
has offered both historical and forecasted prices. In either case, the BTER is
estimated by averaging monthly price information into a single rate for each of the
residential and non-residential calegones.
The averages reflec a compressioJl of high prices of fuel and purchased power
faced and paid by Nevada Power in the summer, with the lower prices paid in shoulder
and winter months. An average BTER is not designe to cover the Company's high
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summer cots, and reuires at leat short-term financing to pay for such costs.
Nevada Power explains in several places in its Appliction and testimony in this case,
and in it Docket No. 06.01018 Application, that even if it requested BTER is granted
In its entirety, it expcts to experience accrued deferrals of up to $200 millon.
The specifc issue i am raising is the inabilty of the BTER, if estimated and set
at an average level over the entire test year, to track the out-of.pocket costs for fuel
and purchased power incurred by the Comp?lny.
SEASONAL BTER
WHAT DO YOU PROPOSe TO REPLACE THE CURRENT METHOD OF
ESTIMATING AND SETING THE BTER ON AN AVERAGE ANNUAL BASIS?
i propose that the monthly calculations that are currently developed for the BTER not
be reuce to a single annual figure, but Instead be set and charged on a seasonal
basis. The summer BTER would be based on the forecast prices for the months June
through September, while the non.summer BTER would be baed on the forecst
pr\ces for the month of October through May. ,
WHY DO YOU MAKE THIS PROPOSAL?
First and foremost, as an economist who has worked before this Commission for many
years, l recognize that whenever possible and practical rates to customers have been
based on costs, particularly marginal costs. A seasonally-based BTER would promote
an alignment of rates with the pronounced seasonality of fuel and purcase powr
costs.
Under the existing annual BTER, customers have litle or no knowledge of the '
prevalence of high summer fuel and purchased power costs as compared to non-
summer months, nor do they have the ~bilit to shape or avoid consumption that can. ",
reduc; their power bils. All customers now pay too little for power consumed in
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summer costs, and requires at least short-term financing to pay for such co.
Nevada Power explains in several places in its Application and testimony in this ea$e,
and in its Docket No. 06-01018 Application, that even if it requested BTER is grante
In its entirety, it expect to experience accrued deferrls of up to $200 millon.
The specifc issue I am raising is the inabilit of the BTER, if estimate and set
at an average level over the entire test year, to track the out..f-pocket costs for fuel
and purchased power incurred by the Comp?lny.
SEASONAL BTER
WHAT DO YOU PROPOE TO REPLACE THE CURRENT METHOD OF
ESTIMATING AND SETNG THE BTER ON AN AVERAGE ANNUAL BASIS?
I propose that the monthly calculations that are currently develope for the BTER not
be reduce to a single annual figure, but instead be set and charged on a seasonal
basis. The summer BTER would be based on the forecast prices for the months June
through September, while the non-summer BTER wouJd be based on the forecast
prices for the months of October through May.
WHY 00 YOU MAKE THIS PROPOSAL?
First and foremost, as an economist who has worked before thrs Commission for many
years, I recognize that whenever possible and practical rates to customers have bee
based on costs. particularly marginal costs. A seasonally-based BTER would promote
an alignment of rates with the pronounced seasonalit of fuel and purcased por
costs.
Under the existing annual BTERt customers have little or no knowedge of the
prevalence of high summer fuel and purchased powe costs as compared to non-
summer months, nor do they have the abilit to shape or avod consumption that can
reduce their power bils. All customers now pay too little for power consumed in
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summer months and to much for por consumed the rest of the year. A seasonally-
based BTER promotes efcient usage decisions, as well as economic conservation.
WHAT OTHER BENEFITS DERIVE FROM THE REDESIGN OF THE ANNUAL
BTER TO A SEASONALL V-BASED BTER?
The corollary to the annual BTER-induce customer un.derpayment of the high
summer months' fuel and purchase power cots is the shortall of revenues collected
by Nevada Power in the summer months. The Company speaks to this revenue
shortll throughout its filing (Applicaion, p. 4, lines 18.20; p. 17, i. 25-27; Yackira '
Direct, p. 1~, i. 11-21; and in its Application in Docket 06..1018, p. 12, 1. 5-18).
Depending on a number of factors, Nevada Power indicates ~e need for up to $200
millon in additional financing to cover accumulatd and prospecve BTER revenue
shortalls. Seasonalizng the BTER to track seasonal fu~1 and purchased power costs
should eliminate the nee for this financing by providing substantial additonal revenue
and cash floW to pay for higher fuel and purchased power costs during summer
monts.
WOULD THE SEASONALLY-BASED BYER POSITIVELY AFFECT NEVADA
POWER'S FINANCIAL FUNDAMENTALS?
Yes. As I indicated, the seasonally.based BTER Improve the Company's cah ftow
and repuce the need for substantial new debt. As many have noted in recent years,
Nevada Power and Its parent, Sierr Pacific Resoürce, have been excessivly debt
leveraged for some time. In my opinion. any and all positive steps toward reducIng the
Company's need for debt would have favorable consequences for Nevada Powr's
customers, shareholderS, and bondholders, Credit rating agencies such as Moody's
and Standard & Poor's have implored the Company to improve the important debt-
equity ratio. The net efect of a more balanced capital structre is a lower cost of
capital through lower debt costs.
:;ODMA1PCOOCSLRNOOOCSI522781..Page 5
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WHAT OTHER BENEFITS WOULD ACCOMPANY THE IMPLEMENTATION OF A
SEASONAllY-BASED BTER?
As noted in the tetimony of Company winess Mr. Yackira, p. 10,1. 16-17, substantial
carring charges of $23.4 millon are included in DEM5 balances. In addition, Period
6 deferr balances could rech $178 milion under an annualized average BTER. A
seasonally-based BTER designed to avert the summer months under recovery would
minimize deferred balance and save customers the 9.03 percent carring charge rate
whic is applied to these balances. If the entire $200 millon in new debt requested in
Docket 06-01018 is avoided, the seasonally-basé" BTER could minimize or eliminate
1innualized carring charges of up to $18 milion.
CALCULATING A SEASONALL Y-BASED BTER
HAVE YOU CALCULATED A SEASONALLY-BASED BTER BASED ON NEVADA
POWER'S FEBRUARY 24, 2006 FlUNG?
Yes. My Exhibit DEP-1 summarizes Nevada Power's February 24, 2006 updated
price forecas and associated annual BTER. This exhibit then seasonally
differentiates the Company's revied annual BTER of $0.063253 into seasonal
components.
PLEASE EXPLAIN.
Exhibit DEP-1 distinguishes by month, by seaso. and by test year the fuel and
purchased costs forecast by the Company. For example, dividing the total test year
sales of 20,243,888 mwhs into th net retail cost (after removing the FERC allocation)
of $1,277,325,000, we obtain Nevada Powets requested annual BTER of
$O.06325/kwh, bere adjustment for Hoover B. To seasonalize this annual BTER, the
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forecast of summer and winter fuel and purchased power costs is divided by the
relate forecast energ sales.
The Hoover B adjustment of approximately $7,177,000 in favor of the
residential class result in a net reuction of $.00083 for reidential, and a net additn
of $.00062 for non-residentiL. The final seasonal BTERs based on Nevada Power's
February 24, 2006 update are shown at the bottom of Exhibit DEP~1, $0.06242 for
residential and $0.06387 for non-residential.
ARE YOU RECOMMENDING THAT NEVADA POWER'S PROPOSED ANNUAL
BTER LEVEL BE ADOPTED AND THEN SEASONALIZED IN THESE
PROCEEDINGS?
No.
WHY NOT?
After I noticed the significant decrease in Nevada Power's proosed BTER from its
January 17, 2006 filing forecast to it February 24, 2006 revise forecast, I further
update the fuel and purchased power forecast to March 1, 2006. The seasonally-
based BTER i develop below and recommend in these proceedings is calculated with
this later, more current forecast.
Aftr i note that Nevada Power1s original January 17, 2006 BTER filing
proposed to collec $264.1 milion in revenues, the Company's update of February 24,
2006 reduce its request to $137.7 millon, a reduction of over $128 milion.
BEFORE YOU EXPLAIN YOUR REVISED SEASONALLY~BASED BTER
CALCULATIONS BASED ON YOUR MARCH 1 FORECAST, PLEASE ÉXPLAIN
HOW YOUR PRICE FORECASTS AND RELATED SEASONALY-BASED BTER
COMPARE TO THE FORECASTS AND BTER PROPOSED BY NEVADA POWER
ON FEBRUARY 24, 2006.
::ODMIPCDOCS\LRNODOCS\713\ 1 Page7 '
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Prices for both fuel and purchased power for the test year are now forecasted to be
lower than the forecasts used ~y Nevada Power. This, of course, results in a lower
estimaed annual BTER forecast. But, due to the seasonally higher summer BTER
rates I calculate below, use of the seasonal BTER wil pose no greater risk of revenue
under-revery than the BTER propoed by the Company on February 24, 2006. This
is due essentially to the fact that my propose summer BTER is estimated to be very
nearly the same as the updated BTER proposed by Nevada Power. The diference is
that the non-summer rate i estimate is approximately $8/mwh lower, but this lower rate
should not go into effct until October of this year, when fuel and purchased power
costs nonnally decrease, barring no significant changes in fuel and purchased power
markets by that time.
PLEASE EXP~N YOUR UPDATE OF FUEL AND PURCHASED POWER
MARKETS AND THE DERIVATION OF SEASONALLY.BASED BTER BASED
UPON THAT FORECAST.
My update, and recommended seasonally-base BTER, is shown on my Exhibit DEP-
2. All significant data and assumptions used by Nevada Powr were also used in my
revised analysis, with the notable exception of its fuel and purchased power forecast
Upon review of the forward market natural gas and electic pnces, I found that prices
had continued th downward trend found by Nevada P~er by the end of January. In
fact the March 1, 2006 natural gas price markets had fallen slightly over 10 percnt
from the forecast use by Nevada Power.1 The fuel and purchased power costs for
the summer and winter periods show on Exhibit DEP.2 reflect this decrease in costs.
These fuel and purchase power prices adjusted to March 1, 2006 are then
developed Into seasonally-based BTERs on Exhibit DEP-2, in the same fashion as
those in Exhibit DEp.1.
28 1.For example, this was derived from observng a deceas in natural gas NYMEX price of $1.37/mmbt
fro Nevada Power's pric. Purchas power pnces were also lowr since tiey are heavily influece bynatral gas co.
::ODMA\PCOOC\HLRNODOCS\2228\1 Page 8
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The final result of these adjustent result in my proposed seasonally-bsed
BTERs in these proceedings.
Proposed BTERs
Summer Winter
Residential
Non-Residential
$0.06125
$0.06270
$0.05318
$0.05463
The summer BTER is generally applicable to months June through September, while
the non-summer BTER is applicable for months October through May.
ARE YOU AWARE OF THE FACT THAT NEVADA POWER IS REQUESTING THAT
THE BTER BE IMPLEMENTED BEGINNING MAY 1, 20061
. Yes, and this could cause a bit of disntil'uity in terms of rae design, as the lower
non-summer rate Is really most appropriate for May 1, 2006. However, the
Commission may not wish to implement the lower rate for one month, followed by the
higher summer BTERt espeially since May is a shoulder month wih consumption and
costs nearly approaching summer month levels.
DO YOU HAVE A RECOMMENDATION IN THIS REGAR?
Yes. i recommend that the higher summer BTER be implemented on May 1, 2006 as
a special circumstance related to the Company's reques for early summer
implementation.
WHY DO YOU MAKE THIS RECOMMENDATION?
I make this recommendation fo several reasons. First, Implementaion in May
provide~ some rate continuity. Second, the Company indicates that it wil be carrng
positive deferral balances into this new test year, thus there is no reason to lower
current BTER rates fÓr one month. Lastly, it will provide some cushion for summer
::ODMA\PCOOCSloNODOCSI58\1 Page 9
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costs, altough my updated forecast indicates that the Company-preicted summer
revenue shortall should be largely, if not entirely, eliminated, as well be the nee for ,
its referenced $200 millon additional debt financing.
DO YOU HAVE A PROPOSAL FOR IMPLEMENTING THE NON-8UMMER BTER?
Yes. If the most rent forecast is accurate, the approximately 8 mil/kwh reduction in ,
the BTER would commence October 1, 2006.
However, as a transitional accomlTodation, i recommend that Nevada Power
be allowed to update the natural gas and electic forecasts by the end of August if
there Is signifcant change from th Marc 1, 2006 forested prices. This
accmmodation is simply to eliminate the nsk of market change against it at that time,
and to allay any angst from the financial institutions that the transition to seasonal
rates could be negative to the Company. Since a higher BTER wil already be in
place, the ability to accmmodate a change In forecaste prices would also be easy to
Implement If it just meant not lowering the non-summer BTER as much as estimated
for October 1, 2006.
SUMMARY AND CONCLUSIONS
PLEASE SUMMARIZE YOUR CONCLUSIONS,
I recommend that:
1. The seasonal rates summarized in my Exibit DEP.2 be implementd in
this case.
2. The higher summer BTER rate, ordinarily put in place for the first
summer month of June, be implemented as a one-time exception this
May 1,2006.
3. Nevada Power be allow to re-file a fuel and purcase power update
in August that might, or might not, af the degree to which the non-
summer rates to be implemented October 1, 2006 are reduced.
DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
Yes.
: :ODMA\PDOCLRNOOOCS\52278\1 Page 10
AFARMATION
I, Dennis E. Peseau, pursuant to NAC 703.710 hereby affirm that the
foregoing prepared testimony wa prepared by me or under my direction an is
correct to the best of my knowledge.
Signed
Dated
¡;~-
t3 - t?1-l2
ATTACHMENT 1
. .
Attchment 1
Dkt. 061016
Witness: D.E. Peseau
Page 1 of3
STATEMENTOF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conducted economic and financial studies for regulated
industries for the past twenty-eight years. In 1972, he was employed by Southern
California Edison Company as Associate Economic Analyst, and later as Economic
Analyst. His responsibilities included review of financial testimony, incremental cost
stdies, rate design, econometric estimation of demand elasticities and various areas
in the field of energy and economic growth. Also, he was asked by Edison Electrcal
Instiute to study and evaluate several prominent energy models as part of the Ad
Hoc Commitee on Economic Growth and Energy Pricing.
From 1974 to 1978, Dr. Peseau was employed ,by the Public Utilty
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and financial studies and prepare testimony pertaining to public utilties.
In 1978 Dr. Peseau established the Northwest offce of Zinder
Companies, Inc. He has since submitted testimony on economic and financial
matters before state regulatory commissions in Alaska, California, Idaho, Maryland,
Minnesota, Montana, Nevada, Washington, Wyoming, the District of Columbia, th
Bonnevile Power Administration and the Public Utilties Board of Alberta on overooe
hundre occasions. He has conducted marginal, cost and rate design studies and
. .
Attachment 1
Dkt. 06.01016
VVUness: D.E. Peseau
Page2of3
prepared testimony on these matters in Alaska, Califrnia, Idaho, Maryland,
Minnesota, Nevada, Oregn, Washington and in the Distnct of Columbia. He has
also conducted cost and rae studies regarding PURPA issues in the states of
Alaska, California, Idaho, Montana, Nevada, New York, Washington, and
Washington, D.C.
Dr. Peseau holds B.A., M.A. and Ph.D. degrees in economics.
He has co-authored a book in the field of industrial organization entitled,
Size. Profits and Executive Compensation in the Large CorporaiQn, which devotes
a chapter to regulated industnes.
Dr. Peseau has published articles in the following professional journals:
Review of Economics and Statistics, Atlantic Economic Journal, Journal Qf Financial
Management, and Journal of Regional Science. His articles have ben read before
the Econometric Society, the Western Economic Association, the Financial
Management Association, the Regional Science Association and universities in the
United Kingdom as well as in the United States.
He has guest lectured on marginal costing methods in seminars in New
Jersey and California for the Center of Professional Advancement. He has also
guest lectred on cost of capitl for the public utilit industry before the Pacific Coast
Gas and Electc Association, and for the Executive Seminar at the Colgate Darden
Graduate School of Business, University of Virginia.
Attachment 1
Dkt.06-01016
Witness: D.E. Peseau
Page 3of3
Dr. Peseau and his finn have partcipated with and been members of the
American Economic Association, the American Financial Association, the Western
Economic Association, the Atlantic Economic Association and the Financial
Management Association. He was formerly a member of the Staff Subcommittee on
Economics of the National Association of Regulatory Utilty Commissioners.
Dr. Peseau has been President of Utilit Resources, Inc. since 1985.
Month
Exhibit CEP.1
Pae 1 Qf1
Periiiu
NIMI Po Compel\
Clllatlon of SiOlIiIl Ba Tariff Enl'Y Rate.
Annualize for ti. Twl¥l Man1l End NlMmbr SO. æUG
Foreted fO the Twlv. MoJl Eniec Apil 30 207
(000$)
Fue an Purcse Pow Cot Forsted Mw Eny Sales
Nevada
Summer Willr Tot Suer Neda Winir FERC Tot
98574 1.711.457 4.75
130,203 1.987.807 9,283
169.496 2.497,571 13.940!!i.?47 2,251,9 13,&8124.419 1,748,87
90,426 1,288.96
74,349 1.487.914 817
84,310 1,523.952 1,208
99.03 1.538.124 2,51488,3 1.00,185 1.17085.69 1,44,83Q 244
76.796 1,43.025
51J8ES 697,528 1.20,393 8.486.193 11.702 47,aDa 20.24888
2,1 88 a.06
ö848 6941 1,277,325
'0.0084 $0.0691 50.00325
Mey.(Juri
JulyoO
Augul1-0Seøl..
OClOflr.(6
November-0Decebe-0
JanU8o07i:iy-0
Man-07
Aprii-7
Tot
Less FERC Alloction
Net Retøl Cosl
CO$I pe kWh bere Hover
AdJUltm'* for Hoov B
Hoover B Benul
Alllln ci Hoovr B 10 Non.
RcGidenllel
ADocalln of Hoove B8e to Røidial
Røiiiriie SaleaNan-Ridnl SalTolISeI.
NGl Hor B a_li io
Rel POI kWh
Nel Hor B Cot to NOl-
R86ldela pe kW
CO per kW Me HoReiitllNonlllil
1:1.545
7.117
(7,177
8,641,455l' .!5.62
20.196,08
($0.0083)
$0.0082
Summer Winter TOIII
$0.06757$0.692 $O.(J08
$0.06013
$0.08242
$0.637
Sourcu: ExhIbi E(Rev) end ExhIbit E.' (Rev)
P; 16
. . ..
Month
Neva PCIr ComanyCalCUlah of SesonllZed Base Tarff Energ Rale
Annll for the1W1v Months Ende N_ber 30. 205
URI Adsl FCl for tt Twe Mo Ended ApI30. 2Ø07
(000$
Exbll DEP
Page 1 of1Peu
FU an Pun: Powr COI Foreted Mw Energ SaleNevadSlr,Winter TQlI Summe Nevada Wir FeRC T0C1
89,463 1.711,4 4.$118,188 1.87.807 9,21538292.497.571 13.94144.074 2.251.9l 13,68112,19 1,746,827
8208 1.26,36
67.477 1,467,914 817
76,517 1,52,952 1,28
89,679 1.53.124 2.514
80;179 1,300.185 1.170
77.774 1,440,8 244
69,698 1c39,1
528.991 63055 1,162,046 8.48.193 11.709,89 47,8 20.243.88
2,150 824 2,784
526.830 63431 1,159.262
$0.068 $0.051 $0.05740
MaJuniJuly-
August~Sepem.Q60d.0No-ØeDll.Q6
Jønuary7
FebRl-G7Mari7
Aeril.(
Total
Less FERC AUocUo
Net Retail Co
Cost per kW bafa HOCr
Acusents fo HOOf B
Hoar B Bonet
AlIn of Hooer B to Non-Redenia
AUoction afHoQl B
Benet to Redeal
Reslclønll SalesNon-Rekll SaleTot Sa
Ne Hoov B Benefit to
Residntial pe kW
Net Hoovr B Co to Non.
Redenal pe kWh
Co per kWh Afr Hoove
Redential
Nci.Rea1cnlBI
12,55
7.177
(7,177)
8,641..t
11,554.29ii.l9l;0
($0.00083)
Summ
$0,00082
TolalWinr
$(,06125
$0.062 $0.05318
$0.054 $0.056$0.058
So: Exhbit E(Re) and Eilb~ E-1(Re)
Pag 17
1
2
PROOF OF SERVIE
3.I hereby certify that I have this day served a copy of the foreoing Direct Testmony of
4 Dennis E. Peseau on behalf of Southern Nevada Water Authoriy In Docket 06-0101~,upon
5, each of the partes listed below by hand delivery or by electronic mail and U.S. Mail, propeny
6 addressed, with postage prepaid to:
Elizbeth Elliot
Associate General Counsel
Nevada Powr Company
6100 Nell Road
Reno, NV 89520
Fax: [phone]
Email: bellotcmsppc.com
7 Mark Russell, Esq.
Mirage Hotel and Casino
3400 Las Vegas Blvd. South
las Vegas, NV 89109
Fax: [phone]
Email: mrusslJ~mirage.com
8
9
10
II Julia E. Sullivan
Law Offce of Julia E. Sullivn, LlC
219 A Duke of Glouceter Street
Annapolis, MD 21491
Fax: [phone]
Email: luliasullvantãjeslaw.us
Staff Counsel
Public Utilities Commission
1150 E. Wiliam Street
Carson Cit, NV 89701
Email: aburtens(dpuc.ste.nv.us
Richard Hinckley, Esq.
Public UtiltIes Comission
1150 E. Willam Street
Carsn City. NV 89701
Fax: [phone]
Email: hinckley(puc.state.nv.us
Dale Swan
Exeter Associates, Inc.
5565 Sterrett Place, Ste. 310
Columbia, MO 2104-2690
Fax: [phone]
Email: dswan(dexeterassoates.com
Jon Wellnghoff, Esq.
Becey Singleton Chtd.
530 Las Vegas Blvd. South
Las Vegas, NV 89101
Fax: [phone]
Ema~: Iweillnghoffcmbeckleylaw.com
Charles K. Hauser, Esq.
Southern Nevada Water Authoriy
1001 S. Valley View Blvd.
Las Vegas, NV 89153
Fax: [phone]
Eric Witkoski, Esq.
Consumer Advocate
Bureau of Consumer Protection
555 E. WashIngtn Street, Suite 3900
Las Vegas, NV 89101
Email: epwikos(iag.stte.nv.us .
Phil Wiliamson, Financial Analyst
Bureau of Consumer Protection
100 N. Carson Street, Suite 200 .
Carsn Cit, NV 89701
Fax: [phone]
Email: pjwillaCãag.state.nv.us
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¡-
::ODMA\PCOCSRNODO22'46\1 Page 18
i Lawence A. Gollomp
Assistant General Counsel
2 U.S. Department of Energy
1000 Independence Avenue, SW
3 waShinmon, D.C. 20585
Fax: [phone]
4 Email: lawrencè.Gollomp~hq.doe.gov
5 Dated this ~ay of March, 2006.
6 h~::d7
An employee of Hale Lane Peek
8 Dennison and Howard
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::ODMA\PCDOCS\HLRNODOCs\227461 Page 19
Conley E. War (ISB No. 1683)
GIVS PURSLEY LLP
601 W. Banock Stret
P.O. Box 2720
Bois. ID 83701~2720
Telephone No. [phone]
Fax No. (208) 388~1300
cew(ggivenspursley .com
RECElVÈO" inFILED 0
lfm JUH 2 l PH ~ 34
IDAHO PUl~lIC
UnUTiES, COMMISSHJN
, 7/7/¿l/
R I' $'( liiil l!..
Attrneys for Potlch Cororation.S:\lIS\l3i4~Ðl~Teidmon.Ð
BEFORE TH IDAHO PUBLIC UTILITIES COMMSION
IN TH MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTORITY TO INCREASE IT RAlE
AND CHAGES FOR ELECTRC AND
NATUL GA.S SERVICE TO ELECTRC
AND NATU GAS CUSTOMERS IN
TH STATE OF IDAHO.
Case Nos. AVU-E..~ 1
AVU.G-041
DIRCT TESTIONY OF DENNIS E. PESEU
ON BEHALF OF POTLTCH CORPORATION
June 21, 2004
,ORIGINAL
1 Q.PLEASE STATE YOUR NAM AND BUSINSS ADDRESS.
2 A.My nae is Dens B. Pesu. My buiness addrss is Suite 250, 1500 Liber Stret,
3 S.B., Salem Oregon 97302.
4 Q.BY WHOM AN IN WHT CAACIT AR YOU EMPLOYED?
5 A.I am the Preident of Utity Reurçe. In. ("URl'). UR has conste on a number of
6 economic, financial and engineeg ma:tt for vaoos priva an public entities for
7 more th twenty yea.
8 Q.PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND WORK
9 EXERINCE.
10 A.My resue is ataced as Exhbit No. 201.
11 Q.HA VB YOU PREVIOUSLY TESTIFIED BEFORE TH IDAHO PUBUC UTILITIE
12 COMMSSION?
13 A.Yes. on may occaions.
14 Q.FOR WHOM ARE YOU APARIG IN THIS CASE?
15 A.I am appeang on beha of Potlatch Corporation ("Potlatch").
16 Q.WHAT is THE PUROSE OF YOUR DIRECT TÈSTIONY?
17 A.I have been asked to review Avist's applicaton in tls cas and mae apprate
18 recommendations to the Commssion.
19 Q.PLEASE PROVIDE A SUMY OF YOUR TESTIMONY.
20 A.My testmony deals with four major issues. all concerng th application for an increae
21 in electrc rates. Afr reviewi the evdence, I conclude tht:
DIRCT TETIMONY OF DEN E. PESEAU - i
IPUC Case Nos. A VU-E-1 aDd A VU-G-041
............:..................................................................,.........................................................................".,..........,.........,...................................................,...,.............
I 1.The Coyote Spnngs 2 generti plant should be exclud from rate bas on
2 seer grounds. not the least of whch is that the plan is not "used and usefu" in
3 providing serice to Avita's rapayers.
4 2.Avista should not be allowed to recover the cost of natural ga hedges or sws
5 put on in Apri and May of2001 because they were imrudent and inteded to benefit
6 Avist's ungulated activities at the rateayer' expens.
7 3.Avis's use of a 2002 tes ye, adjuste for allegedy known and measurble
8 chages. produces a mismatc of expes and rate bae, on the one had. and revenues
9 on the other. I offer 3 altertive metods of correctig ths mismatch.
10 4.Avista's inclusion of Potlatch's Lewn Facilty in Schedule 25 for rete design
11 plDses is uneasonable on its fa and A vista's cost of serce stuy overstates the
12 anua cost of servng Potatch by apximaely $1.4 millon per year.
13 In addition, John Thornton wiU pret Potlatch's cost of capita temony and its
14 recommendation for are on equity for Avista. However, in th rectly completed
15 Idaho Power rate cae, I offd a critique of Dr. Avera's temony tht showe that
16 updted data and a consistent application of his methodology demonstrte that his cost of
17 equity is oventated, even if one accepts his assumptions. I fea tht if I were to not
18 perfonn a similar anysis in ths case the Commission would draw the unwaanted
19 inerence that my critique is no longer valid. To forestal th infernce. I have prepared
20 and atthed an Appendi to this testimony tht once agan shows tht simple updates to
21 Dr. Avera's data, an the us ofintey consstnt d: employed with his retu on
22 equity metods, drcally lowe his ret on equity estate below the 10.4% to
23 1 i .9% equity cost rage (af the addtion of flotation costs) he estimates for benchmark
DlRECT TEIMONY OF DENNIS E. PESEAU ~ 3
IPUC Case NOI AVU~E-041 and AVU-G-4-1
....... ........... ....... ........'. ... ..... ........ ...................,... _.. .--.. ...... _.. ... .... ...... ...~ ......... ... _.. ........-......... ..... .... ....,.. ... ............... ...... .... .... ......................... ......... ................... .................. .............. .~...-.
1 elecric utilities in th wester U. S.t and below the 1 i.5% eqty retu he endorses for
2 Avista.
3 Coyote SpnDgs 2
4 Q.WOULD YOU PLEASE EXLAI TH ISSUES CONCEG TI COYOTE
5 SPRIGS 2 GENERATIG PLAN
6 A.Before I do so, a short prefae is in orer. The two toics I next discuss in ths tetiony
7 rase very distbing isss about the relatonship beween Avista's reguated and
8 ungulated ar. In order to unta the signficace of thse iss the
9 Commssion need to have a clear understading of Avista's peul corprate strctue.
10 Consquently, I hae repruce below Scott Morr' Avista orgazatona char frm
i i his Exhbit No. I, page 5 of 5:
DIRCl TESTIONY OF DENN E. PESEAU - 4
IPUC Case Nos. A VU-E-041 and A VU-041
............................................................................,..........................,..................u...,...................................................,...............,..........................................
1
2 Q.
3
4 A.
S
6
7
..
8
9
10
11
A vista Corporation Company Overvew
o
-I A~'" Ði I
o '--.''''0l
o .-.ICop1ldirilo..lì..ii..
llalblllf6. iS.MoA. Çwloft
PLEAE DESCRIE TH ENTITS AND OPERTING DMSIONS ON THE
CHART.
Avist~s unguate enteise appear on the right had side of the char. Avist
Capita is a holdi compay for these enterises. Avista Advage provides
inormtion serice and related business serces. Neither it nor the operatin division
labeled "Other" figue in my teony. The tw entities engaged in "Energy Marketig
and Resour Maagement " on the other hand, playa prominent role in the following
discussion.
Avist Power is Avista Corpration's il-fatd entr into the merhat powe
business. It wa orgialy designed to build or acqui generatig plants and other
DIRECT TESTIONY OF DENN E. PESEAU w 5
!PC Cas Nos. A VU-E-041 and A VU-G04-1
1 reures to serve the unguated wholese electcity marets. According to Avista's
2 teony it is now intive, but it was the origin owner of the Coyote Spnns 2
3 genertig plant and it stll own 49% of th Ra merct plant.
4 Avista Energy is Avist Corporaton's energy tring ar. Its prar purse is
5 to trade in both the electrcity and 1lal gas markets. In addtion, it brokers deas for
6 . Avís Utilities, althoug the Washingt Utities and Traorttion Common
7 recently orderd the terination of ths relationp with respect to natul ga purches.
8 At the pea of its activity it genrated reenes far in excess of A vita Corpration's
9 reguated public utlity saes.
10 Q.YOU EARIER DESCRIED AVISTA CORPORATION'S ORGANIZATIONAL
11 CHAT AS "PECULIAR." WHT DID YOU MEAN?
12 A.The right hand side of the chart is not at all unusual for a utility. Most utlities pla
13 uneguate actities in separte entities. The left had side is quite the opposite. All of
14 th utities I am famar with orga the utilty fucton as a separa busines entity,
15 which makes its own purchas and busnes deas separte and apa ftm the
16 ungute enterp. But in Avista's cas, th is no separe utility entity, only an
17 operatig division. In effect, "A vista Utilities" is simply a nae for the residua holder
18 of A vista Corporaon asset tht ar not claimed by one of the unegulated entities.
19 Q.WHT DIFFERECE DOES AVISTA'S ORGANTION MA?
20 A.It blur the distncton between regulated and ungulated activities. In the las A vista
21 rate cae, I complained, appary not stenuously enough that Avìst~s corporate
22 strctue, and its prctce of not contemoraousy makig trdes to its regulated or
23 non-reguated ar, lef it with the latitude to subsuently alocate trades based on their
DIRCT TEMONY OF DEN E. PESEAU. 6
IPUC Cae Nos. AVU-E-()1 BDd AVU-c.O..i
1
2
3
4 Q.
5 A.
6
7
8
9
10
11
12 Q.
13 A.
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15
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18 Q.
19
20 A.
21
22 Q.
..................................................,......................-..,..................................................,............................................................................
profitailty. I charzed th sitution as analogous to a stockbroker who maes
investents and th month or even year later~ decides whether the purhases were for
his own or his cusomer's account.
IS THIS STILL A PROBLEM?
In fact, th preent cae is fa worse. In the case of Coyote Sprgs 2 ("CS2")~ the
ungulated entity (Avist Power) purchad a plan that subsequetly proved to be a
disaster. What is the Company's afer tle fact position? "We (A vista Corpraon)
ordered th trcton by our unguted subsidia (Avi Power) for the 'befit' of
our reguated cusomers." Ths is analogous to a broke buying a stock for hi own
acunt, and then tw yeas late, when the trade is hopelessly under water, declag tht
the trde was really for the cuomer's acount
HOW DID CS2 GET STARTED?
The CS2 fiasco began li many other recet energ debacles in the West, with Enrn
playing ~ prominent role. CS2 wa originaly a Portand General Elecc ("PGE")
project to be built as a compon to POE's Coyote Springs 1 generati station located
nea Boaran Orgon. POE was a regulated Enron subsidiar dur the entirety of the
CS2 saga.
DID ENON PLAY ANY ROLE IN TI DEVELOPME OF CS2, OTHER TH
BEING PGE'S PARET CORPORATION?
Yes. On May 4, 1999 Enon ordered the turbine for CS2 from OE at a contrac price of
$35,889,000.
HOW DID AVISTA BECOME INOLVED WI CS2?
DIRcr TETIMONY OF DENNIS E. PESEAU - 7
IPUC Case Nos. A VU-E-4-1 and A VU-Go0i
A.In mid.1999, Enon and POE decided to sell CS2. On October 4, 1999, Avisa Power
2
3
entered into an "evaluation ageement" with POE that allowed it to begin its due
diligence investgaon of the pla. r asswne that other potential buy were also
4 investigati the purhase at abut the same time.
5 Q HOW WAS TI PROPOSED SALE STRUCTUD?
6 A.By the time it was completed, the deal wa classic En in its quirkiess. On October I,
7 1999, the days befor A vist Power signed its evaluation agreement, EnroD
8 inorprated Coyote Springs 2, LLC ("LLC") as a wholly owned subsidiar. On
9 December 22, 1999, Enron and POE agred to trfer CS2 to LLC, contient upon a
10 subsequent sale to an unidentified thir pary. The Decembe 2200 ageement also
11 divided up the proceed of the potental sale as fol1owsth POE and Enn would fit
12 recover thei "cos basis" in CS2 and the turbine, plus their out of pocket ánd allocated
13 cos of development. Thereaer, the fust $10.47 millon of profit wa allocated to POE,
14 the next $12 millon to Enll and any additional amounts were to be split.
15 Q. DID THIS POE AN ENRON DEAL CONlMPLA TE A SALE TO AVISTA
16 POWER?
17 A.
,
Not originlly. Appartly it was strctued for a sale to an unidentified third par who
18 ultimately backed out. Then Avist Power re-entered the picte. On March 4, 2000,
19 Avita Power signed a Ler oflntent ("LOI") with Enron to buy both CS2 and the
20 tubine. The LOr set the puchae price at $19.5 millon for CS2, an $40 milion for the
21 tubine. POE's and Enrn's collecve cost basis and developmen cost for CS2 were
22 idetied as $ 8,450,000, with the reainig $11,050,000 labeled as a "premium."
23 Q.WHAT DID AVISTA POWE IN TO DO WIll TH CS2 PLANT?
DIRCT TESTIMONY OF DENN E. PESAU. 8
IPUC Case Nos. A VU-E-4-1 and A VU-G-1
1 A.As in the ca of th Radr plant, Avist Power prsuly inteded to opera CS2
2 as a mercha plant sellin into Western wholesae eleccity make. i bas ths
~
3 presumption in pa on the plant's location, which is il suited to serve Avist Utiities
4 load centers th are loced far to the east of CS2.
5 Q DID TH PURCHASE CLOSE AS PLAND?
6 A.No. On June 20, 2000, th LOI wa amended to reaocate the purchas prce as $16.5
7 milion for CS2 an $43 milion for the tu. I càot fid an explanon for th
8 chage in any of the discovery documents we received, although I sur it may have
9 been the reult of a retion in the previous estima of developmen cost.
10 An even stger development took plac apprximly the weeks later, on
11 July 7, 2000, when Enn assigned its rights to the GE tune to A vista Power. On th
12 same day, Enron crated another subsidiar, LJM-Coyote ("LiM"). For a price of
13 $3,540,000, UM2 provided Avista Power with a two week ''put option" on the tubine.
14 In other words, frm July 7th thugh July 21sl, Avi Power coul requ LJ to
15 repur the tubine for the sum of$39.960,OOO. This put option wa never exerise
16 becus, on July 21, 2000, Enn assigned its inteest in LLC to A vist Power, thus
17 giving A vista Power ownerhip of CS2 as well as the tubine.
18 Q.WHY is TI LJM TRASACTON STRGE?
19 A.I ca think of no legitiate business reaon for A vista Power to ente into the put option
20 agrement. In the first plac, tubines we in short supply at the time, and A vist would
21 have had litte diffty re-selling the tmine if the CS2 de somehow collapsed.
22 Moreover, it is diffcult to understand why, if Avita Power feard the exposure of
23 holding the tubine before it seured the CS2 rights, it didn't simply insist on a
DlR TESTONY OF DENNIS E. PESEAU - 9
IPUC Case Nos. A VU-E-61 and A VU-G-Ð1
..............................,...................................................................................-..................................................................-.....................................................................................................................
1
2
3
4
5
6
7
8 Q.
9
10 A.
11
12
13 Q.
14 A.
15
16
17
18
19
20 Q.
21 A.
22
simultaeous trfer of the two components. Inea it alowed Enon to impose a tw-
week gap on the signng of the two agreents and, in effect, sell it $3.5 milion of
insuance to cover the mini exposu that gap cred. Finally, why would any
reaonle busineseron pay $3.5 millon for a two wek "insce policy" issued by
an empty corprat shelL, with no as and an opeatng history of less than a day, even
if Enron guteed the put? TIs simply doesn't pas even a mimal smell test
parcularly when the counte par is naed Enrll
WHN ALL WAS SAID AN DONE, WHAT DID AVISTA PAY FOR CS2 AN
TH TUIN?
Th total purhase prce, inlud the option, wa approximately $59.5 milion, for a
plant that, by my calcuations, appared to have an all-in cost of approximately $42
million.
WHT WAS TH BOOK VALUE OF THE TRSFERRD ASSETS?
The book value of the tubin would have bee the sae as its purchae price,
$35,889,000. The Alloction Agmet date July 21, 2000 listed CS2's book value as
$3,755,409, with an additiona $2,287,591 alocate to projec deelopment exenes.
Consquently, the book value would have been $39,644,409 withoutthe development
expns, and $41,932,000 if development expenses we capitaize an added to book
value.
WAS THAT THE EN OF AVISTA POWE'S INVOL VEMB WITH ENON?
Not quite. In Apri of2002, CS2's prme contror, another Enon afate, fied for
bany and CS2 lost the beefit of its fied price conscton contract while at the
DIRCT TESTIMONY OF DENNI E. PESEAU - 10
!PUC Case Nos. A VU-E-i and A VUG-1
........................................................................................................,...........................................................................................................................u......................................................_..............
1
2
3 Q.
4
5 A.
6
7
8
9
10
11
12
13
14
15
16
17
18 Q.
19
20 A.
21
22
sae time incurng the cost of replacin the prie contctr an setting with
subcntrrs.
WAB THAT TI ONLY PROBLEM THT OCCURD DURG TH
CONSTRUCTION AND OPERATION OF CS2?
No. It is fair to say that CS2 ha been an contiues to bet an ecnomic an operational
nightmare. In May of2002t apprxitely a month befor th scheduled completion of
the plant, a fire desoyed the trsformer purchased frm a Turkish supplier. This not
only prevented the completion of the plan, it al resuted in an environmenta inident
when water used to douse the fire over the splash pond built to conta the
trsformer's contets in the event of an acident. Clean-up cost as of Deember 31,
2003 wee approxitely $1.7 millon, ha of which are A vista's responsibilty.
A replaemen transformer arved at the site in Decmber, 2002, but an
inon reveaed it could not be insled because of shipping dame. Repai to th
tranrmer delayed CS2's commercia operation date fo more th a yea, to July, 2003.
Ther, the plant wa in serce for apprxitely six months. It then exenced
another round of trformer problems that shut it down aga. The projected dae for a
retu to seice is now Aug of2004.
YOU JUST DESCRIED CS2 AS AN ECONOMIC NIGHTMAR. AR YOU
REFERRG TO SOMETHG BEYOND ITS CONSTRUCTON PROBLEMS?
Yes. The constrcton probleI have causd the estimated cost of Avist's haf of the
plat to swell from approximately $94 mion to $109 millon. In addition, the natura
gas swaps I wil discus in detail later in my testiony produced losses in excess of $62
DIRCT TETIMONY OF DEN E. PESEAU .11
IPUC Case NO& A VU-E-041 and A VU.Go01
i millon. The bottm line is th A vist overpd for the plat in the original purhase,
2 an ever tu of the car sice then has only added to the miser.
3 Q.SO WHO PAYS FOR ALL THS?,
4 A.Under Avist's proposa 'to rate base the entity of the plant's cost Avistrateayers
5 will pay for all of these problems. If Avista's proposa is acepted, the only entities that
6 wa away from this train wrck uncathed ar the plants ongi own. Avi Power.
7 and its part. A vista Coipration.
8 Q HOW DOES A VISTA POWER ESCAPE AN RESPONSffILIT FOR CSlS
9 PROBLEMS?
10 A.In December of2000. Avista Corporation anoun it would acqui CS2 from Avist
11 Power. But it did not in fact follow though on ths anouncement. Instead, it vailate.
12 Intern A vist memos indicae th A vista Powe was trin to sell the en plant to
13 th pares in the summer and fall of 2001. But A vist Power received only one full
14 prce offer from Mirant, and that prospecve dea fell apar whe Mirant ran into ca
15 flow problems. Ultimaely. Avist Powe ended up sellg 50 perent of the plant to
16 Mirat, and 50 percent to Avista Coipration.
17 Q.WH DID TIESE SALS OCCUR?
18 A.A vita Power asigned a SO percent intet in LLC to Mirat on Decmber 12, 200 i.
19 But it did not transfe the other 50 perent of th plat to Avist Corportion unl
20 Januar 1, 2003, af the close of th test yea in ths cae.
21 Q GIV TIS mSTORY, WHT is TH APPROPRITE RATBMAG
22 TRTM FOR CS2?
DIRcr TESTIMONY OF DENNIS E. PESEAU .12
IPUC Case Nos. AVUE-ß1 and Avt04.1
1 A.
2
3
4
5
6
7
8
9
10
11 Q.
12
13 A
14
15
16
17
18
19
20
21
22
23
I have tw recommendatons concerng CS2. The fist is that th cost of the plant
should not be inluded in rat ba in ths cae. CS2 is demonsbly not used an usefu,
and its trck recrd does not inpire confdenc it will be used and us in the nea
:f. A vist has had th tres at completng the plant and get it rug on a
reliable bass. It ha stck out al th ties. Given ths history, the plant's cost
should not be eligble for recovery in regulat rates unti it ha a deonstated tr
recrd of usfuess and reliabilty.
Furennore, ü and when the plant does become eligible for inclusion in rae
base, the rate based costs should be limted to the plan's fair market value, as decrbed
below, as of th trfer date of Janua i, 2003.
WH ARE YOU PROPOSING TO REUCE THE PLANT'S COST IN THIS
MA?
I am simply applyig stdard ratemg preceps to the purhae. A vist Powe is an
wiegulated Avist Corporon subsidiar, and tractions between it and Avist
Corpraion ar clealy not at an lengt. I am not an atorney, but I have spent enough
yeas in the regulatory field to stae that, in jurisdicton I am famlia with when a utility
purchases goods or service from an ungulated afflie. the burden is on the utility to
prove th the purcha price di not exced fair maet value. In the present cas.
becuse of al the construion disast, it is quite clea th trerr CS2 to A vista
Corpon at cost cretes a purchae price that is well in excess of fa market value.
These exce costs should be dislowe. It is patently unjus to as th
rateayes to relieve Avist Power of th unortate consequence of its half ownerp
ofCS2.
DIRCl TESTIMONY OF DENIS E. PESEAU .13
IPUC Case Nos. AVU-E-1 and AVU-G1
1 Q.DOES TH FACT THAT AVISTA CORPORATION PREVIOUSLY ANNOUNCE
2 AN INTION TO ACQUI TI PLANT MA ANY DIFERECE IN THIS
3 CASE?
4 A.No. Avist's anunced intetions came afer Avista Power ha aldyoverd for the
5 asse it purchasd from PGE and &ron, so an adjustent to fair maket value would
6 have been in order even thn. In addition, even though the hoards of directors of the
7 involved compaes autorize their executives to prce with the transation, the
8 companies never acted on those resolutons. Avist's discver responses cotan no
9 contrct, memoradum of unerstding, or any other docent tht would evidence an
10 intention to prceed with the sale. Under those circumstaces, Avis Power wa under
11 no legal obligation to sell to Avi Corption, and it in fat tred to sell the plant to
12 thrd paes month afr the anouncement. Eventuly it did sell haIfto Mirant.
13 Avist unlateally chose to purase CS2 thugh its ungulat subsidiar,
14 thereby avoidig any reguatory consnts on its use or diosition of the assets. Let us
15 suppose tht Avista Power had succeeded in the suer of 2001 in selling the plat at a
16 profit. Would Avita Power have volunteered to sha the procee with the ratepayer
17 just because at on tie it innde to sell the plant to A vist Corporation? Ths is the
18 same A vist that reiste sharing the Centra sae prees with raayer. A vista
19 would have argued tht the dea wa never consate, and th ratepayers never
20 acquired an equitale interst in the plant thugh th payment of depreciation.
21 Q HOW DO YOU PROPOSE TO DETERM TH FAI MAT VALUE OF CS2?
22 A.The Commssion could conduct fuer proceedigs for the express purse of makng
23 suh a detemion, but there is a much easer metod rely available. Just two yeas
DIRCl TESTIONY OF DENN E. PESEAU - 14
IPUC Case Nos. AVU.E-1 and AVU.G-i
1
2
3
4
5
6
7
8
9
10
11
12
13
14 Q.
15
16
17 A.
18
19
20
21
22
ago, th Commion conducte an extensive investation to dete the cost of a 270
megawatt combin cycle natal ga plant to use as å suga avoided resour
("SAR") for the purose of caculing avoided cost ras. On Aug 2, 2002, one
month afer CS2's origin schedule4 completion date, and five month before the
trfer of CS2 to A vita Corportion, A vista fied rebutt testony identing the
most rent constrction cost estimats for the SAR as $604/klowaU. I see no reon
why A vista should not be held to its own contemporeous estate of the cost of
consg a plant nealy identical to CS2. This figur, afr all, repreents the
maxmum value A vist Corporaon was willing to pay for the purchase of resurces
frm unlate thd pars just before it acuired CS2 frm A vita Powe. Using the
$604 figue prduces a fair maket value for CS2 of $84,560,000 for Avist's shae of
CS2. The Comion should not allow cost above ths amount in rate base at any time.
The Natural Gas Hedges
WHAT is THE iSSUE WITH RESPECT TO TH "DEAL A" AND "DEA B"
HEDGE TRASACTIONS IN mE COMMSSION'S ORDER ON A VISTA'S 2003
PCAFILING?
To its credit, the Commssion reognzed the peuliar natue of both Dea A an Deal B
in the 2003 peA prceg and deferr a deciion on the costs of these des into the
presnt general rate cas. As I explai below, the high costs associate with each deal ar
the resut of imprut decisions and self-dealing between Avist Corpraon and Avist
Energy. A vist' s actions have resuted in excess natu gas costs of more than $62
million on a system-wide bais.
DIRCT TESTONY OF DENN Eo PESEAU . IS
IPUC Cas Nos. A VU.E....i aDd A VUG-i
......................................."...............................................................,.......................,.................................,..................................,....................................................................................,............,'....
1 Q.
2
3
4 A.
S
6
7
8
9 Q.
10
11 A.
12
13
14 Q.
HAVE MOST OF THE INORMTION, DATA, AN FACTS NECESSARY TO
UNERSTAN TH NATUR OF DEAL A AN DEAL B BEE TRATE AS
CONFIDENT BY AVISTA?
Yes. Th is unortate, as most of th confdential tring data necessa to understand
Deal A and Deal B are public an available on the FERC website as par of the PEC's
show-cause procee th cunated in its Mach 2003 PA02-o2 report Fina Report
on Price Mapulaton in Western Marets. Ther is therefore, no valid reason to
contiue to trat hirica trg da as confideti.
WHAT IS THE DIFFERECE BETWEN TH NATUR GAS TRASACTIONS
OF DEAL A AN DEA B AND NORM NATUL GAS TRSACTIONS?
Thre ar at leas the distnct asec of the Dea A and Deal B tranactions th ar
pecul. The fist dinction is that the Dea A and Dea B tres were finacia as
oppose to physical transactions.
16 A.
15 PHYSICAL TRANSACTIONS?
WHAT is TH DISTICTON BETWE NA11 GAS FIANCIA AN
17 quatity of natu gas at specifed prcig, tes ~d conditions. In physical gas
A physical traction is the more nonnal an common purhae of an acua, physical
18 tracons, ther ar no winners OT losers. The buyer receives a specifc quatity of gas
19 at agreed upon prcing ters. The seller recives a payment for providing the physical
20 gas to the buyer.
21 A financial nal gas transaction involves no actua exchnge of physical gas.
22 Insead, a financial dea is agrd upon by buyer an seer in which the buyer bet tht
23 futu gas price wil increa, while the seller bets that fu gas prces wil decase.
DIRCT TESTIMONY OF DEN E. PESEAU . 16
IPUC Cas Nos. A VU-E-64-1 and A VU-G-01
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19 Q.
20 A.
21
22 Q.
23
24
25 A.
26
Dependig upon the :f monly movement of ga prices, the loser, or th
counte on the wrng side of the bet wrte a monthy check or "settes" with the
other par. The PEC re just referenced defies finacia gas sws silar to Dea
A an Dea B as:
In a swap, two counares execute a trde in which th buyer pays a
fixed, known price for some notional quatity of gas and the seller pays a
price that wil var with the maket price (generly based on some ageed
upon price indx). which will only be known later. Thus, the buyer in a
swa trsacton is goin long - ma a be that the market prce wil
rise - an the seller is beg tht price will fa.
(page II-51)
On the four days April 10, Apnll1, May 2 and May 10,2001, Avist Ener
entered into the finaia sws, Dea A and Deal B,on behaf of Avista Utilities that
we of unpreedeted length and lost over $62 milion for ratepayers. At no time durng
the te oftbese tw deals wee thes finacial tres "in the money," or profitable for
Avist Utilities. The deas were extaordnaly profitable for the thee seller
counteares.
WHO WERE 1l COUNARTI TO THESE lRSACTONS?
BP and Mit were the counterpares on Dea A. Increible as it may seem, Avist
Energ,y was the countear for De B.
WH WOULD TH SAM ORGANIATION SIMTANEOUSLY TAK
OPPOSITE SIDES OF TH BET ON TI DEAL B SWAP? ISN'T THIS A "ZERO
SUM GAM?'
The fact tht the PCA proted Avis Cororation is the .only th tht mae ths an
attactive trsaction for Avis Corporation. The PCA insulated the shaholde of the
DJRcr TETIMONY OF DEN E. PESEAU - 11
llUC Case Nos. A VU-E-04-1 and A Vl041
1
2
3 Q.
4 A.
S
6
7
8
9
10
11
12
13
14
15
16
17
18
19 Q.
20
21 A.
22
23
parent company by pasin. though to ratepayer the excess of the locked in hedged
natu gas prces over and above the acal maket prices tht exist at the time.
MIGHT lHS BE SIMLY A CASE OF BAD LUCK FOR A VISTA'S CUSTOMES?
No. The only maer in whch a fiancia swp can be consued is with a wining
buyer and a wig seller. The reason for entering a sw on either side is because one's
inormation on market prcing makes the nsk of this bet wortwhle. Agan, the only
possible reason for Avista Utilities to buy th long-te finacial Swap th it did was
beuse it was predctig gas prces would continu to incrase. If futue gas prces at
the tie the swap was entered were expectd either to reai at the then high levels, or to
decrease then entering th fied pnce swap could ony har the buyer. On the other side,
the seller A vist Energy appartly had information suesti that fu gas prices
were not goin to rise above th agree upon price per decathemi over the subsequet 17
month, or it would have been foolish to sell the swap. Unless Avist Energy based its
action on inormon tht prces would either reman at their hig levels or fall, it would
have been acg directy agt the be interts of its shaeholders. If natu gas
prices try were expectd to incras over the subsequent 17 month, the best action for
both Avist Utilities and A vi Enrgy would have bee for A vita Utilities to buy the
fied-price swap frm a less inormed counterp.
is THERE ANHING ELSE UNSUAL ABOUT AVISTA CORPORATION'S
DECISION TO MAKE TH SWAP?
Yes. At the time, A vist Energy brokered all of the natural gas and electrc tr mae
for th benefit of Avista Utities. Avista'sjustfication for ths practice was that Avist
Energy's continuous maket parcipaton provides it with maket inights and knowledge
DIRCT TESONY OF DENNIS E. PEAU . is
IPC Case Nos. A VU-E-1lUd A VU.G-4-1
1
2
3
4
5
6
7
8
9 Q.
10 A.
11
12 Q.
13
14 A.
15
16
17
18
19
20 Q.
21
that the utty division does't have. Avista Energy's role as a broke for the utty
division placed it in a fiduciar position that reuied it to diclose the fact th it
considerd Deal B (and by implication, Deal A) to be a bad deal for Avist Utilities. If
A vist Ener did disclose tht fact and the additiona fac th it was tag the other
side of th sw, it wa obvously imprden for Avista Utities to proce with swaps
tht th par with superior knwledge regaed as foolish. If A vist Energy did not
dilose its role, then it violate its fiduciar reponsbilties. and that alone would be'
grunds for diowing the cost of both deals in rate.
WHT WAS TH RESULT OF THE DÈAL B SWAP WITH A VISTA ENGY?
The result wa tht A vist Utilities imediately began monthy transfers of wha tued
out to be iiUions of dolla to Avist Energy.
HOW COULD 1lRE BE AN IMMDIATE TRASFER OF CASH? I THOUGHT
THE SWAP WAS FOR GAS TO BE DELIVRED IN THE FUT.
The immedate impact occued because of the way fiancial tres such as this ar
setted. As I stated ealier. swaps lik this ar litealy bet on the diretion of prces.
Consquently, thy settle monthy baed on the futus prce of gas for the time period
covered. In any month in which th fus price is less than the fixed prce. the buyer
(Avista Utities) los his bet an must cut a check to the seller (Avist Energy) for the
differenc. 1
WHT is TH ULTITE SIGNIICANCE OF THE WAY THE TRES AR
SETTLED?
1 Avi converd Deal Ð to a physical purchas at an equivaent fied pri on Jwi 20,200.
DIRCT TESTIMONY OF DEN E. PESEAU . 19
IPUC Case Nos A VU.E-1 an A VU-G041
..................n....'.......,........,..........,.................,.,.................,......................._......._............__..........................._...............'...n.....................................,................................,...................,...,...................
1 A.It explai why the Commsion realy ha no chice but to disalow Deal B. Any other
2 decision would prvide Idao utiities that have a PCA or PGA with a blueprint on how
3 to rad rapayers' pockets for the benefit of shholders.
4 Q.HOW DOES AVISTA UTIITIES AITMPT TO JUSTIY IT DECISION TO
5 ENER INO ''BUYS'' IN BOTH DEAL A AN DEA B?
6 A.Avista witess Mr. Laer discusse these tw deals (acty four tractions) in
7 pages 29w56 of his testony. The attptedjustfication, whle sometimes repetitive, is
8 outlined as follows: Deal A and Del B were mae becus:
9 1.Avist wa in an elecc reource deficit or a "short-posti~" durg the hedge
10 perods. (pp. 3 lw32, 37-40, 42-47)
11 2.The high hedge prces of Deal A and Dea B still comp favoraly to forw
12 maet prices of electrc purha at the tie. (pp. 32-36)
13 3.Electc maket prices in Januar.May 2001 were high, and federa opposition to
14 prce caps sugge no relief in marke prices. (pp. 40-42, 41-42)
15 4.The 36 month and i 7 month duron of Deal A and Deal B were not unusua ters
16 for company hedges oftms sort. (p. 48w52)
17 S.The company did not exec tht forward natul gas prices would decline as they
18 did. (pp. 52-53)
19 6.The tes orDea A an Deal B were consistnt with maket conditions on Aprill 0
20 and May 10. (pp.53-54)
21 Q.WOULD TH DEFICIT ELECTRC RESOURCE POSITION IDENTIFIED BY TH
22 COMPANY JUSTIY BUYG FIANCIA HEDGES LIK DEAL A AN DEAL
23 B?
DIRCl TEIMONY OF DENNIS E. PESEAU - 20
¡PUC Case Nos. A VU-E-04-1 and A VU-G04-1
1 A.No. I fist wa to ma clear that Potlat does not want in any way to discoure
2 apprpriat resource acquisitions to manta the reliabilty of service to cusmers.
3 However, I am quite swnsed tht the company teony in ths red sugges that
4 somehow De A and Deal B in any way assis in covenng a resourceshort position.
5 Q.WHY DO YOU INDICATE TIT DEAL A AN DEAL B DID NOT ASSIST
6 A VISTA IN COVEG ANY RESOURCE DEFICIT?
7 A.Finial fixed-fot-floatin swaps such as Deal A and Dea B never prvide for any
8 physica quatities of natul gas. Again, Deal A an Dea B ar strcty the ta of
9 "price positions" between two paes, a buyer and seller. For example, if! thought th
10 nat ga prce were going to incrase in the near-term and I could locate a pary
1 i thnkg the opposite, I could buy a na gas fiial swap and reap gas or sufer
12 losses according to my acy, and never be involved with actu physica quantities of
13 gas.
14 If I need naral gas to close an electrc resoure deficit, I would need to enter into
i 5 disct physical gas contr as a buyer. Deal A an Dea B did not entitle A vista to
16 even a molecue of metane.
17 Q.IF A VISTA NEEDED ADDmONAL NATUL GAS SUPPLY TO COVER TH
18 PERCEIVD DEFCIT, HOW DID IT ACQUI SUCH SUPPLIES?
19 A.The company on March 13 and Marh 22, 2001, entered int 36 month and 17 mont
20 physical trdes for 27,658 and 20,000 d.cathens per day at maket inex-baed prces.
21 Thes tw gas contracts alone filled the need to cover the resour deficits discusse by
22 the Compay. Deal A and Dea B merly expressed the perceived dirction th natu
23 gas prices would ta over th eng 36 and i 7 month periods been the bettng
DIRCT TESTIMONY OF DENNS E. PESEAU -:n
IPUC Case Nos. A VU-E-4-1 aDd A VU-G1
...........~.... ......... ........-........ ........ ... ......... ........ - _.....-.. -........ .... ... ................. ................ ........... ..... _... ..... ...... ......... ...., ............. ........... ..... .... ......,... ...... ..... ... ...... ... .........-........ ......, ....... ,..........................
1
2 '
3 Q.
4
5
6 A.
7
8
9
10
11
12
13
14
15 Q.
16 A.
17
18
19
20
21
22
23
pares. The Common should reject any notion th these fiancial swps can be
peddled to customer on the bais of encing system reliabilty.
WHT DO YOU MAKE OF MR LAFFERTY'S DISCUSSION ON PAGES 32-36 OF
HIS TETIONY THT SUGGESTS TH DEALS WERE PRUDENT BASED ON
THE TH FORWARD MA PRICES?
The analysis at pages 32-36 of Mr. Laffer's testimony attempts to demonstrte tht the
varable cost of power produced by A vita's geneato would have bee below the
prdicted fu maet powe prices at the gas prices in Dea A and Deal B. That is,
Avis was predicting tha at the Dea A and Deal B fixed swap prices, buyng gas for
inter genertion would be cheaper th buying on the elecc makets. This assmes,
of course, that the exstig forw power prices at mid-Columbia represented a goo
predictor of actua prces in the fue.
Whle ths anysis is maematically corr, it hay demonstrtes that tle Deal
A and Deal B tr wer prnt
PLEASE EXLAI.
The anysis presented is tle stang point for an "arbitrage" trad. An arbitrge is the
simultaus buying and selling of fugible commodties in diferent markets in order to
mae an imedat, nskless profit. For clarfication of the proper use of Mr. Laer's
analysis I refer to th Coyote Sprigs 2 table at the bottom of page 32 of his temony.
The first row indicates tht the Dea B gas fixed price is $6.56 per decatherm and, at the
CS2 plants' heat rate, Dea B gas could produce electcity at a varable cost of
S46.06/MWh. The forward electric prces. accrding to Avista showe power prices at
tle tie of$126.75 and S105.38/M.
DIRCl TESTONY OF' DENNIS E. PESU - 22
IPC Case Noii. A VU-E-041 and A VU4.1
...... .......... ....... ............. ......... ........ .......... ..,....... ....~... .....~.... ............ ........... .................. ......... ,....... ,............ .... .... -... ...... .......... ................... ...... .............-.... ...... .......... .............................. .......................
1 A power trader faing th cirumstance would, if the marke held,
2 simutaeoùs lock in a buy at the $6.56 gas price and a sae at the $126. 7S an
3 S105.381MWh electc prces to insu a nskless profit equa to th dierece beeen
4 thes tw energy sae prices and the $46.061M the electrcity would cost to produce.
5 Th would be a raonal use of Mr. Laert's anlysis.
6 Q.DOES TH ANALYSIS PREEND BY MR. LAFFERTY DEMONSTRTE THT
7 DEAL A AND DEAL B WERE PRUDENT AT TI TIME FOR TI PUROSE OF
8 PROTECTING RATEPAYERS?
9 A.No. Unlike the arbitre cae where a certin outome (1he risless prfit) is locked in by
lOa conscious decision to forego possible upside and avoid all downside, the ope hedges
II ,conducte by Avistadid the opposite. Avista's hedges in esse locked in the downide
12 - by fixing ga prce at nea record levels for up to 36 month - and precluded th
i 3 ratepayers gettng any upside if gas prces reted to more norm histric levels.
14 Q.WOULD AVISTA ENRGY HA VB ENTD TI SELL SIDE OF THSE
15 HEDGES IF IT EXPECTED NATU GAS PRICES TO CONTI UPWAR?
16 A.Absolutely not. Doing so would have be a dict contction of mageìent's
17 fiducia responsibilty to shaholdes. A vista Energy mae a calculated bet tha the
i 8 very high natu gas marke prices could not be susned. By sellig Deal B to the
19 utility for prices that exceeded S6.00/decathen it stood to reap all th profit frm fang
20 prces. If prices simply remane at the thn high levels, A vist Energy stood to lose
21 nothg. Only if gas price incrasd fuer from these high levels, did it risk losing
22 money. The end resut is tht Avist Energy made an obvious be and reaped more th
23 $18 milion in benefits from its parnt utility.
DIRCl TESTONY OF DENNI E. PBSEAU - 23
IPUC Cae Nos. A VUpE-041 and A VUG-041
..................nu....................................................................................,.....'"....................................................................u........,..,......................................................................................................
1 Q.PLEASE ADDRESS MR LAFFERTYS DISCUSSION ON PAGES 4042
2 REGARING TH PRUDENCE OF THEE TRNSACTIONS.
3 A.Beginnng on line 17 of his page 40, Mr. Laf sugests that a prnt pern would
4 have viewed th high wite prices of20OO.2001, an th feder goverment's position
5 agint th implemention of price caps, as reasons to "go long" with the natu ga
6 ' hedges. I have jus two short comments on th pomt
7 First, th prudent man at Avista who wa buying the fixed-price hedge on behal
8 of the utility wa the sae man who wa selling it on behalf of Avista Energy. Takg
9 simultaeous and opposite positions on the sae trction cat each be deemed
10 prudent. The sam maket obsetion of high prices and prce caps could not have led a
11 single individual or committee to opposite conclusions regarng th futu near-term
12 trnd in gas prces.
13 Second, other utilities and maket paricipants in the wester U.S. observed th
14 same maket phenomena discussed by Mr. La and did not tae long-term price
15 positions th anticipated fuer ga price incrases.
16 Q.PLEASE DISCUSS MR LAFERTY'S TESTIONY ON PAGES 48-52 THT
17 SUGGESTS TI T TI 36 MONTH AN 17 MONT HEDGES ARE COMMONLY
18 MAE BY THE UTILITY.
19 A.Mr. Laer's discussion here mvolves only physica resource acquisitions not fmacial
20 hedges. I cey agr with him that any resource portlio should have varous short
21 medium, and long~term resource. In ths Jight, I do not challenge or tae issue with
22 A vista's enteg into its Mah 13 and Mah 22 long-ter phsical gas pure
23 contr, as I previously note.
DIRCT TESTIONY OF DENNIS E. PEEAU - 24
IPUC Case Nos. AVU-E-04-1 audAVU.G-D4-1
.........................................................O¥................................................................................................................... .'._....'.............................................................................................,..............._...
The issue here, of coure, is th A vist took an unprecedente lon-term prce
2 view in the fonn of finacial hedges and, in combination with its subsidi A vist
3 Energy, Avista Corporaon, took both sides of the trsaon. Mr. Laert is silent on
4 these points.
5 Q.HAS AVISTA EVER. TO YOUR KNOWLEDGE, ENERD INO FIANCIAL
6 HEDGES AS LONG AS THE 36 MONlH AND 17 MONTH TERMS OF DEA A
7 ANDDEALB?
8 A.No. hi respnse to Potlatch's data reest, Avista provide a lis of al ret financial
9 hedges and fixed price contrs. Of th 67 fixed-price tranactions provided, the
i 0 overhelming majority of the contrac were for te of 1-3 months, with a few with
1 i terms of one year. Only the Deal A and Deal B tractions were for such long perods.
12 I conclude tha it is not Avist's norm buness pracice to ente into long-term pnce
13 hedges.
14 Q.HA VB YOU REVIEWED OTH DATABASES FOR INORMTION TO
15 DETERMIN WHTH mE 36 AND 17 MONT TERMS OF DEA A AND
16 DEAL B AR COMMONPLACE IN TH INUSTRY?
17 A.Yes. In conjunction with its investigation of electrc and na gas price mapulation
18 in weste U.S. markets, th FERC compiled masive dabase regardíng both physical
19 and ficial natu gas trs. As a check on the frequency of long-ter fmancial
20 hedges, I reviewed th FERC data fie for al natura ga financial hedges that we
21 entered into durg May 2001, the sam period as Deal A and Deal B.
22 Accordin to the da base file, there were 37,472 such transations durng May
23 200 i. The huge preponderace of these financia hedges was for th immediate month or
DIRCT TESTONY OF DENNI E. PESEAU - 25
LPUC Cas Nos AVU.E-041 aDd AVU-G-01
..........................................................................................................................................__...'..................................................................................................................... ...._-.-.........,.-..........._--..
1
2
3
4 Q.
5
6 A.
7
8
9
10
11
12
13
14
15
16
17
18 Q.
19
20 A.
21
22
quaer ahea althoug some we for quarly i*ods endig as late as Deceber
2002. I found no othr financial trades tht extended as long as the 36 and 17 month
te contned in De A and Deal B.
PLEASE ADDRESS MR. LAFERTY'S TEST!0NY THAT TH DEèLIN IN
NATU GAS PRICES WAS UNORESE~LE.
Mr. Laert's testmony on paes 52-53 sttes tha "the Compay" did not expect tht
forward natual gas prices would decline, as of coUre they did (page 52. lines 3~6). I
canot from the context of the stateent aser just what ''te Compay" is. Cey,
Avist Energy expeced a decline in nat gas p1ce. or it would not have sold the fied
,
prce swa.
I
Furer, Mr. Lafert's explanation does nqtjust the utity buying the swa.
As I exlaied ealier, buying the fixed-prce swap only gave the utity protecton from
, fuer increes in gas prices, not from the then existing level of high prices. Mr.
Laerty expla ony tht "... the Compay expctd the price for natal gas would
remain high for some time into the fu..." (page 52, lines 5-6). He does not mae the
arguent tht the Company exctd gas prces to contiue to increas, which would be
the only legitimae reason for th swaps.
WERE TH TERM OF DEA A AN DEAL B CONSISTE WI MAT
CONDmONS ON APRl 10 AND MAY 10,2001, AS MR. LAFTY ARGUES?
As I have prously indicated, ther wer apparently no other natul gas hedge
tranactions occurng that wer comparble to Dcal A and Dcal B. The references Mr.
Lafert makes to forwd prce cues at th tie ceainl is no indication of wht an
DIRCl TEIMONY OF DENNIS E. PESEAU .26
IPUC CalC Nos. A VU-E-4-1 and A VU04-1
................................"......................................................,............................,.....,.. ....-...-'.............,...,.........................................................,.......................,..................,........,.................................
1
2
3 Q.
4
5
6 A.
7
8
9
10
11
12
13
14
15
16
17
is
19
20
21 Q.
22 A.
23
ar-lengt buyer and seller might agre upon for ficial hedges of up to 36 month in
len.
WHT is YOUR RECOMMATION WI REPECT TO TH FIANCIAL
LOSSES CLAMED BY TH UTTY IN CONJUCTION WITH DEAL A AN
DEAB?
The fiancial losses incued by the utilty in Dea A and Dea B are sumzed in my
Exbit No. 202. As of March 31, 2004, the cumulative losses to the utility on th hedges
were $62,446,000. Thes losse represent the differnce beteen what the utiity would
have pad for natu gas on the ma (absent the hees) and the high fixed gas prce
tht it agr to pay by virtue of the hedges. The market prices for ga ar shown for the
Malin receipt point, and ar compared to th weighed average price of the heges,
labeled "Averge $/dt." For Deal A, the cumulative finania loss wa $44,175,600. For
Deal B, the cumulative loss wa $18,270,400.
Since De B involves self-deaing and a dit trfer of the utility's losses to
sharholder profits, the enti $18.3 milion must be dilowed, adjusted of cour for
the Idao jursdiction sha and for the PCA te peod. Dea A did not involve self
deain, but it wa ceiny imprdent and it is fuer sus due to the unrecened
term of 36 months an the high locke in price. I believe it should liwise be
disallowed. But if the Commssion for some reason reject ths proposal, I propose, in
the alternative, a lesser adjustment based on a more normal hedging strtegy.
PLEAE EXLA TH LATI RECOMMATION.
Dea A repreent two hege contracts of 10,000 decthenns each for a penod of 36
month. Th naed coun pares to th Del A contts ar private entities with no
DIRCT TESTIMONY OF DEN:E. PESAU ~ 27
IPUC Case Nos. A VU-E-L and A VU~G-4-1
......................................................................................................................................................................................................................................................................,.. .............."..-.-......,.,.,.
1 appart lega connection to Avista. According to the Company's repons to Potlath's
2 data requests, A vista did not have either of these entities "sleeve," (conduct the tre for
3 Avista Ener's benefit) the traction. Thus, ther wa no apparent enchment of
4 Avi's shaolde. But De A wa neverteless an imprudet $44.2 milion hedge
5 given its dmation and the fact th it wa put on contr to Avista Engy's position.
6 I base my adjusent on Avista's norm hede stregies for all its other fied
7 price gas purchaes. As I std earlier. Avista normally hedges for gas deliveries in
8 ensuing seaons and occasionay for peods as long as one year. If A vist had followed
9 its normal hedng stttegy it would have avoided the disasus 36 month Deal A fixed
10 price of S6,45/decatherm.
11 Q.HOW is THS INORMATION USED TO CALCULATE AN ADJUSTMENT FOR
12 DEAL A?
13 A.My revew of Avist's confdential information on other hedges reveals that Avista's
14 normal hedges were established approximately six month pror to a sean (November.
15 Mach or Apri-0etber). I threfore usd the Mali natual gas contr prices in effec
16 si months prior to eah upcoming seon as a bas price. For example, May 1,2001
17 prices were used for the November 200 1.Mar 2002 season. These prces are then
18 subtacted frm the Deal A price. The results ar sud in my Exhbit No. 203.
19 Q.
20 A.
WHT DOES EXHIT NO. 203 SHOW?
Th exhbit indicates th ü Avista ha not enterd into Dea A and inad hedge in
2 i the same mar tht it wa hedgi other natural gas purchas in the same tie frame,
22 gas cost would have ben '30,365,240 lowe. I altertively propose tht, should the
23 Commsion not dialow the enety of the Deal A cost, it should disallow $30.4
DmECI TESTIONY OF DENIS E. PESEAU . 18
IPUC Case Nos. AVU-E-041 aDd AVl1
..........................n............................................u...................................,.............................................................................................................................................'.......................
millon of Deal A costs, adjuste for both the Idao jursdction as well as th peA test
2 period.
3 The Tes Year Mismatch
4 Q.YOU EARIER STATED THAT AVISTA'S CASE CONTAIS A MISMATCH OF
5 REVENS AND EXPENSES. PLEASE EXLAI WHT YOU ME BY THE
6 WORD "MISMATCH,"
7 A.Avista caculates its tes year revenue in a sthtoi maer. Test year revenues'.
8 const of2002 ac figws, "normzed" for wether and other stadar Commission
9 appved adjustnents. On the other side of the ledger, however, expnses and rate base
10 are treated in a much differet maer. Avista pro form increases in selected expen
11 items, such as pesion, insuce, and labor cost, to 2004 levels. A vi also includes in
12 rate bae a number ofprject th were plaed in serce afer the tet year, as well as
13 constrction work in progrs that is scheuled for completion in 2004. These
14 adjustents produce operang and maintenace incres of approxiately $5.4 milion,
15 rate bae additions of$54 milion, and associad dereiation increes of $2.3 millon.
16 The net effect is a mismatch of2002 reues agait year-end 2004 exes and rate
17 bas.
18 Q.is THIS AN ACCEPTABLE RA TEMAG PROCEDUR?
19 A.No. For unown reasons Avista chose a 2002 te year, rather th 2003. Havi made
20 that choice, it should not be allowed to unlatrally alter the test year relationship beteen
21 revenues. expenses and rate base. It is a fudamenta principle of regultion tht a
22 utlity's rate base and expenses should be'matched agait revenues for the sae period.
23 Avist's pro fonn reults clealy violate this prciple.
DIRECT TESTONY OF DEN E. PESEAU "29
IPUC Case Nos. AVU~E-041 and AVU-G-1
........;.... ........ ......... ......... .... ........ ......... ........ -......." .-...... ..._...... .._...... .......... ..... ... ...... ........"" ........" ..... ............. ..... .........." .... ..............~........u.......u.............~.........u... .......................""".. .................... ....
Q.AR YOU SUGGESTIG PRO FORM CHANGES TO A TEST YE BASE CASE
2 SHOULD BE REJECTED OUT OF HA?
3 A.No. Addin known and meaable chages to a test year bae case is a legitiate
4 reguatory tool, but it must be used with exe cawon beus of the high potetial for
5 abe. In a rate cae, utilies have every incentive to idenfy changes tht incre the
6 reenue reuiement, but no incentive at al to find revenue enhcing chanes.
7 Consequetly, it comes as no surrise that all of Avist's proposed known an
8 measurable chanes produc an incree in revenue requiement. These chages should
9 either be reject or accmpaed by a corresponding adjustent to reenues.
10 Q.CAN YOU PROVIDE AN EXALE OF THE TYPE OF KNOWN AND
11 MEASURALE CHAGE TIT SHOULD BE ACCEPTED?
12 A.The classic exaple is a post.test yea chage in ta rates. Pluggig the new tax rates
13 into the reveue requireent cacultion does not ditub the relationshi beten test
14 revenues and expenses and is obviously equitable.
15 Q.WHAT RULES SHOULD BE APPLIED TO POST-TEST YE KNOWN AN
16 MEASURBLE CHAGES?
17 A.Post.test year expense and rate bas adjusents should only be acceptd when they are
18 in fact try known and meaurble. In order to quaif, a proposed adjustment mus be
19 virtaly cerin to occur, and its revenue reuiment impact must be precisely and
20 reliably quatiable. Fuenore, thre mus be some limt on the tie interv been
21 the test year and pr form adjustmens.
22 Q.AR A VISTA'S PRO FORM ADJUSTMS CONSISTET WI THE RULES
23 YOU HA VB JUST DESCRIED?
DIRCT TESTIMONY OF DENNIS E. PESEAU - 30
IPUC Case Nos. A VU-E-..i and A vu-Go..i
No. In the case of its pr forma expense adjusent) the time lag beween the 2002 test
year and adjusents based on 2004 data or projections maes thes adjustments
inequitable.
WHY is TH TI LAG IMPORTAN
For most utiities) exenses tend to increae every year. but this is offset in whole or in
par by effciency improvements and load grwt. If this were not so) utlities would
automatically fie rate caes every yea. Avista's own rate cas histry nicely ilustrtes
ths point. Its las rate case occurd in 1998, and the one before tht wa sever yea
ealier.
Avista's pr forma exene adjustents for items like incased labor) ince,
and sinular cost ar simply 200 budget estimates. It is absolutely inppropriate to
match these exenses agaist 2002 revenues beuse normal load growt wil recup
some or all ofthese cost. The Conuion should either reect the 2004 adjustents or
impute revenue increases to the 2002 test yea to correc this mistc
AR AVISTA'S PRO FORMA ADDmONS TO RATE BASE SUBJECT TO TIE
SAME OBJECTIONS?
Only in par. Additions to Avist's generati caty were added to th power supply
model, and ths presumably adds revenues or decreases exenss as a result of the pro
form plant additions. I have not attemted to conf tht this modelig chae wa
properly implemented. but I assume Stawill do so. If the implementation was corrcty
done, I have no objecon to the pro for adjusents as such, although I have
proposed the removal of Coyote Sprigs 2 on other grunds, as discusse above.
DIRCT TETIONY OF DENNIS Eo PESEAU - 31
IPUC Case Nos. A VU-E--1 and A Vl04i
..... ..... ..............-....... ........ .......... ..... ........... .....~.. ...... ...,'........................... .....,......... .,.. . ..... .... ........... ..,.." ........ ,....~..................,......... ..... ............ ........... .....,....... ....... ................,....................... ......
1
2
3
4
5
6
7
8
9
10
, 1 i
12
13
14
15
16
17
18
19
20
21 Q.
22 A.
23
24
25
26
27 Q.
But there is no siilar revenue adjustment for the $26,300,000 in 2003 and 2004
transsion projects A vista pro form into th rate base, even thugh these additions wil
alo prduce either additional reenues or opetiona savigs. Like other busiesses,
utilities generally do not ma additional investents or increse their expenses unes
they can generte additiona revenues and profits, eithr by servng additional customers,
or by cuttng costs or increasng magins. There is no reon to assume ths is not the
cae here. The projected expnditues A vista ha identified must be prsued to
generate additional revenues or other benefits that would offset their costs, in whole or in
pa. Avis has mad no atempt to identi thes offsettng benefits.
As the Commssion pointed out in its recent order in the Idao Power rae case:
Generally speang, the Commssion expects al utilties to atempt to identify
exnse savin and revenue prducing effects when proposing rate base
adjustments for major plant additions. It is unfai to raepayers to assume tht the
investment in the plans win not incre Company revenue or decreae
Compay expenses in.the fu. Furer, it is uneaonable to expt the
Commssion to allow ful recovery,ofplant investment as if the plant ha been in
operaion the ful year without a correspondi adjustment to revenues and
expenes.
Order No. 29505, p. 7.
HOW SHOULD TIS MISMATCH BE CORRD?
There are basicaly th alternive remedes available to correc ths rate base mismath.
The firs would be to reverse the pro form entres and properly match test year averages
on both sides of the ledger. The second alternative is to update reenues to th 2004 level
in the same maer as rate bas and expenses. Finally, the thrd altertive is to employ
th rate base adjusents the Commsion adopted in the Idaho Power ra cae.
DO YOU HA VB A PREFERENCE BETWEN nmSE THREE ALTERNATIES?
DIlCT TESTIMONY OF DENN E. PESEAU - 32
IPC Case Nos. A VU-E-U4-1 and A VU.o4-1
.................................... ....... ............................... ...... .......... ........ .... ... .....~......... .............. ....................... ....... ............... ......... .......... ...........-.....-....................... .......... ..... .......... .......... .........................
2
3
4
5
6
7
8
9
.10
11
12
13
14
1.5 Q.
A.A! I have stte in other cas, I th anuaizg revenues to 2004 year.end levels is the
preerable cour for two reons. Firt, it is much simpler to anualize reenues than to
back out pro forma adjustments from numus expense and rate base categories.
Moreover, adjusti revenues pruces a more forard.lookig resut than reering the
expense and rate base anuaIizons.
I reognze, however, th th Commssion adopted a third course of action to
corct simla mismache in the recent Idao Power rate cae. In th case, the
Commsion adopte a proxy for incrased revenues and reduced expnses. Whle the
Commssion stated that it did not necssary regar th adjustment as precednt for
futu cases, the circumstaces in ths cae are ver similar to the Idaho Power cas. I
lack the preci data to caculate a simar remedy of the mismtch in tls cae, but I note
that in the recent Idaho Power decision the Comiion adjustd tota revenues on the
order of 5 percent of the rate base additions.
Cost of Serviee Issues
17 A.
16 RESULTIG RATE DESIGN?
HAVE YOU REVIEWE AVISTA'S COST OF SERVICE STUDY AND mE
18 the pas with a major excetion desribed below. I recmmend two improvements to
Yes. The stuy sponsored by Ms. Tar Knox generally follows the methods appoved in
19 alocator contaned in the Company's sty.
21 Q.
20 Avista's Proposed uFour Factor" Alocator for Common Costs
22 APPROVED COST OF SERviæ METODOLOGY USED IN CASE NO. WWP~E-
DOES WITNS TAR KNOX PROPOSE A CHGE FROM TH PREVIOUS
23 98-111
DlREcr TESTIMONY OF DENNI E. PESEAU . 33
IPUC Case Nos. A VU.E.o4-1 and A VU...i
2
3
4
5 Q.
6 A.
A.Yes. As noted on Pages 6v 7 of her direct testiony, the Company proposes to allocte
Ucommon costslt on the bais of four factors: direct O&M expenes, diect labor, net
direct plant, and number of customers. Prousy, A vista ha allocate these common
cost to customer grups with a 60% cumer/40% energy allocation factor.
WHT ARE "COMMON COSTS?'
7 but whch are left over afr most diretly assignble costs have been identified and
Common costs are tyically defined as those costs necar for the utlity to fuction,
8 "fuctionalizedlt to production, trmission, distrbuton or cusomer accounts. These
9 reai common costs include gene and common plant investent cost and
i 0 adinsttive and general expenses. Offce buidigs, fuiture, transporttion
11 equipment, cert inventories computer costs and a portion of magement saaries
13 Q.
i 2 typicaly comprse commn costs.
AR TH SPECIFC FOUR FACTORS USED BY MS. KNOX TO ALLOCATE
14 COMMON COSTS PARTIALLY VALI?
15 A.
16 allocate common costs. However. the metd Ms. Knox uses to calculate the act
Yes and no. Yes, the four fators, if corrcty defied, are legitite bases upon which to
17 weights of the four-factr allocations has a serious flaw, one that ren her calcuations
19 Q.
18 higWy volatie and incorrect.
PLEASE EXLAIN.
20 A.
21 common cost allocations:
In order to bettr explain ths issue, I list the propose four factors chosen for the
22
23
24
25
1.
2.
3.
4.
Dir O&M Expns
Dirct Labor Expenses
Net Dirct Plat Expenses
Number of Customers
DIRCl TESTONY OF DENN E. PESAU - 34
IPC Case Nos. A VUvE-041 and A Vl4-1
......................................................................................................-..........,........,..................................................................................................................................................................................
Th issue I raise involves only one of the fom facors - Dirct O&M Expenes. Simply
2 put, Ms. Knox fails to remove a porton of these dit O&M expense, an adjusent
3 that is necsary for th proper allocation of common cost.
4 Q.WHT AR DIRE O&M EXENSES?
5 A Dirct O&M exenes in A vist's cost of service study ar listd as FERC Accoun 500-
6 916 on pages 4-10 in Ms. Knox's Exibit 16, Schedule 2. For referece, the su of th
7 expenses in these O&M acounts is $97,699.000 (Line 369, Page 10 of 59, Exibit 16,
8 Schedule 2).
9 By using the sum of all the dollars in all of th O&M acunts, and thei
10 ailocators (energy, deman, custmer) as one of th four factors used, Avist and Ms.
1 1 Knox ar sugesting th common costs ar cad in a fashion similar to the caue of the
12 O&M costs. Prperly defined, O&M expenses fonn a reasnable meas with which to
13 alocat common costs, but Avist's O&M expene definition fals in ths regar.
14 Q.WHAT is TI BASIS FOR YOUR STATEME THAT AVISTA HAS
1 5 IMPROPERLY DEFIND ITS DIRET O&M EXENSES AS ONE OF THE FOUR-
16 FACTORS TO ALLOCATE COMMON COSTS?
17 A.Three distnct reasons suppo my conclusion th Avista's fir factor, the Dirct O&M
18 Expense, incorrectly allocat common costs:
19 1.Avista's O&M expene allocato is extremely volatile frm yea to year,
20 and common cost ar not volale.
21 2.Avista's anual common costs from 1998-2003 ar acly inversely
22 related to its defition of O&M expenes.
DIRCT TESTIONY OF DEN E. PESEAU - 35
¡PUC Case Nos. A VU-E-1 and A vu-Go+i
.......~..............................u.............................................................................................. .__....................................................... ............~.....................................,....................................................
2
3
4
5 Q.
6
7
8 A.
9
10
11
12 Q.
13
14
15 A.
16
17
18
19
20
21
22
23
3. A ststical regresion anysis support the conclusion that the conion
cost allocator usig Avista's Dirct O&M Expenes is vald it and only if,
variable ful and puchaed power exense ar removed.
Avista's Volatile Direct Expense Defnition
WHT is TI ISSUE WI RESPECT TO TH VOLATITY OF USING
AVISTNS DEFINITION OF DIRECT O&M EXPENSE TO ALLOCATE COMMON
COSTS?
Simply put, Avistas deftion ofO&M expenes includs fuel and purchased power
cost as an element from which the relatively fied common costs ar allocate. I offer
clea evidence below tht common costs simply do not var in any reation to chages in
ful and purchased power costs. '
APART FROM ACCOUNG AND STATISTICAL DATA, IS mERE A COMMON
SENSE EXLANATION AS TO WH COMMON COSTS SHOULD NOT BE
ALLOCATED ON TI BASIS OF FUL AND PURCHASED POWER COSTS?
Yes. As we ar all aware, fuel and purchad power prces have risen, fallen, and agai
risen by as much as sev hundr percent on a year-to-year bais. Ifwe assue; as
A vista has done, that common cost ar caused by chages in fuel an puchased power
costs, th we will be chaging the common cost alocator by as muc as seve huned
perent year-by-yea.
Anoter way of stang the misapplication is that A vista is implying th its
expenditu on offce buildings, fuitue, par inventories, vehicles, computers, offce
supplies, employee pension and beefts, rents and gener plat maintena can be
expected to var diretly with the recen huge swigs, both up and down in fuel and
DIRCT TESTIMONY OF DENNI E. PESEAU - 36
IPUC Case Nos A VU.E-04i and A VU-G-Ðt
. ..... ...... ..., ......... ..... .... ........, ........ ......... ....... .............. .... ..... ...... ......... ... .......... ..............~..... ......... .............. ......... ...... .......
purhaed power prices. (See Exlbit 16, Schedule 2, Pages 1 O~ 11 for complete list of
2 common (A&O) cost items.)
3 Q.DOES THS DISTORT THE COST OF SERVICE REULTS?
4 A.The distoron is huge, beause fuel and purchasd exnses frm year to yea comprise
5 the overhelmg majority of Dirct O&M expenss. For exaple, of th tota test yea
6 O&M expses of $97.7 millon (Exhbit 16, Schedule 2, Page 10, Line 369) $66.5
7 inion, or 68 percent of the tota is fuel an purchased powe expenes. The effec on
8 cusomer of allocag relatiely fid common costs on volatie fuel and pmcbasd
9 powe prices is to caus huge swings in the levls of common costs allocated to eah
10 customer class. These swings have nothng to do with the common cost of serv these
11 customer classes.
12 Q.is THRE AN EASY, COST.BASED FIX TO A VISTA'S VOLATILE AN
13 INACCURTE COMMON COST ALLOCATOR?
14 A.Yes, apa from the inclusion of ful and purhaed power exenses, the remaining Direct
is O&M Expense factor is farly indicatve of, and related to the nee to incm, common
16 costs. The easy fix is to simply reove the fuel an purhased power expenses and use
17 the remaiing non-fuel and purchased power O&M expenes as one of the four-factors
18 for common cost allocaor propose by A vista.
19 Avista's Histoncal Common Costs are Inversely Related to Fuel
20 and Purchased Power Expenses
21 Q.OTHR TH YOUR COMMON SENSE DISCUSSION, HA VB YOU ATTTED
22 TO ESTABLISH EMPIRCALLY THT A VISTA'S EXPENITUS FOR FUE
23 AN PURCHASED POWER DO NOT DIRCn. Y RELATE TO, OR CAUSE
24 A VISTA'S COMMON COSTS?
DIRECT TESTIMONY OF DENNIS E. PESEAU - 37
IPUC Cue Nos A VU-E-01 aDd A VU-G-01
.........,.....,...............................................................................................,....................................................................................................................................................................................-:.....
1 A.Yes. My Exhbit No. 204 is a grph of the recent histry of Avista's anl varation in
2 tota fuel an pured powe ex comparng them with Avista's ac A&O
3 (common) cost, 1998~2003.
4 Q.WHT DOES EXHffITNO. 204 SHOW?
,
5 A.Exhibit No. 204 confrm what we know to be tr - tht Avista's fuel an pured
6 power costs have vaed trmendously on a yea-to-year bais since i 998.
7 The exhbit also confrm the point I wa makin above, that Avista's common
8 (A&O) costs have been virtally consant sinc 1998. Use ofUie fuel and purhaed
9 power expen component with Avista's Direct O&M fa would therefore genrate
10 widely fluctating allocations of common costs to different cusmer classes. distortng
II the intent of a common cost alocator.
12 Statistical Relationship Between O&M aDd Common Costs
13 Q.WHT STATISTICAL VECATION DO YOU HAVE THAT INDICATES TIT
14 AVISTNS INCLUSION OF FUEL AND PURCHASED POWER EXPENSES IN ITS
15 COMMON COST ALLOCATOR is INCORRCT?
16 A.The use of formal ststcal anysis to prove th volatile, variable cost for fuel and
17 pured power are not corrlated with fied common costs may be overkill, but I
18 neverless offer a statistca regression anysis supprtg my arguents. The
19 statistica tests or "hypothese" I review also indicate th ful and purchased powe cost
20 should be excluded from the alocator usd to allocate common costs.
21 Q.PLESE EXLAI.
22 A.The regrsion analysis I perormed siply answer the question of wheer A vista's
23 incuence of commn costs is fudamentaly related to a defition of O&M expenses
DIRCT TESTIONY OF DENN E. PESAU - 38
LPC Case Nol!. A VU-E-1 and A VU-G1
.........................._...................................................................,......................,..................,..................u.....................,..'...........................,......_.........._..................._,....................................,............
1
2
3
4
5
6
7 Q.
,8 A.
9
10
11
12
13
14
15
16
17 Q.
18 A.
19
20
21 Q.
22 A.
23
tht includes or goes not include ful an purhaed powe expenses. As our goa in the
cost of serce sty is to idetitY th causative factors of common cos, we seh
sttistcally for the acunts mak up O&M exnss tht do, and those th do not,
case A vist to incur common costs. Then, in th allocation of coon costs to
customer clases, we use only those O&M accounts th do relate to, or "cause" common
costs.
WHT DOES YOUR STATISTICAL REGRESSION ANALYSIS SHOW?
The anysis shows that common costs ar much more related to, or "colated with,"
O&M expense tht have had fuel and purhaed power expenes reoved. The
regression anysis wa conducd for two different equaons:
1. Common Costs related to (O&M minus F&PP expenses); and
2. Common Costs related to (O&M with F&PP expenses)
where F&PP refer to ful and purchased power.
Exhbit No. 205 sumzes the results of regrssion for these two equations.
For completess, coon cos data were developed two ways: first measd as A&G
costs; second, as dollar levels of Avist's gener plant accounts.
HOW WERE THE DATA DERIVD?
Al data were taen frm the 2003 FERC Form I S, for A vista and the five other wester
electrc utlities lis in Exlbit No. 205. The other five utiities provide a
represtationa cross setion of similarly situated elecic utilities.
PLEASE SUMMARI THE QUANTITATIVE FINDINGS.
Regardless of wheter A&O expens or general plat is used as th measure of common
costs, the regrssion results strngly indicate that O&M expenss less fuel and purchaed
DIRCT TESTIONY OF DENNIS E. PESEAU. 39
IPUC Case Nos A VUE.04-1 and A VU-G04-1
.................................................................................................. ..........."...........................................................................................................................................................................................
1
2
3
4
5
6 Q.
7 A.
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 Q.
23
power expenes is a suenor allocator, compard with Avist's prposed chage of
including fuel an purhaed power expees. Ths analysis support the common sense
rening and grphic evidence preend earlier, and it demonsates that Avist's
proposed chane in these proceedings to include ful and purchas power expenses to
allocate common costs should be rejecte
HOW SHOULD COMMON COSTS BE ALLOCATED IN THESE PROCEEDINGS?
I believe tht the Commssion is left with two reasonale altertives. Firs the
Commssion could adopt in principle Avista's foiu-fator common cost allocator concept,
hut simply ord the Company to remove fuel and pursed power expnses frm the
one factor, Diret O&M Exp. In ths way, each of the facors in the foiu-factor
metod would closely trck common costs. I have parcipated in cost of servce stdies
in the past where FERC ha simlaly removed fuel and p'Led power expenses from
the Direct O&M Expens accounts.
Alterntively, the Commission could order Avi to cotiue to use the
priously apprved coon co allocator, wher costs we alocated 40% on energy
and 60% on customer coimts. The allocations resulting frm the two alternatives are
simlar in this case. My Exlbit No. 205 reflecs the cost of service resuts frm the four-
factor "Direct O&M less F &PP expes" method.
My recmmendation to the Commission is to us the four-facr Dirt O&M less
F&PP expen method.
Avita's Transmison Cost Allocator
DOES AVISTA'S COST OF SERVICE STUY CORRCTLY ALLOCATE IT
TRSMISSION COSTS?
DIRCT TESTIMONY OF DENNIS E. PESEAU - 40
(PUC Case Nos. A VU-E-041 and A VU-G-01
....................~........................n................................................................_.hn........................................................._.........................................._...................................................................~..........._.
1 A.
2
3
4
5 Q.
6
7 A.
8
9
10
ii Q.
12 A.
13
14
15
16
17
18
19
20
21
22
Transmision costs ar incur to meet pe demans, and ar therefore approrily
allocte to customer classes on the bais of ded (caacity) allocators. Avista's
proposed cost-of-serce sty allocates a significat amount of tranission costs, not
on demad, but on an energy basis. Ths is no longer defensible.
DID A VISTA'S COST OF SERVICE STUY IN WW-E-98-AA ALLOCATE
TRNSMISSION COSTS SIMARY ON A DEMA AND ENEGY BASIS?
Yes. Unlike the previous issue on the four-factr metod, the trssion allocation
issue I raise her clealy would require the Commission to modify its position in the
preous rate cae, and adopt the same methodology it recently approved in the Idaho
Power rate cas. But I believe the evidenoe supportng this chge is compellg.
PLEASE EXPLAI.
My proposal to allocate trmission costs strctly on a dema basis is based on thee
ditict propositions:
1. A vista's and viy all other trssion systms are planed, size,
an buil to meet maximum insttaeous, or peak demands,
2. Avisa's proposed deand/energy trssion alocator is inconsistent
with, and contrictory to, the sae transmsion system rates it has ha
approved, and indee charges, to wholesale customers thugh its Open
Accss Tramisson Tar ("OA IT").
3. The Commission has just weeks ago approved the demand allocator for
transmisson costs th I propose here in the recntly complete Idaho
Power genera ra ca.
DIR TESTIONY OF DENNI E. PESAU - 41
LPUC Case Nos. A VU-E-041 aDd A VU-G1
........................................................ .............._........_..........................................................................................................-....-...........................................,-................,...........................................
1 Q.
2
3
4 A.
S
6
7
8
9
10
11
12
13
14
15 Q.
16
17
18
19 A.
20
21
22
23
WHT is TH BASIS FOR YOUR CONCLUSION THAT A VISTA'S
TRSMISSION SYSTEM IS CONSTRUCTED TO MEET ITS PEA DEMA
REQUIREMETS?
Our fi has exaned syst plag methods and models for many years. For
generation systs, a hydr-electrc da bein a good exaple, constion cost ca be
incu to meet both demd and energy consideratons. In the Pacific Norwest, for
examle, we mow tht hydr genertion costs ar incd or "causedlJ not only by pea
demand reuirements, but also by the need to store energy. Generation cost are
routinely allocate to both ded and ener.
Trasmission syem, while thy obviously trmit energy, are planed for, and
the cost is causd by, the need to meet pe demands. Once the costs ar incu and
the facilties constcted, no additional costs ar inctUcd to tranmit energy. Thus, the
principle of cost-causion lea us to alloca transmision on the basis of deand
(capacity) usge only.
HOW is AVISTA'S PROPOSED DEMNDIEERGY TRNSMISSION
ALLOCATOR INCONSISTET WI TH TRASMISSION COST ALLOCA nON
AN RESULTIG RATE IT HAS IN PLACE FOR WHOLESALE TRASMISSION
USERS?
The open acce policies implemented by FERC some yea ago, as we mow, requi
A vista and oth utiities to fie and matai OA ITs, th rates of whch mus be based
on cost of serice. I have reviewed the cuent A vista OA TT an detrmned tht the
Company allocates its trsmission syste cost (the sae system contaied in its
prsent trnussion cost of servce) not on the basis of the demd/energy alocr
DIRCT TESTIMONY OF DENNIS E. PESEAU - 42
IPUC Case Nos. A VU-E-4-1 and A VU-G-l1
..-.................~.............................................-..............................,..................0-.,..................................................................................................................................................................................
1
2
3
4 Q.
5
6 A.
7
8
9
10 Q.
11
12
13 A.
14
15
16
17
18 Q.
19
20 A.
21
22
23
proposed in ths genera reta rate cae, but raer on the same demand basis tht I am
proposing her. There is no resonable jusficaon to have two differt sets of
transmission costs and rates for the same identical systm.
HOW DO YOU KNOW THAT TH APPROVED OArr RATE is BASED ON A
DEM-0NL Y ALLOCATOR?
In my Exhbit No. 207 I attch a copy of the relevant pages of A vist's prnt OA TI.
The raes posted there ar denved strctly on a lfper kW" or demand basis. TI indicates
that the OA IT rates and the trmission cost contaned thern ar based solely on a
dema allocator.
DO PROBLEMS ARSE FROM ALLOCATIG TH SAM TRSMISSION
COSTS OF SERVICE ON TI BASIS OF TWO DIFFE ALLOCATORS, AS
AVISTA is PROPOSING?
Yes, obviously so. First, the deman method is corrct and the deand/energy is not.
Therefore, one set of rats is correct and the latter is not. Th is no sound reon why
identcal ret or wholesale trsion customs should hae their respecive cost
allocaons and therefore their rates differ for the same usge. This is disparty is not only
ilogica; it is also potealy dicnmintory.
WHT TRSMISSION COST ALLOCATION METIOD DID THIS COMMSSION
ADOPT IN TI REEN IDAHO POWER GENER RATE CASE NO. IPC.03.13?
The Commssion based its rate design on Idaho Power's basic cost of seice sty,
which allocate the Compay's trmission costs on the bas of demand only. Idaho
Powes approved OA rr rates are also based on demand-only trsmission cost
allocators.
DIRCT TESTIMONY OF DEN E. PESEAU - 43
IPUC Case Nos. AVU-E-4-1 and AVU-G-ol
..........................................................,..................,.........................................,...................................................................................................................................................................................
HAVE YOU PREPARD A COST OF SERVICE STUY THAT INCORPORA'rS
THE CHAGES YOU RECOMM?
Yes. Exhbit 206 is a summar of th results of my cost of serce stdy incorporag the
proper 4~facor and transmion capacity allocator. Wle the chages to the alloctions
to the varous cutomer claes ar not dramtic, they are significat and necessa to
properly capte cost of serce.
WHT DOES YOUR COST OF SERVICE STUY SHOW wrm RESPECT TO TH
PRESEN CONTRUTIONS THT DIFFER CUSTOMER CLASSES AR
MAG TOWARD RESPECTIVE COSTS OF SERVICE?
The sumar resuts incate, consstent with the conolusions of Avist's cost of seice
stdy, tht reidenti cutomers, Schedule i, and large generl serice customers,
Schedule 25, are receiving substatial subsidies frm all remaiJUng cusmer clases,
including Potlatch. Page i of Exhbit 206 shows tht the residential and gene sece
customer classes' rats generate raes ofre that ar significatly below the syste's
average rae of retu thus indicag tht other clases' rates are set to high in order to
make up the shortal.
HOW SHOULD THE COMMISSION DEAL WITH THE ELIMATION OF THESE
SUBSIDIE?
In the recent Idao Power gener ra case I testified that a huge subsidy, in tht cae to
the irigaton pumping class, need to be systmacaly an unuivocally reduce to
ze, necesitatig a large increas to the irgator. The sam principles apply here,
althoug the levels of subsidies to the residenti and genera servce customer ar not so
large as in the Idaho Powe cae. In principle, I believe thes subsidies should be
DIRCT TESIMONY OF DENN E. PESEAU - 44
IPUC Case Nos. A VU-E-1sDd AVU~G-i
...............................................................................................................................,............................................H....................................".................................................................'......".............
1
2
3
4
5
6
7
8
9
10
11
12
13
14 Q
15 A.
"
16
17
18
19
20
21
22 Q.
elinaed imedatly. Howeer. I am alo awa the Commisson has expressed
concerns abut the "rate shock" tht could result from ver step increas for a
parcul cusmer class.
Accordingly. I propose in th proceedings th if the overll aproved incree
is ten pecent or less. all cusmer clases' should be moved to fu cost of seice. If the
increase is grater than ten percent. the Commission order should order residenial and
large general service rate moved at leat haay toward rate of retu paty, with two
anua autmatic adjustments therer to close the remainig cos of servce gap.
Under the latter alternative, the other customer classes (Schedules 1 1 - 12, Schedules 21-
22, and Potlatch) would contiue to pay a subsidy in the nea term, but would receive
assurces th the rema subsdy would be eliminate over the next two year. Ths
, is. I believe, more th fair to the subsidize cutome classe.
Rate Desig Issues
DO YOU HA VB AN COMMNT ON A VISTA'S RATE DESIGN PROPOSALS?
'Yes. My fist obseration is that Avista's proposal to include Potltch's Lewiston
Facilty (''Facilty'') in Tarif Schedule 25 should be reected. Becaus of the huge
disarity in size between the Facilty and the other Schedule 25 customer, it maes no
sense to include the Facilty in tht schedule. For cumers the size of the Facilty, the
Commssion ha always used seare taiffs for eah spcial contrac cuomer, and it
should do so in ths cae as well. The Facilty is approximtely thre times the si of all
the entire Schede 25 class.
is TH FACIITY IN FACT A SPECIA CONTCT CUSTOMER?
DIRCf TESTJMONY OF DENNIS E. PESEAU . 4S
IPUC Case Nos A VU-E-4-1 and A VU-G1
A.Yes. The A vist and Potatch powe supply ageement (UAgrementtt) is a unique
2 contrct th governs Avista's serice to only one cusmer- the Facilty. In tht
3 Agreement, the pares agreed to the teporar use of Schedule 25 mtes for service to the
4 Facilty, peding the next rae case. But Potlatch did not ag to become a Schedule 25
S cusmer. The Facilty has always been a "special cotrct cutomet' in the pas and the
6 Agreement clearly contemlates tht ths sts will continue in the futW.
7 Q.is IT DIFFICULT TO SEPARATE THE FACILIT'S COST OF SERVICE FROM
8 SCHEDULE 251
9 A.No. The A vista cost of serce stdy, an my own, already compute all cost of sece
10 elements for th Facilty on a std-alone basis, in recogntion of th fac tht the Facilty
11 is indeed a custmer class unto itself. Given this, the Commission should require Avist
12 to preserve these cost elements trating the Facilty as the cusomer clas tht it is. It
13 makes no sens to subseuently meld the Facilty with the much smaller Schedule 25
14 class. In orde to set mtes for the Facilty with the Schede 2S clasii, A vista in this
15 ca had to resort to major rate design changes in order to properly ase tht Potlatch
16 would not be overharged.
17 Creang a stad~alone rate schedule for the Facilty wil not afect th Facilty's
18 cost of serce or rates. It is simply a prentive meaur. The concer is tht in the
19 futue ths distiction could be blur in a subsequent stdy in a maner tht caus th
20 Facilty to pay costs for which it should not be accountale. The distinction between the
21 Faclity and the Schedule 25 cumers should be clarfied by placing th Facilty in a
22 separ ra schedule.
23 Q.DOES THIS COMPLET YOUR TESTIONY?
DIRCT TESTIONY OF DENN E. PESEAU - 46
ipue Case Nos A VU-E-041 and A VU.G-61
..............................................................n........................................................................................................................................................................................,..............'.......,............................
1 A.Yes. it does.
2
'.
DIRCT TEIMONY OF DENNS E. PESEAU - 47
IPUC Case Nos. A VU.£1 and A VU-G-U4-1
..................................................,....................................................................;....................................................................................................................................................................................
1
2 Q.
3
4 A.
S
6
7
8
9
10
11
12
13
14
Append A-Update to Dr. Avera's Analysis
WHT is TH CORR RETUR ON EQUIY RAGE USfNG DR. AVERA'S
METHODS FOR ESTIMTIG EQUITY RETUS?
i conclude that consistent aplication of the discounted cah flow (DCF) and ri
prmium meods used by Dr. Avera reduces hi recmmendatons as follows:
RQEMethod Aver EstmatenI Peseau Update
DCF
Risk Premium i
Rik Premium II
CAPM
10.4%
11.4
10.8
11.9
9.3%
10.8%
9.2% to 10,1%
10.9%
_n/ includes flotation costs of20 basis points.
15 of 10.4% to 11.9% and cery do not support a recommended ROE of 11.5%. See
Updates that are consistent with the method Dr. Avera utiiz do not supprt his range
16 Exhibit No. 211.
17 Q.
19 A.
18 AND ANALYSES OFFRED BY DR. AVE?
WHT GENRAL COMMENTS DO YOU HAVE REGARING TH TESTIMONY
Dr. Avera offers 70 paes of testimony coverng a nwnbe of topics. Twenty-four of
20 thes pages cover discussion of flotation cost and the quantitative equity retu metods
21 and estmates commonly considered by ths Commission. The res of the testiony is
22 concerned with genera and fudamenta ecnomic and fincial topics tht ar normly
23 and effciently taen into accoun by invesrs when bidding on an purchasin coon
24 stock and other assets. Financial intutions and investors know the finacial and
25 operationa chateristics of Avist ever bit as well as Dr. A vera and use ths
26 informon to mae form investment decisions. A well-known finacial principle is
27 that investrs are not normly, nor do they expect to be, compensted for nonmark.t or
DIRCl TESTIMONY OF DENN E. PESEAU - 48
IPUC Case Nos. A vu.E-o..i and A VU-Gi
.....,'....................n.........................................,.....,..................._.....'...,.........................,.....................".......,..............._..._.............,.......................',.............._.._....._.._...._................ ...._............._.......
company-specific risks th ar not systematic. Thes risks are diversiable and do not.
2 and should not for th bass of rate of re "adders." The methods of detg
3 cost of equity used by Dr. Avera and other in ths cas measure retus that ar
4 commenSlmte with siil risk-adjusted investments and should not be adjusd for
5 exogenous risks.
6 Q.PLEASE SUMMARZE DR. AVERA'S ESTITES.
7 A.Dr. Avera presents four quantative anyses of the cost of eqty for a "benchmark"
8 grup ofwestm elecic utlities from which he derives a 10.2% to 11.7% equity cost
9 rage. He presnts a discounted ca flow ("DCF'') anysis for a benchmark grup of
10 electc utilities in the western U. S., tw risk premium approaces, and an estmate baed
1 i on the capita asset pricing model ("CAPM"). From hi DCF analysis he estates that a
12 benchmar sample ofwestem electrc utilities requir a return on equity of 10.2% (page
13 45). Based on two rik premiu models, he concludes tht the cost of equity for the
14 respective reference samples of electrc utities is 11.2% (page 49) and 10.6% (page 50).
15 And, frm ms CAPM apprach, he derives a cost of equity estmae for the wetern
16 elecc utiities of 11.7% (pge 51). Bas on tht inrmaton, and an adder of 20 basis
17 points for flotation costs and addtional premum he argus ar required for risk speific
18 to Avista, he endorss an ROE of i 1.5%.
19 Q.HOW DOES HE RECH TH CONCLUSION THT A VISTA SHOULD BE
20 AUTHORIED AN EQUITY RETU IN EXCESS OF i 1.5%1
21 A.Dr. Avera presets lengty discions of company-speific riks tht he contends ar
22 faced by Avist and should be recognized in sett th author retu. Tht anysis
23 of unque risks is the basis for his contention that the Company reui an equity ret
DIRCT TESTIONY OF DENN E. PESEAU - 49
!PUC Case Nos. A VU-E-01 and A VU-G.o4-i
. ...........- ..... ... ...... ......... ............. ..~... ......... ......... ......... .....~... ......... ......... .... .... .....,.. ... -........ ...... ........ ...... .......... .... ...... ........ ..... ........'. ......... ..... .... ................ _... -...,..... ..-................ ... ...... ... ...... ....... .......
1
2
3
4
5 Q.
6 A.
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
near the top of his estite of the equity cost rage for other wester electrc utilities.
But as I jus explaed, these company specific risks ar incorprated ino his results, and
a subjective adder for such risks is unwaranted.
Update to Dr. Avera's DCF Approaches
DO YOU HA VB ANY COMMS ABOUT IDS DCF ANALYSIS?
Yes. Recal th the DCF methd under stada ficia assuptions reuces to the
equaon:
ROE = Di/Po + g
where ROE ;;requied equity re
fit peod dividend rate01=
Po =today's stck price
g growt rate=
Dr. Avera's estite ofa 10.2% retur reults frm his estimate of the DCF components:
10.2% "" 4.2% (yield) + 6.0% (growt)
I update the 6.00Æi growt rate and his dividend yield. The growt rae g is growt that is
expte in the fu by invesrs. It is by nae forward looking. But I note that on
Dr. Avera's Schedule WEA-2, he usd not only th typical benchmark for expecte
grwt, as report by the invesor intitutions IBES, Value Lin, Firs Ca and Multex
Investor, but also hitorical rate of eangs grwt fo both five and ten year pas
perods:
DIRCT TESTIMONY OF DENNIS E. PESEAU - 50
IPC Ciise Nos. A VU;,U41 and A VU-G-01
2
3
4
5
6
7
8
9
10 Q.
11
12
13 A.
14
15
16
17
18
19
20
21
22
23
24
25
Dr. Avera's Expcted Grwt Rates
Value First Pas Past
(BES Line Call Multe lOYr.5 Yr.
Average Expected
Growt Rate 5.1 2.4 5.2 5.4 7.3 8.1
Whle the simple averge of these grwt raes is 5.6%, Dr. Avera inexplicably uses a
6.0% figue to develop his 10.2% retu
IN YOUR OPINON, is DR. AVERA'S USE OF THE HISTORICAL GROwr
RATES IN InS AVERAGE AN APPROPRIATE BASIS FOR ESTIMATING TH
DCF REQUIR FUT EXPECTED GROWT RATE?
No. To the extent tht pas grwt might be of any importce to invesrs, the analysts'
foreasts Dr. Aver reports for IBES, Value Line, First Call an Multex have alady
taen th inormation into acunt. David A. Gordon, Myron J. Goron and Lawrce I.
Gould, "Choice Among Methods of Esmating Sha Yield," Jounal of Portfolio
Management, pp. 50-55 (Sprng 1989), did a sty tht fomid anyst' forecats of
growt prvide a better explanon of stock prces th three backw-lookig
measues of growt They exlai that their fidings mae sense becaus anys would
tae into acmit past grwt as wen as any new inormion when they form their
forts. Roger Mori report the result of other empirical stuies and concludes
anys' foreasts "are mÒI acurte th forecas based on hiorica growt"
Regulatory Finane.' Utilities Cost ofCapitaJ, page 154. My restateent 'of Dr. Avera's
DCF anysis recognizes four of the growt forecats Dr. Avera relied UPOll but gives no
weight to the meaur of past growt Dr. Avera reported.
DmEcr TESTIMONY OF DENNS Eo PESEAU .51
IPUC cae Nos A VU.E-1 and A VU-G-G1
...............,..........................................,..................,..............................H.......~.............................................~.,...._..................,...............................................................................................................
I Q.HOW HAVE YOU MODIFIED DR. AVERA'S DCF EXPECTED GROWT RATE
2 VARLE TO REOVE TH EFFCTS OF HISTORICAL GROWT?
3 A.My Exhbit No. 208 shows those resuts. To determ an update and consstnt
4 esimate for the DCF exp growt rate for eah of the utilities in Dr. Avera's saple,
'"
S I update his rert estates of investor institution projecons in Schedule WEA.2 as
6 well as his estate of sustanable growt in his Schedule WEA-3. Exhbit No. 208
7 shows an average of four growt forecats; the cur estes reported by IBES, Firs
8 Call and Reut (forerly Multe) and the higher of the two forecas made with Value
9 Line data Exhbit No. 208 shows tht the corrct averae for the prjected or exted
10 grwt ra is 5.1 %, close to the bottom of the 5% to 7% rage adopte by Dr. Avera.
11 Q.DID YOU UPDATE DR. AVER'S DIVEN YIELDS?
12 A.Yes. I used data published by Value Lin, dat June 4. 2004, and the metod Dr. Aver
13 used to compute dividend yields to mae that update. Thes updatd divided yields are
14 also reported in Exhbit No. 208.
15 Q.BASED ON YOUR UPDATES AN UTILIZATION OF ONLY THE FORWARD-
16 LOOKIG GROWT RATES REPORTE BY DR. A VERA WHT is YOUR
17 RETATEME OF DR. AVERA'S DCF REULTS?
18 A.Based on his saple and the restments discused above the indicated avere cost of
19 equity fOl'the west elecc utilities is 9.3% (4.1% dividend yield and 5.1% grwt
20 afer rounding), 90 basis points les than the 10.2% estated by Dr. Avera.
21 Q.DO YOU HA VB OTHR CONCERNS WITH DR. AVERA'S DCF ANALYSIS?
22 A.Yes. The DCF metod he prposes is incot. At page 32, Dr. Avera prsets th
23 genera form of the DCF modeL. It clealy shows th expected divideds pe shae
DIRECl TEIMONY OF DENN E. PESAU . 52
IPUC Case Nos AVU-E-4-1 and AVU-G041
...........h..................................................................................u........................................................................................................................... .-.....u.....................................................................
1
2
3
4
5
6
7
8
9
10
11
12 Q.
13
14 A.
15
16
17
18
19
20 Q.
21 A.
22
23
(DPS) ar the cah flows th ar of interest to invesrs. He adopts Value Line ~
forecasts of dividends for the next year but ignores Value Line ~ forecasts of dividend~ for
other futu years. His DCF approach is incorrct beçus it does not inipra all of
the inonnaton on dividend growt tht investors consider when they prce the sha of
conuon stock in his sample. Had Dr. Avera made IDS DCF estmate wi a mul-stage
DCF model that reognize that dividend grwt is expectd to be les than haf as rapid
as forecasd eags and sutainable growt for the perod 2004 to 2008, th DCF
equity cost estate would be less th 9.3%. But because I limit my testmony to a
resttement of the methods Dr. Avera ha relied upon, I have not presete such an
analysis.
Update to Dr. Aver's Risk Preium Approaches
PLEASE DESCRIE THE RISK PREMI APPROACH TO ESTIMATING A
UTLITY'S REQUIRED RETU ON EQUIY.
Wher the DCF metd adds estates of dividend yield to expted grwt rate to get
equity cost estates, risk premum metods recognze that over tie common stck is
risker th most debt securties (bonds) and therefore requires a premium, or ader, over
and above the retu on bonds. Ths adder is oftn tened a risk premium As yields on
bonds ar genlly dictly obsable and measurable, equity cost estiates may be
derived if reliable risk premiums can be detennine.
HOW DOES DR. AVERA UTLIZ TH RISK PREMI METHOD?
Dr. Avera us a ri prmium method based on authorid equity re, anothr bas
on actu or reaizd retu an, finally, the more academicay rigorous risk prenúum
method, the Capita As Pricing Model (CAPM).
DIRCT TEONY OF DENNIS E. PESAU - 53
LPUC Case Nos. A VU~E-i and A VU-G4-1
................,.........H...........;...................................................................................... ............................................................................................................................................................................
1 Q.
2
3 A.
4
5 '
6
7
8
9
10
11
12
13
14
15 Q.
16 A.
17
18
19
20
21
22
23
WHT EQUI RETU DOES DR AVERA ESTITE USING IDS
AUTORIED RE RISK PREMI METHOD?
11.2%. He derives ths by adding a Debe 2003 bond yield of 6.61 % to a risk
premium estimate of 4.58% tht is derived in his Schede WBA4. Schedle WEA4
uses regrion anysis to attmpt to detene the historica relationship beeen
allowe equty rerns and bond yields; and the differce beteen the two, to estblish
the risk premium. Th theory is that if the regrssion anysis ca deine the
relationship beteen the bond yield an the appriate risk prum, then one can
obsere today's bond yield, ad to it the estiate of risk preum appropriat for the
bond yield and ad the two to get an equity retu estimate. From Schedule WEA-4, Dr.
A vera estiats the relationship as:
(ROE. Bond Yield) = .073 + (-.435 x Bond Yield)
Whle I have no ~el with the basic methodology, Dr. Avera uses interest rates or bond
yields tht are inally inconsisnt in his metod.
PLEASE EXPLA.
Dr. Avera uses a low yield bond to compute hi historica rik prum. Use of ths low
bond yield when subtracted from allowe equity re, producs an exaggerted or
higher risk preium than if a consstent bond rate is us. The bond yield used by Dr.
Avera shown on Schedule WEA-4 is an avee of AA, AA, A and BBB rad bonds.
Since th highy rated bonds AA, AA and A wil have the lowest interest rates, the
composite rate Dr. Avera uses is low. Subtacting a low interest rate frm an authoried
retu yields an arficially high risk premum. Then on Page 49, Line 10, he adds this
high risk prum to th highest bond yiei~ tht of a trple-B bond. Ths mig of
DIRCT TESTIMONY OF DENN E. PISEAU - 54
IPUC Case Noi. A VU-E-Ð.! and A vu.G-0i
.....'.....................................,'''..............,.......,............................................................,........"..................-....................,.................,......."..',..............-.........................................................................
1
2
3 Q.
4 A.
5
6
7
8
9
10
11
12
13
14
is
16
17
18 Q.
19
20
21 A.
22
23
differnt bonds for the regrssion anlysis and for computig the equity retu bia
upw Dr. Avera's estima of an equity re
HA VB YOU AITEMPD TO REOVE DR. AVERA'S INCONSISTECY?
Yes. An approprite calculaton would us the same mea of bond ratig in the
regression anysis as in the recommended equity rewn In makg my resttement, I
have used A-raed utiity bonds to compute the risk prmiwns, to ru the regrsions and
to estiate the equity cost. I ~hose the A-rate utility bond rates becae Dr. Avera reUes
on A-raed bonds in Scheule WEA-5. Also, curt quotations for A-rated utlity bond
raes ar widely available and published by Value Line every week. I also used trple-B
raes. as a second apprh in another regrsion as well because tht is what Dr. Avera
uses on his Page 49.
The results of th resed anysis ar shown in my Exhbit No. 209, pages l' and
2. Combing the revised regresion resut with a June 4.2004 Value Line quotaon of
6.08% for A-rate utity bond rates gives an indicated cost of equity for the bechmark
electrc utilties of 10.8%.40 bais points lower tha Dr. Aver's estiate of 1 1.2%.
Using the trle-B regrions with th curnt trple-B rate of 6.56% reported June 4.
2004 gives a cost of equity estimte of i 0.9%.
DO YOU HA VB ANY COMMS ABOUT DR. AVERA'S RISK PREMI
APPROACH BASED ON mE REALIZED¥RATEOF-RETU APPROACH TIT
HE PRESENTED IN SCHEULE WEA-5?
Yes. First, as he did with his other risk preum approach, Dr. Avera use one type of
bond to deerine the averge risk preium an then incorrtly adde tht risk premium
to a triple-B public utiity bond rate. In ths anysis th ri premium was established as
DIRCT TESTIMONY OF DENNIS E. PESEAU - 55
¡PUC Case Nos AVU-E-041 aud AVU-G04-1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15 Q.
16
17 A.
18
19
20
21
22
the averge dierence ~tween anual res on stocks and A-rate bonds and thus th
risk premium wi be larer th if the premium were eslishe for trple-B bonds. To
mae Dr. Aver's apprach intemly consistnt, I addd the curen A-rated bond to the
premium for A-rated bonds. This chage alone reuces Dr. Aver's equity cost esmate
to 10.1 'Y. See Exhiit No. 210.
My other obsertion is tht Dr. Avera's approach assues th invesrs
tyicaly have holdi perods of only one year, when investors probably exect to hold
shaes of utility stocks for loner peods. If invetors have ver long holdig periods, a
risk premium bas on diffs in geometrc average ret woud be the appropriate
risk premium. If, for exaple, investors have 57-year holding perod, the correct
estiat of the risk premium would be 3.11 % instad of 4.01%. See Exhbit No. 210. I
exp tht investrs typical hae holding periods longer than one-year but much
shorter th 57 yeas. In such a case ths apprach would indicate the cost of equity
would be bet 9.2% and 10.1% but closer to 10.1%.
DO YOU HA VB AN COMMNTS ABOUT DR. AVERA'S CAPITAL ASSET
PRICING MODEL EQUIT COST ESTIMTE?
Yes. Although the CAPM'g derivaon is steeed in a good deal offianial theory and
mathemcal determination, the fina specifcation, like th DCF method, is faily
strghtforward:
Equity Cost = Risk Free Rate + Beta x Maket Ri Premium
Ther ar a numbe of different ways the CAPM can be implemented an a number of
ways tht estmates of the risk fre rate and maket risk premium ca be derived. i limt
DIRCT TESTIMONY OF DENN E. PESEAU - 56
IPUC Cae Nos. AVU-E-1 aDd AVUG-04i
.............................................................................................................................................................................................................................................................................................................
2
3 Q.
4 A.
5
6
7 Q.
8 ' A.
9
10 Q.
11 A.
12
13
14
15
16 Q.
17 A.
18
19
20
21
22
23
my comments to an updte of Dr. Aver's risk free rate an hi estimate of the maket
risk premium (M). I will not contest his meaur of maket risk, "beta"
WHAT is TH RISK-FRE RATE USED BY DR. AVERA?
Dr. Aver uss as a meae of the risk-fr rae th avere yield on long-ter
, governent bonds. He indicate tht this mea of the risk-fre rate as of Decmber
2003 was 5.2%.
WHT is THE REEN YID ON WNO-TERM GOVEME BONDS?
The yield reported by Value Line at June 4, 2004 is 5.32%. I use tht value in my update
of Dr. Avera's CAPM estimte.
HOW DOES DR AVERA ESTIMTE TH MARK RISK PREMIUM ('IMR")?
Whle I do not ag with his method of estma the MR, I use his method her with
a simple update.
Dr. Avera denves a foret of the tota average market ret for the stock
market of 13.7%, thn, to estite the market prium he subtrcts his risk fr rate of
5.2%, which resuts in an 8.5% MRP.
WHT UPDATE HAVE YOU MADE TO DR. AVERA'S MR?
Wherea the long-te goverent bond rate is dìy obserable and is set in
competitive maets, the other component of the risk premium aproach usd by Dr.
Aver the projected market re, is not diectly obseble or meaable. The
projectd maet re is siply the opinon about the futu made by differen investor
institutons an can chage frequently. Use of a projecte market retu of 13.7%, as of a
single point in tie, therfore makes the predcton of total market retu highy varable,
as I now show. For reference, the long-term average market risk prium durng the
DIRCT TESTIMONY OF DENN E. PESEAU . 57
IPUC Case Nos. A VU-E-1 and A VU.G-1
....... ....~.......~............. .......... ....... ..., ,_.,"".... ...... ,..,., '-.,..' .... .,..................... '................................., ........, ..,... . ....;. ......... ....................-.. ,........ ,.......... .......,...... ......... ......... ..... ... ........, ........,........ ........
1 period 1926 to 2003 is 7.2%, not the 8.5% used by Dr. Aver. Invers tht use CAPM
2 would unoubtedly give weight to that long~te averge maket risk premium.
3 Dr. Aver's tota maket retu esat wa ma pror to recet stok market
4 acvity th ha occured since Deer 2003. Investors now understad tht a short-
5 te gai as large as 13.7% is no longer reastc. For example, the Value Line forwd-
6 looking total maket retu for the 1700 stocks it follows, as of June 4, 2004, wa
7 12.55%, not the 13.7% usd by Dr. Avera. Ths huge potetial for mation in these
8 "curent" MR estimates maes rate of retu seg for regulatory puroses difcult.
9 Nevertheless, usng the updated market retu foreas of 12.55%, the implied MR is
10 7.23% (12.55% - 5.32%), not the 8.5% used by Dr. Avera. At this time, the indicatd
11 "cut~ maret risk premium and the long-ter avee maret risk preum ar both
12 7.2%. If investors consider eithr indicaor of the maret risk preum, an update of Dr.
13 Avera's CAPM equity cost esmate is 10.9010 as shown below:
14 Equity cost == Rp + beta x MR
15 Equity cost == 5.32% + .77 x 7.2% == 10.9%
16 Q.PLEASE SUMMAE YOUR UPDATES AN RESTATEMS OF DR.
17 AVERA'S QUANTTATIVE ESTIMATES OF TI COST OF EQUITY FOR
18 BENCHMRK ELECTRC UTIITS.
19 A.I conclud my strghtforwd update of Dr. Avera's esates of the cost of equity do
20 not support a remmended ROE range of 10.4% to 11.9% and cenly do not suppor
21 an equity ret for A vist of 11.5%. My sum Schedule DEP-4 shows tht a simple
22 avera of the updated equity cost estmates is 140 bais points below the 11.5% ROE
23 that Dr. Avera remmends for Avista.
DIRCT TESTIMONY OF DENNIS E. PESEAU - S8
IPC case Nos. A VU.E-4.1 and A VU-G4.1
...............u.........................................................................................................................................................................................................,.................................................................................
Q.DO TH DIRClIONS IN TRNDS OF FINANCIAL MATS SUPPORT YOUR
2 RECOMMATIONS?
3 A.Yes. My Exhbit No. 212 show monthy interest rae data for 10-yea Treasury bonds
4 and for Baa corporate bond for the period Octber 2001 thugh April 2004, as reort
5 by the Federa Reserve. Genely, rates for goverent bond and Baa corporate bonds
6 have deased by 145 bass points since Ocber 2001. I conclude that given the drop ,
7 in caital cost, Avist's cost of equity is well below its 1998 cost
DffECT TESTIMONY OF DENNI E. PESEAU - 59
IPUC Case Nos. A VU.E-041 and A'VU-G1
Conley E. War (ISB No. 1683)
GIVENS PURSLEY LLP
601 W. Banock Stree
P.O. Box 2720
Boise, ID 83701-2720
Telephone No. [phone]
Fax No. [phone]
ce~givenspurley.com
mo
2tm~ JUL -9 PM 3~ 57
i-!! i:ol li._
REC£lVEO
." . ,,~ .....'l ielJ~.;¡U tU~ .i
UiILlTlES CONMlSSION
Attrneys for Potlatch Corpration.
S:1lll J 14\S4\P_Jl T..ii"",DOC
BEFORE THE IDAHO PUBLIC UTILITIS COMMSSION
IN TH MATIR OF TIE APPLICA nON
OF AVISTA CORPORATION FOR TH
AUTORITY TO INCRESE ITS RATES
AN CHAGES FOR ELECC AND
NA11L GAS SERVICE TO ELECTRC
AND NATIRA GAS CUSTOMERS IN
THE STAlE OF IDAHO.
Case Nos. A VU-E-041
AVU-O-04-1
REBUTAL TESTIMONY OF DENN E. PESEAU
ON BEHALF OF POTLATCH CORPORATION
June 21, 2004
ORIGINAL
.............................................................~......n..............................................~.................,...............................................................................................................,...................................-.................
Q.AR YOU THE SAM DENIS PESEAU WHO PREVIOUSLY FILED DIRECT
2 TESTIMONY IN THIS CASE?
3 A.Yes.
4 Q.WHT is TI PUROSE OF YOUR REBUTTAL TESTIONY?
5 B.I have five areas of brief rebut:
6 1.Staff wi1nes Hessing should not have accted the Deal A exces gas cost
7 because his compellng arguen to disallow Dea B gas costs apply to Dea A as
8 well.
9 2.Sta witnesses overlooked the signficant change in cost of servce metods
10 propose by A vista witness KnOx.
11 3.Staff witnesses Sehune's and Hessing's proposal to move varous rate schedules
12 only 200/Ó of the way to cost of service will perpetuate the longstading subsidies
13 between customer classes.
14 4.Coeur Silver Valley witness Yanel's proposa to directy assign pnmar cost to
15 Schedule 25 class has merit.
16 5.Staffs proposal to change the metod of computing peA rates should be rejected
17 or modified.
18 Deal A and Deal B Financil Transactions
19 Q.WHAT AR TH PRIRY ISSUES YOU ADDRESS IN YOUR REBUTAL
20 TESTIONY OF MR. HESSING REGARDING DEAL A AND DEAL B?
21 A.In a nutshell, I agree wholehearedly with Mr. Hessing's recommendation to exclude all
22 the excess finacial cost of the so-called Deal B. In fact, his approach is quite similar to,
23 and parallels, the rationale I provide for excludng Dea B in my direct testiony. There
REBUTAL TESTIMONY OF DENN E. PESEAU - Page i of 16
Case Nos. A VU-E-041 and A VU.G-04.1
......u......................................................u_............_..__........................................................'OV.......................u......._...__.._................................._...........,................,.....,................................."......,......
1 is no ne to elaborate on our similar approaches and our identical conclusions with
2 reect to Dea B, other th to point out th our statement of the amounts in dispute
3 difer, prmany because I used system numbe while Mr. Hessig's figur ar for th
4 Idaho jursdiction and test year only.
5 My issue with Mr. Hessing's temony is that the very compellng circumces an
6 facts that lead Mr. Hessing to appropriately dey Avista reovery of Dea B costs, with
7 one exception, shuld have also compelled hi to recommend disallowance of Deal A
8 costs. My testimony reommends the disallowace of the costs of both Dea A and Deal
9 B.
10 Q.WHT is TI ONE EXCETION TO TH SIMLARTY OF CIRCUMSTANCES
i i SUROUNING BOTH DEAL A AN DEAL B?
12 A.The one dissimilar cirumtan is tht A vist Energy was th counterary to Deal B. In
13 Deal A the apparent counteraries wer Mirant an BP. Thus, the Deal A counteies
14 that profited so greatly were not par of Avist Corporation's corporate stctue. But in
15 all other resect both Mr. Hessin's and my observtions and criticisms regaring the
16 impropriety and imprudence of Deal A and Deal B ar the same for both deals.
17 Q.is TH FACT THAT A VISTA CORPORA nON ITSELF DID NOT PROFIT FROM
18 DEALA SUFFICIENT TO JUSTIFY RECOVERY OF TI DEAL'S EXCESS GAS
19 COSTS IN TH peA?
20 A.No. Mr. Hessing's other compelling arguments for denying revery of Deal B cost on
21 th basis of impnidence also hold for Deal A. Both Mr. Hessing's dirct testimony and
22 my own explain at length the numerous peculiarities and irreguarties of both De A and
23 Dea B that lead t9 the conclusion that each of these deals wa impruent. In fact. the
REBUTAL TEIMONY OF DENN E. PESEAU ~ Page 3 of 16
Case Nos. AVU.E.04.1 and AVU.G-94-1
......._-........_....._...................................'..............................u.........................................................................n.....................................................................................................................................
2
3 Q.
4
5 A.
6 '
7
8
9 Q.
10
11
12
13 A.
14
15
16
17
18
19
20
21
22
extended period of 3 lt year for the Deal A swap actually maes the bet the utilty made
on Deal A prices far more speclative and imprudent than Deal B.
HOW DOES MR. HESSING EXLAIN HIS PROPOSAL TO DISALLOW DEAL B
BUT ACCEPT DEAL A?
On pages 15-16 of his direct testimony, Mr. Hessin offrs two reans for not
disallowi Dea A. First, as explained above, the counteares to Deal A were not
Avista affliates. Second, Mr. Hessing opines tha Dea A did not pu A vista over "the
long limit contaned in its Risk Policy."
YOU HA VB ALREADY EXLAI YOUR POSITION ON DEAL A
COUNTERPARTIES NOT BEING AVISTA AFFILIATE. WHT is YOUR
RESPONSE TO MR. HESSING ALLOWIG DEAL A BECAUSE IT WAS STUL
UNDER THE "LONO LIMIT?"
As I discussed in more detal in my direc testimony, Deal A and Deal B were both
financial trades, not physical tranactions. In other word, Deal A and Deal B did not
purchae any natual gas. On page 5, lies 14.24 ofms teimony, Mr. Hessin describes
both the physical index-priced gas purchaes and the subsequent ficia tractons as
if they were all pars of Deal A and Deal B. But the proposed Deal A and Deal B cost
adjustents ar strictly related only to the financia imprudence of these transactions, and
not in any way to the procurement of the physical natual gas. Therefore, I find it
irrelevant tht th physical purchases were, or were not, over some designated volumetrc
or long limit Neither of the Deal A and Dea B finacial tres was prudent on behalf of
the utilty's customer for reasons explained in Mr. Hesng's and my testiony. I urge
REBUTAL TESTIMONY OF DENNI E. PESEAU . Page 4 of 16
Case Nos. A VU-E-04-1 and A VU-G-04-1
.............-............................................-.._.......T........._.......T.....'................................................................................,.................................................................,......T_....'..............................................
PAGE 5 is CONFIDENTIA
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5 Q.
6
7 A.
8
9
10
11
12
13
14 .
15
16
17
18
19
20
21
other reckless and unprecedented featues of both deas that Mr. Hessing and I identfY in
our diect testmony, compels the conclusion that both should be excluded frm rates on
the grounds tht thei cost were imprudently incured.
Staff Fails to Aclowledge the Importance of Avista's Incorrect 4-Factor Allocator
WHT is YOUR REPONSE TO STAFF'S ADOPTION OF A VISTA'S COST OF
SERVICE METHODOLOGY?
Both Mr. Hessing and I testi that Avist's cost of service methodology generaly
follows tht ordered in prior Commission orders. However, I point out that there is a
significant change in Avista's newly proposed "4-factor" allocator for common cost.
Whle I indicate tht a 4~factor allocator is not objectionable on its face. the maner in
which A vista witness Knox constrcts this allocator is incorrect and uncceptable.
My issue here is with Mr. Hessing's chartenzation of Avista's study as consistt
with th usd in its last general rate cae ''wth mior modifications" (Hessing, page 4.
lines'1-2). Wht I want to make clear, and demonste quantitatively, is that his
characterition of "minor modifications" holds only if the newly proposed 4-factor
method ofal1octing common (overhead) costs is corrected as I propose on pages 33-40
of my direct testimony. As I show below. the corrected 4-factor allocator I develope
represents a less extreme dearre from the previously adopted allocator. In the cae of
Potlatch's Lewiston Facilty, the pnor method and my corrected 4.factor alloctor should,
and in fact do, produce similar cost allocations. both of which differ significantly from
the A vist :rults.
REBUTTAL TETIMONY OF DENNIS E. PESEAU. Page 6 of 16
Case Nos. AVU-E-04-1 aDd AVU-G-Ð4.1
HOW DO YOU PROPOSE TO DEMONSTRTE THAT THE INCORRCT
ALLOCATOR PROPOSED BY AVISTA is NOT, AS MR. HESSING STATES, A
"MINOR MODIFICA noN"?
Q.
2
3
4 A.Below I list three colums sumarg th rate schedule rates of retu from i) the
5 "40% energy/60% customet' used and adopted in pror procengs, 2) A vi's newly
6 proposed but incorrect 4. factor allocator an 3) my corrcted A vist' s 4.actor allocator! :
Class
Schedule 1
General Service
Large General Servce
Schedule 25
Potlatch Lewiston
Puping
Lighting
AVERAGE
7 Q.
40%160%
Method
1.04%
9.35%
9.26%
2.07%
5.61%
7.79%
6.52%
4.71%
Avista
4-Factor
1.97%
9.70%
8.12%
1.7%
5.24%
7.24%
4.55%
4.71%
Potlatc
4.Factor
1.84%
9.52%
8.16%
1.28%
5.60%
7.22%
4.15%
4.71%
PLEASE EXLA THS TABLE.
8 A.My intent here is to show that Avist's incorrct 4.factor allocator is much more than a
9 "minor modification." As I discussed in my direct testmony, Avist's results ar skewed
10 by its inappropnate inclusion of varable fuel and purhae power expenses in the
1 i definition of O&M. By includig these energy costs in an allocar meat to allocate
12 fixed common cost, Avista improperly shfts costs to lugher load factr customers.
13 Whle the perentage shift is rela1ively small, the effect in absolute terms is not Avist's
14 flwed cost of service chage increases Potlatch Lewiston's cost of serice by
16 common sense.
15 approximately $ i ,000,000 per year. A shift of this magnitude in common cost defies
, The Potlatch-calculated ret differ from those in my dirct testimony bece, In order to make accur
compansos, I do not her chane the trission allocator, as I reommend in my dict tesimony.
REBUIAL TEONY OF DENNIS E. PESEAU . Page 7 of 16
Case Nos. AVU.E-4-1 and AVU-G-4-1
.........................u..................................................................................................................u.............................................................................................._.............................................................
1 Corrting Avita's misten inclusion of fuel and purhased power expes, as I
2 show in the colum headed '¡Potlach 4-Factor," prouces fil allocations that are less
3 prejudicial to lugh load factor customers and more consistent with pror order than
4 Avista's apoach. My rebut Exhibit 213 suaris the denvation ofthe Potlatch 4w
5 Factor metod. The other colwns are developed frm A vista Exhbit 16, Schedules 2
6 and 3.
7 Q.HOW DO YOU RECOMME mAT TH COMMISSION RESOLVE THESE
8 DISPARATE COST OF SERVICE RESULTS?
9 A.I recommend that the Commission either stick with its previously adopted "400/0160%"
10 method, or adopt the corrted 4-factor metod that I propose.
11 Stafs Proposed 20% Movement to Cost of Service is Inadequate
12 Q.WHT is THE iSSUE WITH RESPECT TO STAFF'S PROPOSAL TO MOVE EACH
13 RATE SCHEDULE 20% TOWAR COST OF SERVICE?
14 A.Both Staf witnesses Messrs. Hesing and Schune proposed to limit the movement of
15 each cutomer class's rates to 20% of the discrepancy with cost of servce, with the
16 remaning revenue requirement deficiency being made up by spreading th deficiency on
1 7 the basis of an equal percentage to each rate class.
18 My issu here is that the Staf proposal once again blunts any meaingful movement
19 to cost of serce, therby continuing indefintely the longstding intewclas rate
20 subsidies. The concurrent PCA reduction makes ths an ideal time to fmally make some
21 progress towa rate parity.
22 Q.PLEASE EXPLAI.
REBUTTAL TESTIMONY OF DENNIS E. PESEAU . Paite 8 of 16
Case Nos. AYU-E-04-1 and AVU-G-04-1
1 A.Staff jusifies its proposal to mae minmal progrss toward cost of service on th basis
2 of avoiding rate shock. The unortte consequence of limiting rate incrases of
3 customer classes currently being subsidized is tht it generates a corrponding rate shock
4 to rate classes ilat are alreay paying well in excess of cost of service (potlh's
5 Lewiston Facilty). For example, staf proposes an overall averge rate increase of
6 15:8%. As my cha on page 7 of this testmony points out, the residential class's rates
7 curntly generte rougWy 20% to 40% of the average rate ofret no mar which
8 cost of service method is adopted. Yet staff proposes to limit the incras to the
9 residential class to 18.8%. On the other had, Potlatch's currt rates generate retus
10 well in excess of the system averge retu, yet Stats proposal results in a 14.9% rate
11 increase for Potlatch. Stated another way, depending on the cost of serice methodology
12 chosen Potlatch is generating a rat of retur that is approximately 3 to 5 times that of
13 the residential class, but the Sta proposes only a 3.9% duference in the percentage rate
14 incrase assigned to the two classes. I respectfuUy submit this result is neiiler just nor
15 reasonable.
16 Q.HOW DOES STAFF'S RECOMMNDATION IN mlS CASE SQUAR WITI ITS
17 RECOMMEDATIONS IN THE PAST?
18 A.As I understand it, in ile prous A vista general rate increase Staff prposed thee cost
19 of servce options-to move rates one.thrd, one-hair, or entirly to respective cost of
20 service. The Commssion instead selected 20% as the overall cap on the movement to
21 cost of service.
22 Q.DID THT INITITIVE IN FACT RESULT IN A PARTIA CORRTION OF
23 RELATIVE RATE OF RETU DISPARTY?
REBUTTAL TESTIMONY OF DENNIS E. PESEAU - Page 9 of 16
Cas Nos. A VU-E-041 and A VU-G-04-1
..u.......................................................................................................................................................................................................................................................................................,...................
A.Unfortnatly, no. In fact the inter.class subsidy of the residential clas has increaed,
2 rather th decreased, since the las A vista rate case. Under these circumstaces, the rate
3 shock argwnent is wearng very thin. There has been no progress towad the elimination
4 of this subsidy for roughy five years, and I suspect Staffs proposal, if adopted, will be
5 revealed to produce little or no progr when the next Avis rate cae rolls arund. I
6 fuy realize this is a tough issue for the Commssion, but the indefnite continuaion of a
7 subsidy of ths magitude is simply intolerable. It is bad economics and bad policy and,
8 at best, it only postpones the day of rekonig whe the reidential clas wil ultimtely
9 have to pay its ful cost of sece, or sometg very close to it. At that point, the rate
10 shock wil be far worse than it would be in this cae.
11 Q.AR THRE CIRCUTANCES IN TH PREEN CÁSE TIT WOULD SOFT
12 TI RATE IMPACT OF MOVING MORE BOLDLY TOWAR COST OF SERVICE?
13 A.Yes, the propose PCA reduction provides an offset to any rate incrase the Commission
14 ultimately approves. For exaple, if the Commission adpts the Staffs proposed 15.8%
15 general rate increase, the net incrase for the Idaho jursdiction af the PCA adjustment
16 is only 2.4%. Under Staffs 20% proposal, the net increae in residential rates would be
17 only 5.1 % in ths sceo. There is clealy room to make a more meanngful move than
18 this to equa class rates of retur without causing rate shock
19 Q.WHAT DO YOU RECOMMEND THT TH COMMISSION ADOPT IN TERMS OF
20 MOVEMENT TOWARD COST OF SERVICE?
21 A.I recommend tht the Commission do two ths. Firt, it should order that customer
22 class rates move 50% towa cot of service in ths cas. Secnd, the Commission
REBUTTAL TESTIMONY OFDENNlS E. PESEAU- Page 100f16
Case Nos. A VU-E.4-1 and A VU-G4-1
1 should expres the intet that in subsequent cases, or with 2 years if no genera rate
2 cas is filed, rates wil be moved an additiona 50% toward cost of service.
3 Coeur Silver Valley's Diree Assignment of Primary Distribution Costs
4 Q.I NOTICE YOU DID NOT DISCUSS SCHEDULE 25, TI OTIR CUSTOMER
5 CLASS THAT APPEA TO BE REA VI Y SUBSIDIZED, IN TH PRECEBDING
6 SECTION OF YOUR TESTIMONY. WH is THT?
7 A.After reading Mr. Anthony Yimel's direct testimony on behal of Coeu Silver Valley, I
8 am convinced that all of the cost of service studies in this cae, including my own,
9 significatly overste Schedule 25's cost of servce. Mr. Yankel points out that it is
10 possible and practical to dictly identi al those A vist priar facilties necssar to
11 serve all Schedule 2S customers from the Company's accuntig records. Since ths is
12 possible, Mr. Yanel argues tht it is always more accurte to dirctly assign those
13 facilties' costs to Schedule 25 customer, rather than average these customer-specific
14 costs into all other reidential and smaller general servce custmers and then alocate
15 them on a les accurte basis.
16 Q.WHAT is YOUR POSITION WITH RESPECT TO miS ISSUE?
17 A.While I have not fuly reviewed Mr. Yankel's analysis, I can state that his position that
18 directly assigned costs are more accurate thn those derived by a computed allocation is
, .
19 correct.
20 The reason tht dirctly assigned costs beter reflect cost of service is raher
21 strightforw. If I can directy identifY those investents mae specificaly to sere a
22 customer, I can clearly tre both the cause an the costs of those invesents to tht
23 customer. Mr. Yanl has identified the direct costs of primar distbuton facilties
REBUTAL TESTIMONY OF DENNIS E. PESEAU - Page 11 ofl6
Cas Nos. A VU-E-04-1 and A VU-G-04-1
...................................... ..............................................................,.....................................................................................................................................................................................................
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10
U Q.
12
13 A.
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15
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17 Q.
18 A.
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22
used to serve Schedule 25 customers an, as J understa it, proposes to directly assign
these identifiable cost to the Schedule 2S class. J cerinly agree in principle tha this
direct assignent is prferble to an indirct cost alocation.
Accordin to Mr. Yanels calculations, ths direct assignent ofprim distibution
facilties signifcantly reduce the purrtd subsidy of Schedule 2S customers. I have
not attempted to veri his caculations. But as I have just noted, Mr. Yanel's
adjusent is correct in principle, and uness someone ca demonstrte that it ha been
imroprly implemented or calculate, his ultimate conclusion-at Schedule 25's cost
of servce is oversted-is correct as well.
Stafrs Proposal to Change Basis for Computing peA Rates
DOES STAF PROPOSE TO CHANGE TH BASIS UPON WHCH peA RATES
ARE COMPUTED?
Yes, on pages 22-24 of his tesmony, Mr. Hessing proposes that the Commission chage
from the curent method of spreadig PCA account balances to customer class rates on an
"equal percentage" basis to a metod of spreaing balances on an equa cents per kwh
basis.
WHT is YOUR POSITION ON THS ISSUE?
I oppose th proposal on both thoreica and pratica grounds. Firt, I have always
argud that power supply costs ar not 100% energy or kwh-based and should not,
therefore, be spread on an energy-only basis. Ther is both a fixed or capacity
component and a seasonaly-differentiated cost component to power supply cost that
makes spreing balances on a flat, equal kwh basis incurte. Recovering power
REBUTAL TESTIMONY OF DENN E. PESEAU - Page 11 of 16
Case Nos. AVU-E-04-J and A VU-G-1
.............................".......................,................,.................................................................,............u...,...........................................................................,.........,..........................,..........................,....
supply adjustments on a per kwh basis is inconsistent with the way we establish base
2 rates, and should be rejected as a matter of principle.
3 Q.WHAT is YOUR PRACTICAL OBJECTION TO TH PROPOSAL?
4 A.In theory, whether PCA changes ar recovered though percentage changes or energy rate
5 adjustments should be a matter of indifference to ratepayer. If bas rates ar properly
6 set, a customer who pays more wider an energy only recovery of a surhage wil also
7 receive a proportonaely larger benefit frm any PCA "rebate." Over the long haul, eac
8 customer's tota PCA exosure should be the same wide either recovery method.
9 But as a practical matter, high load factor cusomers such as Potlatc who compete in
10 nationa or global markets ar not really indifferent. Switclng to a per kwh recover
11 methd will make these customers' rates much more volatile, because the suchages and
12 rebates will both be grater th under the curt system. In short their high rates will
13 be higher and their low rates lower wider Mr. Hessing's proposal. This is a concer for
14 Potlatch and other industral cusomers becaue it makes buiness planing and
, ,
15 management more diffcult. Furthermre, rate increaes can cause disruptions and losses
16 that canot be recovered by corresponding decreases in subsequent years. To cite but one
17 example, a peA rate increae can potentially shut an industial cusomer off from some
18 markets or, in an extreme case, render production wieconomie in all markets. Losseslike
"
19 these ar not likely to be adequately compensated by benefi from PCA rebates in good
20 yea.
21 Q.AR THER ANY OTHER PRACTICAL PROBLEMS WITH STAFF'S PROPOSAL?
22 A.Yes. On page 23, line7 to page 24. line 2, Mr. Hessing carfuly explains tht, due to the
23 fact that there are curently positive balances in the PCA accowits, and these accowits
REBUTTAL TESTIMONY OF DENNI It PESEAU - Page 13 of 16
Case Nos. AVU-E-4-1 and AVU-G-04-1
'.......n........n.......n.................................................................................................................................................................................................................................................................................
1
2
3
4
5
6
7
8 Q.
9 A.
10
11
12
13
14
15
16
17
18
19 Q.
20 A.
wer collecte on the present equa percentae basis, it would be very unfair to high load
factor customer to now change and attempt to reover these balances on a new, energy
only basis. He proposes that any change approved in the PCA metodology not be
imlemented Mti the present defer balances are clead. I simply wat to underscore
th this mixing of methods to accuulat and then to recover such balances is potentially
highly prejudicial to high load factor customers unless it is implemented when balances
are essentially zero.
DO YOU HAVE A SECOND RECOMMENDATION REARING THIS ISSUE?
Yes. If the Commission decides to make the change Mr. Hessing remmends in the
name of consistency, it shol.d tae the proposal to its logical conclusion. If the
Commission really believes tht power suply adjustments ar incurd on a "per kwh"
basis, the "cents pe kwh" revery should be "sesonaized" on a monthly or quarterly
basis in a maner simiar to avoided cost rate. Doing so would alow PCA rates, like
other cost components, to track the actul chanes in power costs as they va over the
year. It is an eay ma to calculate the act monthly kwh rate that cause the PCA
defer balances to change, and frm ths information detennine the basis for adjusting
the PCA rate seasonally. All the benefits of cost-causation and price signl
considerations that apply to base customer rates would then apply to PCA rates.
DOES lHS CONCLUDE YOUR TESTIMONY?
Yes.
REBUTAL TEMONY OF DENNiS E. PEEAU - Page 14 or 16
Case Nos. A VU-E-04-1 and A VU-G-04-1
....._.................H......................... __................,........,....................._...,............."...............................,.................................,.....................
CERTIFICATE OF SERVICE
I HEREBY CERTIY that on this 911 day of July 2004, I caused to be served a
tr and correct copy of the foregoing document by the method inicated below, and
addressed to the followig:
Jean Jewell
Idaho Public Utilties Commission
472 W. Waslun Stree
P.O. Box 83720
Boise, ID 83720-0074
( ) U.S. Mail
( ./ Han Delivered
( i Overght Mal
( J Facsimile
Scott Woodbur
Lisa Nordstrm
Idaho Public Utilties Commssion
472 W. Washingon Stret
P.O. Box 83720
Boise, il 83720~0074
swoodbu(gpuc.state.id.us
lnordst(gpuc.state.id. us
( J U.S. Mail ,
( J1 Hand Deliveed
( ) Overnght Mai
( J Facsimile
( ) E~Mail
David J. Meyer
Senior Vice President and General Counsel
A vista Corporation
P.O. Box 3727
1411 E. Mission Ave., MSC~13
Spokane, WA 99220-3727
david.meyer(avistacorp.com
( ) U.S. Mail
r ) Hand Delivered
( J) Overnght Mail
( ) Facsimile
( ) E-Mail
Kelly Norwood
Vice President, State and Federa Regulaton
A vista Utilties
P.O. Box 3727
1411 E. Mission Ave., MSC~ 7
Spokane, WA 99220~3727
kelly .norwood~avistarp.com
Denns E. Peseau, Ph.D.
Utity Resoures, Inc.
1500 Libert Street SE, Ste. 250
Salem, OR 97302
dpesea~excite.com
( ) U.S. Mail
( ) Hand Delivere
( II Overnight Mail
( ) Facsimie
( J E-Mal
( J) U.S. Mal
( ) Hand Delivere
( ) Overnght Mal
( J Facsimile
( J E.Mail
REBUTAL TESTIONY OF DENNIS E. PESEAU . Page 15 of 16
Case Nos. A VU~E-4.1 and AVU.G-04.1
.......................................................,....................................................................................YO............................................._..............................................................................................................
Chales L.A. Cox
EVANS, KENE
111 Main Stt
P.O. Box 659
Kellogg,lD 83837
ccox~usamedia.tv
( ) U.S. Mail
( J Hand Delivered
( Jl Overght Mail
r J Facsimle
( 1 E-Mail
Bra M. Pudy
Attorney at Law
2019N. 17th Street
Bois, ID 83702
bmpurdy(!otmaiLcom
Michael Kar
147 Appaloosa Lane
Bellgham, W A 98229
michael~wish.net
i 1 U.S. Mail
r ,JJ Hand Delivered
( 1 Overnght Mal
( i Facsimle
( 1 E-Mail
( J U.S. Mail
( J Hand Delivered
( Jj Overnight Mail
( J Facsimile
r ) E-Mail
r J U.S. Mail
( J Had Delivered
r./ Overght Mail
( ) Facsimle
( 1 E-Mail
Anthony J. Yanel
29814 Lake Road
Bay Vilage, OR 44140
REBUTTAL TESTIMONY OF DENNIS E. PESRAU. Page 16 oft6
Case Nos. AVU.E-04.i and AVU-G-04-1
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04 OCT 28 Prj 3: 2 U
Please acct for fig an ongínaJ and nine copies of the prefied direct
testiony of Dr. Dens E. Peseau on beha of the Souther Nevad Water Authorityin Docket No. 048022. '
filing.
Please call Fre Schmdt at 684-6008 if you have any quesons regarding ths
~tO~Mã~way
..
HAE LANE PEEK 'DNNISON AND BOWARD
RENO OfICE S41 Kiekc i.i Sed Floorl Ri. Nc.. 8951111'1011" (75) 3i7.iao I Fai:il. (ns) 786.6179
LAS VEGAS OFFCE: 230 WCSI S1IlI' Avenuc I Elimh FlDD I Box 81 La VClIl NC\ 8910211'1_ (7 22-1500 I Pacili,Uc (702) 365-60
C:\WlNPlvnlc~olCr i.rPVleadiig.dOg
ATTORN.V. AT LAW
m Etlt Wil Slnll Slll io I Qm Ci. Nna moi
Tinc (7) 6l I Facsiniile (nS) 6l1i
Webste: htt:Hwww.hllløc.i:
Octobe 28, 2004
Ms. Crta JacksnSecret
Public Utities Comission of Nevada
i i SO Willam Strt
Caron City, NY 89701
Dear Ms. Jackson:
Sincerly,
: \ ..e -
I'" :.:- :., ~.. r'",ri~~..: :.,,. I:." .' ..,. ... .!
C¡. ¡ "1"..;:..
~~
04 OCT 28 Pl- 3: :~ 0BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Docket No. 04-8022
Direct Testimony of
Dennis E. Peseau
on behalf of
Southern Nevada Water Authoriy
1 Q.PLEAE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A.My name is Dennis E. Pesau. My business addre is Suite 250, 1500
3 Liberty Street, S.E.. Salem, Oreon 97302.
4
5 Q.BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
6 A.I am President of Utility Resourcs, Inc. My firm consults on a number of
7 ecnomic, financil and engineering matters for various private and public
8 entties.
9
10 Q.ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
11 A.I am testifying on behalf of the Souther Nevada Water Authority (SNWA).
12
1 of 12
. .
1 Q.
2
3 A.
4
5 Q.
6
7 A.
8
9
10
11
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13
14
15
16
17
18
19 Q.
20 A.
21
22
23
24
e -
DOES ATTACHMENT 1 ACCURATELY DESCmBE YOUR BACKGROUND
AND EXPEmENCE?
Yes.
WHAT IS THE PURPOSE' OF YOUR TESTIMONY IN THESE
PROCEEDINGS?
T-he primary purposes for the SNWA involvement in this case are to re-affrm
its support for Nevada Power's reques to have the Commission approve the
HAM 500 kV component of the Centennial Prject; to confirm with Nevada
Power that the significant transmission needs of the Colorado River
Commission (eRC) and the SNWA are in no way compromised by any
Company request made in its filing; and to propose that a mutually beneficial
joint ownership between Nevada Power and the SNWA of the HAM 500 kV
project be considered and Nevada Power be ordere to report back to the
Commission the results of discussions with SNWA to consider such a joint
owership option. Ms. Gail Bates describes in more detail the second issue of
confirming levels and reliabilit of CRCJSNWA needs.
WHAT CONCLUSIONS HAVE YOU REACHED?
i conclude that:
1. Nevada Power's technical studies in this cae cormrm the
economic and engineering superiority of th HAM 500 kv project
over alternatives. However, there are Important unresolved
2of12
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3
4
5
6
7
8
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29
30
31
32
33 A~PROVE THE HAM 500 KV PROJECT
at e
questins rearding the amount of the line that will be
subscribed. The SNWA therefore conditions its support for the
HAM project on the successful discussion on joint ownership I
discus below.
2.The Commission should reuire in these proeeing that
Nevada Power commit to providing to the CRC/SNWA all
contractual and generaiiy áccted levels of transmission
service necessary to protect the integrit of the Southem
Nevada water system and represent that the proposed removal
of the previously approed McCullough 5001250 kV transformer
and the Clark Substation from the HAM 500 kV project wold
not affec service to CRC/SNWA.
3.The Commission should encourage Nevada Power to
immediately investigate the feasibilit of and discuss with the
CRC/SNWA the joint development and ownership of the HAM
500 kV project to identify the potential mutal benefits for
Nevada Power shareholders, ratepayers and SNW A and water
purveyor custmers summanzed below. The Commission
should order Nevada Power to report back to the Commission
within 90 days the results of such discussions. I believe this to
be a "wln-win" opportnity for all parties.
4.The SNWA does not oppose Nevada Power's request to keep
the $15.56 millon in investment reduction due to cancellation of
the McCullough transformer component of the HAM project by
placing this sum into the contingency fund, but request that this
sizable sum be sep~rately earmarked as a budget line item, to
be used only for newly Identified facilities, not merely cot
overruns on existing planne facilties.
34
35 Q. WHAT IS THE ISSUE WITH RESPECT TO COMMISSION APPROVAL OF
36 THE PROPOSED HAM 500 KV PROJECT?
3 of 12
e e
1 A.The Actn Plan contained In the Company's proposed Third Amendment
2 Filing (Pages 2-3) request among other things that the Commission reaffrm
3 its approval of the HAM 500 kV project
4
, 5 Q.WHAT IS THE SNWA'S POSITION ON THIS REQUEST?
6 A.The SNWA considers this HAM 500 kV component of the overall Centennial
7 Projec to be extmely importnt for the long-tenn economics and reliability
8 of Nevada Power's electic syem.
9 The HAM 500 kV project is an important enhancement to southern
10 Nevada's transmission network and is an Ideal facilit to integrate future
11 facilities needed by SNWA to por th existng and planned water system
12 infrastrctre. The HAM 500 kV line is considered so impont that the
13 SNWA request that it be allowe to assist in it financing, and development
14 and ownership with Nevada Powr, as I explain below.
15
16 Q.HAVE YOU REVIEWD THE TRANSMISSION ALTERNTIVES TO THE
17,HAM 500 KV PROJECT STUDIED BY NEVADA POWER IN ITS THIRD
18 AMENDMENT FILING?
19 A.Yes. On Pages ß.12 of the direct testimony of Nevada Power witness Larr
20 Luna, and Pages 8-11 of the Thir Amendment, the Company discuses the
21 numerous advantages of the HAM 500 kV projec over five alternative
22 transmission projecs. While I am not a trnsmission engineer, the clear
23 findings that the HAM 500 kV project is cost competive, has greer capacity
40f 12
. .e e
1 than alternatives, serves as a backbone system for the greater system and
2 ' can be completed earlier than alternatives provide ample base for approval
3 over the alternative projec.
4
5 CONFIRMING ABILITY TO SERVE CRClSNWA REQUIREMENTS
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7 Q. WHAT IS THE ISSUE WIH RESPECT TO QUESTONS ABOUT NEVADA
6 POWER'S ABILIT TO SERVE NECESSARY CRC/SNWA
9 REQUIREMENTS?
10 A. Based on a bare reading of the Application, the CRC and SNWA had
11 concerns about the Third Amendmenls requested changes and potential
12 impacts on the CRC/SNWA transmission service questons. Gail Bates of the
13 CRe addresses the status of these concerns.
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15 SNWA'S REQUESTTO OWN AT LEAST 10% OF THE HAM 500 KV PROJECT
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17 Q. WHAT ACTION IS THE SNWA REQUESTING THE COMMISSION TAKE
18 WITH RESPECT TO THE SNWA'S REQUEST TO ACQUIRE AT LEAST A
19 10% OWNERSHIP IN THE HAM 500 KV PROJECT?
20 A. The SNWA reqiiest that the Commission instruct Nevada Power to begin
21 intensive, coperative discussions with the SNWA to detemiine the feasibilit
22 of, and if appropriate, allow and provide for the SNWA to finance and
23 purcase At least 10% ownership of the HAM 500 kV projec. i,pointto the
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Commission's affrmative role in bringing about the recent highly successful
sale of power from SNWA's SlIverhaWk combined cycle plant to Nevada
Power as an example' of beneds which can be derived with Commission
ordere encoragement. The expected outoome of Joint ownership of the HAM
500 kV projec has even greater benefits to Nevada Power's customers and
shareholders, as well as SNWA's, and it member agencies' customers.
WHY SHOULD THE COMMISSION REQUIRE THAT A STUDY OF THE
BENEFITS OF JOINT OWNERSHIP OF THE HAM 500 KV PROJECT
BETEEN NEVADA POWER AND THE SNWA BE UNDERTAKEN?
The prospect of such joint ownership is, In my opinion. clearly a "win-winD
sitation, for at least the ecoomic and planning reasons i list below.
WHY IS SNWA SEEKING JOINT OWNERSHIP?
The SNWA is unique among other parties or customers that either "buy from';
or ilsell into" Nevada Power's sysem. The SNWA is neither a usual customer
of nor usual generar of electricity. The SNWA certainly has, and distributes
to, large loas in the Nevada Power system. But the SNWA also has a 125
M. interest in the Silverhawk generating plant and the CRC, largely on the
SNWA's behalf, owns the extensive River Mountains transmission facilities
located in Nevada Power's servce terrtory. The large and regionally
disparate loads served by the SNWA and the necessit of moving power in
different diretions depending. on SlIverhawk and other power source
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availability make partl ownership of the HAM 500 kV project by SNWA a
significant opportunity upon which to build up it water sys infrastctre in
coming years. Simplifying somewhat, the SNWA must. in order to meet the
growth in demand for water that it faces. both develop water sourc distnt to
the Las Vegas Valley and be in a position to obtain and distribute electric
power to It new water sourc in order to pump such supplies to market
WHAT INCREAES IN SNWA ELECTRIC LOADS ARE ANTICIPATED TO
SERVE THESE DEVELOPMENTS?
While the estimates are preliminary and subject to change, the electric power
eventually expcted to be reuired for new water resource development is In
excess of 150 MW of new load in addition to foad growth associated wit use
of the existing water system. A 10% ownership of the HAM 500 kv project
would well serv these SNWA pumping requirements.
WHAT POSITIVE FINACIAL BENEFITS DO YOU FORESEE FROM JOINT
OWNERSHIP OF THE HA 500 KV LINE?
Due to the present excelent credit stnding of the SNWA. its abilty to finance
100% with low cost debt and the present huge capital expenditure budget of
Nevada Power, i expect a number of poitive financial outcomes to develop:
· The financial communit and leading creit raing agencies will
perceive this joint ownership as a win-win for investors since it
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15 I offer the above not as an exhaustive list of benefits, but as a few exmples of
reduces near-term huge capital requirements, improving times
interest.coverage ratios, liquidity and lowers debt cots.
.The SNWA's wilingness todiscuss means to better integrate
the eiåsting CRC/SNWA and Nevada Power transmission
systms provides opportnities for additional import capability,
system reliabilit as additional intercnnecton to eRe and
SNW A's existng transmission is developed.
.Opportunites to stdy the potential for the SNW A to finance
additional ownership portns of the HAM 500 kV line and
transfer benefits -at cost" to Nevda Power could greatl benefit
. both investors and ratepayers.
16 many possible mutal benefit to the parties from sitting down and
17 constctve studying these opportnities.
18
19 Q. WHAT FRACTION OF NEVADA POWER'S TOTAl CAPITAL
20 EXPENDITURES BUDGET WOULD A PROPOSED 10% JOINT
21 OWNERSHIP BY SNWA COMPRISE?
22 A. The reief to Nevada Powets shareholders and customers of the reduction
23 in the Company's near-term capital budget is modest. For example, at a
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budget of approximately $100 million for the compleion of the HAM 500 kV
project, a 10% joint ownership by the SNWA reduces the near-term budget
by $10 millon. This amount is, of course, a smaller percentage of Nevada
Powets overall capital budget of nearly $ 300 milion per year.
But the absolute percentage relief in Nevada Powets capital budget
Is not th prime consideraion here. The announcement effect to investors
and credit rating agencies that Nevada Power, its reulators and its
custmers are encouraging ways to stem the trend in excessively
'averaged investme requireents wil improve the Company's investment
standing.
To the extent that this joint venture opens Nevada Power to
additional investment opportunities to invest in intercnnections and
infrastructure not otherise available. investors wil understand that this
joint venture does not deny preent investment opportunities, but rather
shif them Into near-term future opportunites when Nevada Power is in an
even beUer financial condition to Invest in such assets.
IS THE SNWA INDICATING A WILLINGNESS TO COOPERATE TO
PURSUE PROJECTS OF USE TO NEVADA POWER AS WELL?
Yes, and while I am not providing a list of specific items, certainly a study of
intercnnecton possibilities betwn Nevada Power and the CRC/SNWA
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would identiy such details. There are apparenty very signifcant joint project
that deserve furter study to determine whether they can be underken .
IS JOINT OR MULTIPLE OWNERSHIP OF TRANSMISSION FACILITIES
RARE?
No. Throughout the United State, multie ownershIp of high voltage
transmission lines is common. For example, the huge AC and DC
transmission lines connecing the Pacific Northwest wit Nortern and
Southem California, having a capacit of several thousand megawatt, are
owned by multiple publjc and privte entities which work together to optimize
the physical and economic operation of the transmission system.
IS PARTIAL OWNERSHIP OF THE HAM 500 kV PROJECT AN UNUSUAL
UNDERTAKING FORAN ENTITY LIKE THE SNWA?
No, not at alL. As I have stated, the'SNWA does not fit the simple prole of an
energ consumer. The SNWA is faced with the tasks of enhancing and
developing new sources of water supplies to Southern Nevada. It Is unique
among other entities and customers in this regard. Joint ownership now of the
HAM 500 kV project would greatly reduce the cO and administrative
burdens to the SNWA and Nevada Power in numerous OA IT and other filings
before FERC and this Commission.
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WHAT IS THE ISSUE WITH RESPECT TO NEVADA POWER'S REQUEST
TO KEEP THE $15.56 MILLION IN BUDGET FOR THE CANCELLED
MCCULLOUGH TRNSFORMER?
On page 3, Jines 9-26 of his testimony, Nevada Powr witness Mr. Luna
requests that the Company be aUowed to cancel the additon of a $15.56
trnsformr that wa previously seoped and budgeted for the HAM 500 kV
project. But. rather than reduce the previous budget by the amount of $15.56
milion. he instead request that this amount simply be added to the
Centennial Project.s Risk and Contingency budget. The overall budget '
therefore remains unchanged.
WHAT IS YOUR RECOMMENDATION TO THIS $15.56 MILLION
REQUEST?
The SNWAdoes not oppose keeping these funds available, but requests that
this sizeable sum be separately earmarkd as a budget line item, to be used
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only for newy identied facilites, no merey cost overrns on exiSing planned
facilites.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
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AFIRTION
I, Dens E. Peseau, puuat to NAC 703.710 herey af th the foregoing prepared
testimony was prear by me or under my diction and is corr to th bes of my knowledge.
¡¿&-'~Dens E. Pesu
Dated: 10-2$- Or
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AlTACHMENT 1
e Achment1
Page 1 of3
STATEMENT OF OCCUPATIONA AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has coduced ecnomic and financial studies for regulate
industris for the past twnty-eight years. In 1972, he was employed by Soutern
CaUfomla Edison Company as Assocate Economic Analyst, and later as Economic
Analyst. His responsibilties included review of financial testimony. incremtal cot
studies, rate design. econometnc estimatin of demand elasticrtles and various areas
In the field of energ and economic gro. Also, he was asked by Edison Electcal
Instite to study and evaluate severa prominent energy models as part of the Ad
Hoc Commit on Economic Groh and Energy Pncing.
From 1974 to 1978, Or. Peseau was employed by the Public Utty
Commissioner of Oregon as Senior Economis. There he conducted a numbe of
economic and financial studies and prepare testimony pertinlng to public utites.
In 1978 Dr. Peseau established the Nortst offce of Zinder
Companies, Inc. He has since submitd testmony on economic and financial
mattrs before state regulatory commissios in Alaska, Califoria. Idaho, Maryand,
Minnesota, Montana, Nevada, Washington. Wyoming, the Distrct of Columbia, the
BonneviUe Power Administation and the Public utlities Board of Albert on over one
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hundred occsions. He has coducted marginal cot and rae desin stdies an
prepare testimony on these maters in Alaska. Californa, Idaho. Maryand.
Minnesota, Nevada. Oreon, Washingto and In the Disrict of Columbia. He has
also conduct cost and rate studies regarding PURPA issues In the sttes of
Alaska, California, Idaho. Monna, Neada. New York, Washington. and
Washington. D.C.
Dr. Peseau holds the B.A.. M.A. and Ph.D. degrees in ecnomcs.
He has co-authored a bo in the field of industral organiztion entiled,
Size. Profits and Exective Compsatign in th Large Corporatio. which devotes
a chapter to reulated industr.
Dr. Peseau has published artcles In the following professional journals:
Review of Economics and Sta~. Atlantic Economic Journ. Jouma of Financlšil
Management, and Journal of Regjona! Sgience. His artcles have ben read before
the Econometric Soiety, the Weste Econoic AsociatiOn. the Financial
Management Association, the Regioal Science Associaton and universities in the
United Kingdom as well as in the United Staes.
He has gues lectred on marginal costing methods in seminars In New
Jersey and California for the Center of Proessional Advancement. He has also
guest lectred on co of capital for the public utilit industr before the Pacifc Cost
e _chment1
Page 30f3
Gas and Electrc Association, and for the' Exutie Seminar at the Colgate Darden
Graduate Schol of BusInes, Universit of Virginia.
Dr. Peseau and his firm have participated wi and been membe of the
American Economic Asociation, the Amerin Financal Association, the Western
Economic Assocation, the AUantfc Economic Assoiation and the Financial
Management Assoiation. He was formerly a member of the Staff Subcommitee on
Economics of the National Assoation of Regulatory Utilit Commissioers.
Dr. Paseau has ben Prsident of Utility Resourcs, Inc. since 1985.
e
CERTIICATE OF SERVICE
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J herby certif th i have th day served a copy of the foregoing DIRCT TESTIONY OF
DENS E. PESEAU ON BEHF OF SNWA in Docket No. 04- 8022 upon each of the pares lised
below by fasimile sece as follows:
Conne Westat
Sier Pacific Power Compay
6100 Neil Road
P.O. Box 10100
Reno, NV 89520-0024
Facsile [phone]
Shery McDonad. Man
Regulator Servces
Sierr Pacifc Power Company
6100 Neil Road
P.O. Box 10100
Reno, NV 89520-0024
Facsile (775) 834-8 i 1
Mar Simmons
Sierr Pacifc Power Company
6100 Neil Road
P.O. Box 10100
Reno, NV 89520-0024
facsime [phone]
Staff Counsel
Public Utilities Commission
i 150 E. Wiliam Stret
Carn City, NY 89701-3109
Facsimile [phone]
Alaina Bursbaw
Public Utilties Commssion
101 Convention Center Drve, Suite 250
Las Vegas NY 89109
Facimile [phone]
Tim Hay, Conser Advocte
Bureau of Consumer Protecon
1000 E. Wilia St, #200
Caron City, NY 89701-3117
facsimile [phone]
::ODMA\PDOS\LROD0C14968\\Page i of2
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Gerad Lope
Senor Deut Attrney Genal
Colorao River Commisson
555 E. Waslugtn Ave., Suite 3100
Las Veg, N' 89101-1065
Facsimile [phone]
Bil Koekeeir. Esq.
6005 Plum St., Su 301
Re, NY 89509
Facsime [phone]
Patrick V. Fagan Es.
Allson, MacKenie, Rusl, et at
P.O. Box 646
Carson City, NY 89702
Facimile [phone]
Charles Hausr
Soutern Neva Water Author
i 00 i S. Valley View Blvd.
La Vegas~ NY 89153
Facsmie [phone]
Des Pesau
Utilty Resours
i 500 Libert St., Suite 250
Salem OR 97302
Facsimile [phone]
Jacqueline Roinbaro
Bep
1000 E. Willam St., Suite 200
Cason City, NY 89701
Facmile [phone]
Dat iI. UI¡ da ofOd. 2~e:
~-- -_._~~âl' J ..~
::ODMA\PCDOLRNOÐI4961
Pae 2 of2
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',¡
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.' " , ,,' ". RECEIVED ~i
BEFORE TH PUBLIC UTIS COMMSION OFi.JQi\P~ ~ _~(),!mi~!'imi~ .' . ". \...,. .... . '. '! . .. I
03 SEP 1.9 AM 10: 36
In re Applicaton ofNEV ADA POWE COMPANY to )
Amen its Amended Demand.Side Plan of Acton for it ), 'Refiled 2000 Resour,Plan. )
)
/
Do No. O~-60S6
In re Filng by NEVADA POWER COMPAN FOR
Appva ofits 2003.202 Electc Resur Pla, ' '
)
) CDõe-No:-03õõ100J
)
/'
i
PREPAR TESTIONY OF
DENNS E. PEEAU'
",
. Submi~by~~,FreS~, '.
Hale Lae Pee Deson an Howa ,
777 Eas Wilia St, Suite 200
C~n City, NV 897Òl
(715) 6846000
Attmeys for
SOUT NEADA WATE AUTIORI-
.,.,,-
.,
1t ;-
Of '..
B~FORE THE ~UBlIC UTILITIES COMMISSION OF NeJAOA
pocket No. 03-700'
Dire Testimony of
Dennis E. PeseLi
on behalf of
Southem Nevada Water Autori
1 Q. PLEAE STATE YOUR NAME AND BUSINESS ADDRESS.. ,
2 A. My name is Dennis E. Peseau. My busines address is Su~ 250; 15QO
3 . ,libert Stre, S.E., Salem, Oregon 97302.
4 Q. BY'WHOM AND IN WHAT CAPACITY ARE YOu' eMPLOYEO?
5 A. I am President of LItHity Resourcs, Inc. MY firm consult on a number. ~f
. 6 economiè, financial and engineering matt for various privàte and public7 - enti.
8 Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
9 A. I am tetifing on behalf of the Southern Nevada Water Authority (SNWA).
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~ ~ DOES ATTACHMENT 1 ACCURATELYDE~C~BE YOUR BACKGROUND
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AND EXPERIENCE?
A.Yes.
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WHAT IS THE PURPOSE OF YOUR TESTIMONY?
My testimony focuses pnmarily on five ares or issues 'Nhich l i~enti below.
To place these issues in perspect, I note th tbe overall,tenor of.,., "
Nevada Power's filed Resource Plan is the Commitent to an ambitious'
capitl expenditure proram to greatt expan~ the'Company's own géneration
, and transmisGion plant over the next deCade. The SNwA has provided
testimony in prior Nevada Power dockts including reource plans and
continues now to recognize' and point out the inadequate I~vel.of int~~al
"
generaion and transmission resource addItions made to the Nea po~r .
system over the last decade or more. New ~dditons are necesary and v~i .
to the electcal sýstems.,reliabilit in southern' Nevada. The SNWA heartily
supports, the timely completion of necessary trnsmission and generaion
facilities.
But ~ number of Nevada Power's føinclal proposals in it fding, and
circumstances 'extrnal to its Plan, are simpl ,Incompatible. wit the.
, Company's propose new geiieration and transmj~ion ex~enditures. and it
abilit to maintain any semblanCe of financial stbilit at rate lev,els -thåt are
acceptåble to its customers.
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1 I point speccally to its plans, to issue over $1.7 bilion in debt but no
equity over the peñod 2003-2009 and it decision to begin using project~d
avilable cash to spend in dMdends rather than finance new generation and
transmission facilities. The most recet extrnal circumstance I refer to Is the
August 29, 2003 adverse ruling by a U.S. bankruptcy court to "issue summary
judgment for Enron against Sierra Paciic Resources regarding Enron's tlaim
for liquidated damages. Instead of outining correcive measureS to reairi its
financia~ foothold while making crucial invtments. Nevada Powr instea~
requests a pre~apRroyal of some $40Q-00 milion per year in exenses tJ:at
have historically been scrunized in deferred energy and general råte cases.
This testimony wholeheartedly support and encourages the generaion
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and transmission investment necessary to meet presnt and growing
electñcity requ¡reme~ts and offerS altrnatives to Nevada Powe'r's'proposals.
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WHAT ARE THE FIVE PRIMARY ISSUES YOU ADDRESS?
The five issues are:
1. Nevda Power should avail itelf of purchas powr product
that are suited to it unique summer needle peaking load profile,
rather than continued excessive reliance upon 6x16 or similar
high energy products purchased previously. The SNWA has a
'uniq'ue load profile and its own significant resource product
which Nevada Power should avil itelf of or fully evaluate to
help avoid the large credit.rlsk premiums being demanded of the
Company by vendors on the opn market.
'2. Nevada Power prôposes in this proceeding to begin giving $53
milion per year of it scarc cash flow to its parent Sierr Pacif
Resources begInning January 2004. Given Nevada' Power's
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deteriorating capital structure, such an acton is even more iD..
advised than when the Commission rect such dlvdends1n
Docket 02-4037. The Company's abllty to complete the
importnt Centennial and Harry Allen-to-Mea newtrànsmission
projects, as well as fts proposed generaon will not bè able to be.
financed at reasonable'costs if Nevada Pow gives up this cash
flow.
3. Nevada Power prop.0ses perhaps the móst, '.sweeplng
guaranted cost recovery mechanism in Nevada's regulatóry
history In this Resource Plan docket Some $400-00 milion In
fuel and purchåsed power cost per year are being requeste
to be pre-approved in this docket, removing ,the typical and
appropriate review given the.e expenses in deferred energ arl
general rate cases;
4. In conjuncton with its reuest for preapproval of most fúel ah
PP-expense, Nevada Powr reuests that the Commission.
approve the cost of the call options It has already entered Into
and those it proposs to enter. Recovery of ttese costs is
appropriately decided outside of a resurce plan proceeding.
Any decision regarding call option hedging stategies should bè
evaluated in deferrd energ rate proceedingS.
5. Nevda Powr is proposíng to move from its' policy in recent
years of puising wholesale power 100% on tie short-trm
market to, in this case, purchasing "s signif~nr amount on the '
long-term wholesale market. Proper risk diversification,
techniques would. suggest a more balanced or "portalio. mix of
purcases. Nevada Powr has not provided adequate rilk
, a~alYsis in this re~ard.
29 CONCLU~JONS AND RECOMMENDATIONS,
30 Q. PLEASE SUMMARIZE YOUR RECOMMENDAnONS.
31 A. 1 recommend that the Commission:
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1.Order Nevada Power to fill its huge open position with demand
and supply side resourcs that both fit its load profile R~d
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minimize cost. Nevada ,Pow should, during the nex six
'months explore with the SNWA the unique load charactiSics
and reourcs SNWA has available in Nevaa Powers service
terrory. The $500,000 in thre year actiòn plan funds
requested by'Nevada Power for a coal study should be deferre. '.
until Nevada 'Power report, back on it progress with SNWA.
2. Order, 'or put Nevada Powe on notice that it '.wil order th
Company to consrve çash by prohibiting dividends taUs parent, 'until a 42% eqLlity raio is reached. '
3. Deny Nevada, Powets request for approval 'of .it
"Recçimmerided Gas Hedging Stratey" In th~se procings
and defe any such decison to the next deferred energy eaSe '.
4. . Defer any decision on the appropriat expenses for Nevaa
Power's proposed natural gas call options to the next déferred
energy case., '
. '5. ' Require Nevada Powr to furtller study and report back on .an
appropriate purchased power portolio mix before enacting lI
proposed movement. from the previous polic of purchsing
100% on the short~term market to purchasing as much as 100% '
on the long~temi market. '. '
.21 FllLING NEVADA POWER'S 3,000 MEGAWATT-OPEN POSITION,
22 Q. WHAT IS THE ISSUEWIl RESPECT TO NEVADA POWER'S FILLING OF.'
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ITS HUGE POWER SUPPLY SHORTFALL?
A.As the Companyexplains throughout the supply side plan, energ supply plan
and financial analysis plan portions of it, filing, Nevada ~ower has the, . .
daunting task of procuring at least half ol it required por supply. from
sources as yet unidentifed. The Company proposes to filJ the deficlt of up to.' . . '.. .
3,000 megawatts ,per yeâr by the issuance of'an RFP designed.lQ ac~uire '
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long-term purchased power contrctS-of 3-1' 0 years. While Neva~a Por has
r~cently been unsuccful, accrding to its teSimony in othr proceeding,.-
in attcting responses from vendors In RFPs, i agree with its assessmentthat
the temporary apparent ~dequaey or even slight surplus of reiol generation
may change these generators willngness to respond to Io~g.term contract
The issue is whether Nevada Power wnl be able It attract the rather. unique
and .specialized energy product it requires to optially fiJI it needie-peaki~g
loåd shapes.
9 Q. WH DO YOU QUESTION WHETHER.NEVADA POWER CAN ATTRACT
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THE PARTlCU~R PURCHASED POWER PRODUCTS IT NEEDS?
A.In the last two deferred energy proceedings Nevada Power argued for cos
recvery for losses it incurred frm havIng to resell excess energy resulting
from contract base upon almost exclusively 6x16 purchas. That ~s,
Nevada PoWer felt th In order to fiJI it open positon it was forced to enter
contracts requinng it to purchase energy six days a week, for sixteen hours pèr
day. Since Nevada Power typicaUy only needs peak energy for four to eight
hours per day, these preOUS 6x16 energy contracts caused Nevada power
to acquire substantially more energy than it needed. The excess iNs sold at
huge losses. .
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The question that ari in this filing is whe~er NeVad~ Powr will h~ve
opportunites through it ,prposed RFP procs .to obtain othér t~an 6~16
energy product.
" .
',4 Q.DOES NEVADA POWER'S RESOURCE PLAN FILING J:PRESS THE
5 o HOPE THAT IT MAY THROUGH ITS RFP PROCESS, FIND WILLING
6 PARTICIPANTS TO ENTER INTO SYNTHETIC TOLLING AGREEMENTS
.0
7 FOR POWER, THEREBY REDUCING ITS 6Xi'S OBLIGATIONS?
0,
8 A.Yes. The possibility of entering' synthetic tol~ing ágr~ments is mentioned at
9 : a number of places in the Company's'application.testimony and exhibits.
10
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Q. WHAT (S.A "SYNTHETlC,TOLLlNGft AGRE:~MENT?" 0
A. Tolling is a means bY which a utlit such as Nevada Power can ácquire leg~1
rights to çapacity of a pl\rtcular generating plant owned by an independe~t
part by agreing to pay (usually) fixed demand charges. . A synthet tollng
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agrement Is similar'but not necessarily'tied to à particular plant Anyenérgy. '. ., 0
output requested by Nevada Pow is chargd to the Compan' by th .
independent part on the basis of the market price of gas and a heat rae. or
by Nevada Pow actually acquiring and providing the actal supply.
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1 'Q. IS THE EXECTATION BY NEVADA POWER OF THE OFFERING OF
2 TOLLING 'AGREEMENTS BY OTHERS REASONABLE?
3 A. At some set of prices and terms this expecation is' resonable due to'.a. .'
4
'.5
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app~rent present adequae or surplus of indpendently owned gene('ting ,
'cåacity in the western U.s. If independet ower~ o.f. 'genertion can
. negotiate tolling pñces and terms that exeéd those ~ey cò~ld get on the, .
. open 'market, it is 'reasonable to assume they wouid .-re,spond to, Nevada
Power"s proposed RFP.
,9 Q. , ': IN YOUR OPINION WILL NEVADA POWER FACE PAYING A CREDIT-RISK,
10 PREMIUM FOR ANY SUCH TOLLING AGREEMENT?
11 A. Yes. Due to Nevada Powr's financial cirçumstanÇe it is rea~onabl9 to. ,, .
12 assume that any long-term agreement, tpltng or otherwise, wil have an ,
, ' 13 associate credit premium attached to it.14 .J . '
15 Q. WILL THE HOPED..OR TOLLING AGREeMENTS LlKELY PROVIDE
16
17
POWER SUPPLY OFFERS THAT WILL IMPROVE UPON THE PAST 6X16 "
LONG-TERM PURCHASES?
18 A. Yes, altough the m,or.concentrated ~ purchases are made to conform to
19
20,
only the highes~ peàk hours of the day, the highe,r will be the capacity and,
probably, energ premium charges associated ~ith any tollng contråct.' The
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value to Nevada Power and It customers òf such narrowr peak power~, Of
cours~, enhanced as well.
3 Q. WILL NEVADA POWER LIKELY BE ABLE TO FILL MO$T OF ITS
5
PROJECTED 3.000 MEGAWATl' OPEN POSITION WiTH 'TOLLING
AGREEMENTS?
4
6 A. . The Company does not identi what percntge of itS RFP pross mlglR be
7
8
fiired Wit~ tollng agreements. Nevada Powr does, howver; indicte that 'I
prefers to fill it open position largely with long-tenn 3-10 year contrcts. .
9 Q. WHAT, OTHER PURCHASED POWER PRODUCTS SHOULD NEVADA
10 POWER ATTEMPT TO ACQUIRE TO FILL ITS OPEN POSITION EITHl:R
THROUGH ITS RFP OR OTHÉR NEGOTIAnONS?,1:1
12 A. The SMNA a~d it member agencies, or "wter pumpers,!" togethér haye, '.'
electc loads today in excess of 200 megaWatt Inside the uloåd control" area '
of Nevada Power. Alhough most of that load Is not actually supplied by
Nevada POWer this load will increase to over 300 megawatt by 2005. Trt
combination of the water pumpers'typically of-peak pumping, the abilty to be
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interrpted within limit during on-peak hours, their own signifcant capacit
and energ requirement and a strong financal market credit rating together
provide an almost perf profile to fit Nevada Powets peaking requirements.
I am confident that a good faith effor on the part of Nevada Power and the
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"S
wat~r pumpers could lead to the mot economical resource ~ fiU a slgnlfam
porton of their open positon immediatel. "
Furthermore, the recent activties of the SNWA to bècome a 125 MW
participant in the local Sitverhawk cobined cycle generating plan (~iCh.ls ., '
scheduled online by, next spring), their recent effòrt:, to s~cure firm
. transmissfon rights, and significant but preliminary analyes int th viabilty'
, and siting of fluidizd-bed coal-fired generaion facilliee c~uld grea~1y assist
Nevada Power in it efort to secur additonal supply.~. '.
9 Q., PLESE BRIEFLY DESCRIBE THE NATURE OF THE WATER PUMPERS'
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'A
ELECTRICAL SYSTEM, LOADS AND REQUIREMENTS. .
The water pumpers' electcal needs are ~rved, within Nevadri P~~r's
servic territory both as a cutoiner of Nevåda Power and' as a whoiesa,~. .
customer served by the Colorado River 'Commission (CRC). At present. a. .
signifcant amount of megawatt water pumping loa is serv by Nevada
Power and up to 125 megawa ~rchased through 'the eRe ~rim~r¡1y to
operate the vast Saddle Island complex (whic SNWA owns) comprising,
facilties and pipelines necssary to pump water up and into and within the
las Veg~ valley.
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1 'Q.' WH~T.TYPE OF "CUSTOMIZED PRODUCTS" DOES N~ADA POWER
2 INDICATE IT NEEDS TO FILL ITS OPEN POSITION?
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, A.In Vo.lume LV, the LQad Foreast and Market Eundilmentåis, Page 17, th
Company descrbes the need for power proucts for capacity and elierg of
relatiely nerrw intervals of a fe hours to meet needle 'peaking nature of it '
, system.
7 Q. DO THE WATER PUMPERS HAVE THE ABILIT TO PROVIDE NEV~DA'
8 POWER WITH SIGNIFICANT QUANTITIES OF SUCH' CÜSTOMIZED
, 9 . . PRODUCTS?
10 A., Y.es. The watr pun:pers have a significant amount of both demand s~de and
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supply side products. The abilty to provide these 'custom procuet' 'is, af.. '. .:.". ,
C?urse. subject to, Nevada Powets wilingness to take advantage of s~ch
opportnites.
14 ' Q. PLEASE GENERALY DESCRIBE THE POSSIBLE DEMAND ,SIDE AND
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SUPPLY sioe CUSTOM PRODUCTS .THAT COULD BE OFFERED BY .
WATER PUMPERS.
A.Demand side pro~uct include those that proide, the abilty for Ne~a Power
18 ' to' avoid purchasing otheiwise'scarce and expensive onileak poer supplies... . .. .
19 ' In the ca~ of the retail water pumping lo~ds seiyed by Neyada Powe:r. under, , ,20 appropriate term and conditions, th water pumpers can interru~t capacity' .
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falit located at Apex, Nevada. . The energy produce from this locil "
generator is capable of shaping to accommodae a maximum' of output,
consumption In the off peak for water pumping, leaving the plants peak
capacity and energy available for custers of Nevada Power;
FinaOy, Nevada Powr Is requesting'in its filing to ~xpend $500,000
over the next tw years to study the feasibilit of an undesignated coal plant. .
As part of its ongoing effort to minimize energ cost and satisfy it g~ing
, ,
4
8 ' . ioad requirement, the SNWA forsome time héS been explorng the econåml~, .
. 9 feasibilit of owning a share of a coal plant and has arrèady commit
, 10 $1,000,000 to study ne coal generation feasibiliiy. Just as Nevada Poers,
,11 Reid Gardner 4, coal plant Jointl owed 'by Nevada Power a.nd the water
.12 pumping CalifornIa State Agency (OWR) is an example of a succssful
. 13 private/public ,partnership in electric generation, the study at' a 'co-venture
14 betwen Nevada Power and the SNWA could be very beneficial to Sòutem
15- Nevada. It is also importnt to recnize that SNWA's Double M-. crit.
16 rang from Standard & Poots is certinly unique among pow proucers ar
17 'elecric utilities In general.
18 Q. WHAT DO YOU SPECIFICALL'('RECOMMEND? .
19 . A, Nevada Power should pursue ~sourc optons wit SNWA and report back
20 to the Commission within six months or at least prior to the 2004 peaki, ,
-21 season. In the interim, the Commission should defer approval of Nevada
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1 and energy supplied for mos of their Intemallod requirement for four or So '
2 hours on summer peak days. Of course. this doesn' evn up 'to include
,3 sevral hundred additional.MWs of SNWA lod supplied by.eRe. Nevada
4 Power was unable to locae and purchas thIs type of custom product In the
5 past few summer seasons.
6 Anoter very valuable demand side custom product potentially ava¡la~Je
7 to Nevada Power is an enhanced abilit to protect system reliabili 'by, , .
8 coordination of load sheding a~i1ties off of SNWAtransmisslon laterals urider
9 instaces of sytem emergencies.' '.
10 Q. WHAT WATER PUMPING ~ESOURCES ARE POTENTILLY AVAILABLE
11 TO FILL NEVADA POWER.S OPEN POSITION?
,12 A.In the near-term. the water pumpers either heve. or wil hav substantial power
under contract to meet its own loads that are not served by Nevada- Power.
Typically. ,the economics of minimizing costs dictates that the power provided
under these contrct be 'Shaped into a maximum amount of off peak usag..
for water pumping. and the remainder resold, Into higher prd peak
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.,wholesale markets. This large amount of peak capaci and ~nergy product
Is likely to be a near penect match'to fill Nevdà PoWets needle ~aldrigload
J?rofile.
By next summer, the SNWA intends to add to its power supply program
the 125'megawatt share of the Silverhawk combined cycle combustion turbIne
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,1 Power'~ three. yea.' action pfan request for approval of $500,000 on a coal
2 project feasibi.lily study.
3 NEVADA POWER'S,CAPITAl EXPENDITURE BUDGET IS AT Rl§K
4 . Q. . WHAT IS THE ISSUE WITH RESPECT TO NÈVADA POWER'S PROPOSED
'5 . CAPITAL EXPENDITURE BUDGEr?
6 A. Even with a modest leve of reuired capitl expenditures Nevada Pçiwer
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would be challenged to finance invesment on reasonable tenns at reasonaQJe
.: cOst~. Nevada Power's projectd budget for capital expenditre Is anying. .
but modes~. Tåble 4-3, page 298 of Technical Appendix ll in the Company's
filin reflects the following tota capital budg~t
11 Capitl.12 Year Re,gulremenl
13 2004 $347,435,000142005 .448,1'51,000152006448,505,000162007399,885,000172008.440.861,000182009566,409,000192010477,753,000
..
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,Attchment .A Of the Company respone to BCP 2-28¡ included a~ my
Exhibit_(DEP-1), breaks down the annual capitllnvestment by fi.nc~n. For
the period of the Aciòn Plan, 200+2006 alone, the capital reuirements are
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1 $ 1.2 bilion. The issue is whether Nevada Power's desire- to ~In is,uil'g , .. .
2 . , dividElnds of $53 milion per year, beginning January 1, 2004 i~ consisterit,
,3 wIth the fjnàncial stature necessary to i:ise, such large amounts of cåpital
4 ~lIe maintaining a healthy capitl stctre:
"
5, .Q.
6 A..
7
B
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10
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WHAT fS A HEALTHY CAPITAL STRUCTURE?
A hèaltiiy c~pital structre, is a balanced proorton of outanding debt "an
còrron equity sufcient to att,act additiona eapitl- both debt an eqi:ity:-
on reasonable terms. Nevada Powr for years ,has had far'too much debt,
also termed excessve .Ieverage~, in its capital Structure. Re~giiizin9 this
high degree of le.verage, and the reluctance of Nevada Power ta Issue ample
. common stoc, the Commission 'in Docket 02-4037 prohibited the Ceip~ny
from issuing d.ivdends to Sierra Pacific Resources until eiter thè Company
hit a target of 42% equit ratio as a perCntae of total capital',' or Oecemb,er
S1,2003.,
15, Q. WHAT IS THE CURRENT EQUlTY RATIO OF NEVADA POWR?
16 A., 35%; as indicated on page 82' of Volume Vt of the Integrate R~our~ Pla~
'17 2003.
~1s.
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,1 Q.WHAT ARE THE FINANCIAL CONSEQUENCES OF THÈ 3~%' EQl!1T
. : ~.2 RATIO?
3 A.There are tw very negative consequences ated to this Jow equit ratio.
4 .One, the low equit ratio means too high of a debt ratio. Too high of a debt
,.S rati raises the interest rate which Nevada Power must pay for new ~ebt,
. ..6 ' Secnd, the lo equit ratio disq~alifes Nevda Powr frm rea.lning
7 investment grade credit'ratings. Nevada, Power's debt is currentl rate~ .~t
8 Ujunk- 'Ie~i, or below invstmel1 grade.
..
9 Q.DOES NEVADA POWER HAVE A T~GET. EQUITY RATIO?
.10 A.Yes.The Companýs targe equity ratio' is 42% (pge 82, Vol. vi, IRP).
11 Nevada Powr indicétes that a 44% actual equity ratio Is needed tó, regain
".',12 Investment grade ratings (page 85. Vol. Vi, IRp)..'
13 Q. I:OW IS llE EQUIT RATIO JN~REASED?
14 A. The equity ratio can be increased by financing the capitl budget with neW
15.
16
issuances of common stoc, and/or through internally generaed fúnds In ~
form of retained earnings.
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1 ' Q. DOES NEVADA POWER INTEND TO ISSUE NEW COMMON STOCK?,
2 A. No, not until at least the year 2010. MY Exnibit.:..JDEP-2) reprouce ,thè
3
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extemalfinancing plans of the COmpany (pg. ~98. Tech.'App:ll). ,Ali financing.. .. .
'prlor to 2010 is debt
5 Q. DOES NEVADA POWER INTEND TO' REDUCE ITS ~TERNAL
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8
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'FINACINGS BY MAXMIZNG INTERNALLY GENERATED aAPITAL
fUNDS?
A.No. Nevada Power intends to rèuce its Intemafly'generated funds by åt least
. $ 53 milion per year 'and issue a like amount to Its parent in the form of
divdends for yers 2004. 2005 and 2006 (pg. BO, Financial Plan, Vol: VI).
"
"
:. .
11 Q , .
TO WHAT OTHER PURPOSE SHOULD NEVADA POWER APPLYTHE $ 53
, 12 MILLION PER YEAR IN DIVIDENDS?
13 A. " A more prudent use of the annual cash of $ 53 milJOn is to reduce the annual
14 amount of projected debt issuance by an eq'ùal amount, NevGda Power
15 presently and will for years fåce a diffcult market for its, debt. In its mos '
16 recent finance docket,Nevada POlNr had to refinance unseered6% debt for
17 secured 9% debt despite the fact that market interest rates had not move.
18 Nevada power's plan to issue $ 53 mUlion in divdends to its 'parent simply. ,
19 ' removes this amount of otheiwise readily available capital from internal funds
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, ,and reuires a Jlke amount of expnsive, poorl rated de~ to be Issue,
further'lowring its equit raio.
"
3 .' Q. WILL: NEVADA POWER FACE ADDITIONAL DEMANDS FOR ITS CASH IN
4 THE NEAR FUTURE?
5 A.. . . .Yes.. Unless the recent decision of the U.S,. l:ankruptcy court is reversed,
Nevada Power will ~eed approximately $ 229 milion in cash in the neàr,~re.6
. . .7" Q. WHAT PRACTICAL CONSEQUENCES WILL RESlRLT FRaM ~EVADA
8 POWER'S DIVIDEND PROPOSAL?
9 ' A.' The proposed dividends and their êffect of redUCng the already low equit
10 " , ratio. wilf signiflcantly increase the likelid that Nevada Power wil' ~ot be
"
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able to meet the level of capital expenditure~ ,contined in its resourc plan.
:",.,With its 3000 meg~tt open posiion and its modest .amount of self ownl:
generation, the transmissiòn and generation expenditures in the budget are, ,
crcial for maintaining systm 'rellabllity in southern Nevda.' As was the .
. positon in the last resou~ce plsl1 docket, the SNWA continues to rècommend., .
that. the capitl budget be maintained at the highes leVes. In particula, .
Nevada Power should conserve its internal funds to ensure the timely
completion of the Centennial Transmission Proect prior to the 2007 peak.,
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1 NEVADA POWER'S REQUEST FOR PRE~APPROVAl .
2 OF DEFERRED ENERGY COSTS SHOUlJ BE DENIEP. ,3 . Q. WHAT IS THE ISSUE WITH RESPECT TO NEVADA POWERlS REQUEST
4 TO HAVE THE COMMISSION IN THESE PROCEEDINGS PRe-APPROVE
COST RECOVERY REVIEWED IN DEFERRED ENERGY.AD GENERAL
RATE CASES?
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7
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A Throughout the Company fillng, the request is made to approye a
"R,ecommended Gas Hedgin Strategy.' While reource plans, action pràns,
strategies and sPecific 3-year capital expencJitures are normalry In the purvieW '
of IRP proceedings, the Company requests reai:ing the approval',of a "Gas
, .
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12
Hedging Strategy apparently goe far beyond resource plan pro~Ings.
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Nevada Power's request is actally for the pre-approval of several hundred
millon dollars of natural gas ~ts for ga& yet to be purchased,. b~t rtonnally
reviewed in deferred energy proceins.
15 Q. PLEASE EXPLAIN.
16 A. Nevada Power's proposed Hedging Stegy requests approal fortw distinct
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expenses: one, th recovery of natural gas cost in 2004 incurred for Jl its '
own pJan:t and the coSt of the el~tricity purchased through the antcipated
tollng agreements to fill Its 3000 megawatt open position and, twò, recovry
for the e~nses attbutable to the prop~se call option~ on 100% of the gas
1 seè Application Pages 7-8; Yachlra, Page 6. Unoa 17.21; Iv, Page 3, Lines 6-; Acon Plan, Pas-
2-3; VOL. I, Page 16; Vol. II, Pa 2, 45 , ' '
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5 Q. ARE FUElAND FUEL ACQuismON COSTS NORMALLY AP~RoVEO IN
6 'ADVÄNCE OF PURCHASES?
7 A.. No, in the several fuel cost recoery proceedings in which i have partìcipa. '
8 . revery of fuel costs is granted subsequent to 1he actal incurrin of theS. ... . ~9 , costs.
1Q', Q., ÁRE FUEL AND FUEL ACQUisitiON COSTS USUALLY APPRÓVED IN
',11.
, ,
RESOURCE PLANING PROCEEDINGS? ': .
12 A. No, not in Nevada.
.13 . Q. PLEASE ESTIMATE THE LEVEL Oi: FUEL AND FLJEL ACQUJSlnON
14 EXENSES FOR 2004 ALQ-NE THT THE COMPANY IS SEEKiNG.
15 A.' The followng table summarizes the four dfstlnct areas otcost recorytN¡ ,
,16 Nevada Power IS'requestlng for fuel and fuel acquisition cost: '
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Annual Exense
(milion.)
. $196 .
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370
18
Natural Gas for Own Generation 1
Call Options for Ow Generation2
Exòsure for Tofled Generatiòn3
'call Options for Tolled Generation"
Total, NPC Cos Recvery Request $6Ò4 milion
As show In the table, the single point fuel cost estimate for the 2004 rery
reuest of Nevada Power is $604 million, which Includes the cost of physical
, : gas and hedges,for it own generation resourcBS, pl~ th cost ~f phyical ga~
and hedges for the gas that is procured for the t~lIlng agreents as;ociated
with the proposed RFP. The estimate assumes that the cost of call options
Is only $.025 per met and the talling capacity' fåctor is 45%. each of which '~~y , , ..'
be conservtive.
19 Q. WHAT APPROXIMATE AMOUNT OF THE TOTAL DEFERRED ENERGY
20
21
COSTS NORMALLY REVIEWD IN DEFERRED ENERGY COST.
PR,OCEEDINGS DOES THE $604 MILUOl4 REPRESENT?
1Page 3S. Vol: II
lAS8umec $.2 pri of option alÚugh it is likly ths numbed.s much higher. .
'Exhib"' (DEP-3)
"Assumed $.25 price of opti altough Ills lily this numbr Is much higher.
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1 A. Up to 80% when compared to total ful and purchased power BTER eXpnses' '
2 !n Docket No. 02-11021. The only signIficant remaining cOsts rèf out of this
"hedging stråteg are those associate with ~oal, oil and certain' othèr
miscellaneous items. Most of the purcased power (tolling) 8J1d natural gas
costs are included in the hedging stra.
3
4
5
6 Q. ~~T IS YOUR RECOMMENDATION WITH REGARD TO APPROVING,
7 THE HEDGING STRATEGY?
8 A. The hedging strategy is nothing more than making natural gas purchases 'on '
9 ' the spo market at market prices, with a call optian for strike priceS' ou ò~ the, '
10 money. I recommend that the Commls~ion defer any exlici or,implicit "
11 approval of the costs incurred as a result of any purchasing' and hedging
12. strategy to the next deferred ertergy cost proceedings.
13
14 DEFER DECISION ON PRUDENCE OF COSTS OF GAS CALL OPTIONS
15 Q. WHAT IS THE ISSUE REGARDING NEVADA POWER'S RECOVERY OF
16 THE COSTS IT INCURS TO SECURE CALL OPTIONS FOR NATURAL,
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21
A.
GAS? ,
In the previous deferred energy proceeding, Nevada Power indicted that,.
while call options provide protection. they have a significant cost (Reid
Deposition, Exhibit 2) the October 15, 2001 memo to'RMC. Given the
signifcant cost of call options then, Nevada Power decided to cover a slTan
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portion of it naural gas purchases with these options. T~e issue here is
whether the Comrri~sìon in this resource plan proceeding slioul~ autoriz ~.' .. .
endors the level of costs thatthe Company would incur in going' now ~ a
100% call opton steg.'
. . . .
Q. WHAT WILL BE NEVADA POWER'S COST OF CALL OPTIONS UND~R
ITS 100% PROPOSAL IN THE RECOMMENDED GAS HElllNG,
. STRATEGY?
A.
. .
We, of cours, don't know in a~vance. In Nevad~ PoWteim~ ~ l)ket
No. 02-11021, the C,?mpany indiced that "coll~r ~ptÎ,ons" which are less. .
exensiv than the call options propoed in its Recommended stregy, we.re
5-10 cents per mef (Reid, Direct, Page 5, Lines 13.;14, as modified òrallyat, '
hearings).". ' ~.
The cost of natural gas call options as of the time.of the writing otriy , .
tesmony was between '70 cents and 84 cènts per mcf for December 2003 "
natural gas. Call option for periods beyond Decmber wold be ~uch ..
higher. ., . ,
As an "orders of magnitude" estimate for, the call oPions propøsed by ,, ,
Nevada Powe.:l use a 7~ cent per mcf cost, and the gas quantities ,I
developed in Exhibit ~ (D~P-3). The estimate of the COS~ of just theSe
financial instrument, with no physical gas associated wi it, ìs.$85 m~ni~n ~~r
year (. ~5/5 ." 666).
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Q. HOW DO YOU RECOMMEND THE ISSUE OF THE RECOVERY OF CALL
OPTION COSTS BE CONSIDERED BY THE COMMISSION? ,
A. Firs, I recommend that Nevada Power proV~ addltiona! testimòny on ,it.
position on this Issue,' given that the market price for caD opt. has .
increased so much from'the time its'strategy was origin~tec.
Secnd, . given the uncertinty and tremendous costs tõday of. call. '
options. the Comm~ssion should defer any decision on the appropriate levels
, of optlons costs into the more ~pprpriate setting of the deferred energy
proceedings. In Uiis way the timing and prudence of the options could be. . I .
appropriately evaluated. "
,11. REQUIRE ADDITIONAL ANALYSIS BEFORE
12 LOCKING INTO 100% LONG TERM CONTRACTS
. .. . . '
. ,13 .Q. WHT IS THE ISSUE REGARDING NEVADA PO~R'S REQUEST TO BE
14 " AUTHORIZED' TO ENTER LONG~TERM PURCHASED POWER
'15 CONTRACTS TO FILL ITS LAGE OPEN POSITION?
16 A.. Nevada Power's request for approval of it long-term RrP proceSs and a'.'
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19
20
21
, , '
100% hedged position for Its financial gas exposure wUllock ratepayers Int
a huge financial' commitment.
I am generally not opposed to a considerable intermediate or long.term '" '
purchased power position, but aii such decisions must be wei9lld with risk
and portolio miX considerations.. The issue is whethr the timing Of this "
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resurce plan coupled with the extremely weak finance position of Ned.a' .
power make this a prudent time to lock signifcantly into long-term RFP
contrct.
Q. PLE.ASE EXPLAIN..' .
A.Prior proceding~ have made evIdent. tte very weak. finåncial position of
N~vada Powr and the creit~risk considerations that all vendors will ~e(gh.
when propOsing to sell to Nevda Power.' Credit-risk premiums grOw
exponentially with time. Thus, the terms and coditions under which a power .
supplier would sell to Nevada Powr must bemll much more onerous u~r
a ten, year contract than ~nder, say, a o~year summer peaking ~ntract.
The proposed toiling agrement hav& litte effect on these risk premiums.
12 Q. WHT lSYOUR RECOMMENDAnON ON THE ISSUE Of NEV~D~ POWER
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A.
LOCKING INTO SIGNIFICANT AMOUNTS OF LONG-TERM PURCHASED
POWER CONTRACTS?
The actual dègree to which customers are going to be ask~ to assume a
credit risk premium cannot be known until the long term RFP pros is:, , ,
compleed and Nevada POWer has flied it Amended Plan. I urge the .
Commission to set aside sufcient time to evaluate the results of this procss
and order any changes to th purchased power reource mix that it cO,nctudès
is warranted.
-25-
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1 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
2 A. Yes:'
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AFFIRMATION
I, Dennis E. PeseaLl, pursuant to NAC 703.710 hereby affrm that the.
foregoing prepared testimony was prepared by me or under' my ,direction and is. correct to the best of ITY knowledge. '
Signed lL;i:-..
Dated Septemer 19, 2003
e,'e
Attchment. 1
Page 1 of3
STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUAliFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conductd ecnomic and financial studies f~r regulated, '.
industries for the past twnty-eight years. In 1972, he was employed by Southém
Cafifomiå Edison Company as Associat Economic Analys, and later as Economic.
. Analyst His responsibilties included review of fiancial testmony, increentl cost. .'
. studies, råte design, ecoometric estimation of demand ~fasticiies and various areas. ,in the field of energy and economic growt. AIsoi he was asked by Edison Elecl. .Insttute to studY' and eVåluate several prominent energy models as 'part ofthe Ad
Hoc Committee on Economic Growh' and Energy Pricing,
From 1974 to 1978, Dr. Peseau "was e"!ployed by the Public Util;~
Commissioner of Oregon as Senior Economist. 'There he conducted a number of .
èconomic and financial studies and prepare testimony perting to public utilities., ,
In 1978 Dr. Peseau established the Northwet offce of Zinder
Companies, Inc. He has sj~ce submited teimony on economic and financial. . . .
matters before state reg~lat~ry comissions in Alaska, California, Idaho, Maryland,
Minnes~ta, Montaná, Nevada, Washington, Wyoming, the Distnct of Columbia" tn'
Bonnevile Power Administration and the Public Utilitfes Board of AlbeJ1 on óver one
hundred occasions. He has conducted marginal cost and rate design studies and
e:e Atchment 1
Page2of3
prepared testimony on these matters in Alaska, California, Idaho, Maryland,
Minnesota, Nevada, qregon, Washin,gton ~nd in ti: Distic of Columbia. He has
, also conducted cost and ra studies regårdin PURPA issues in th'e sttes of
Alaska, California, Idaho, Montana, Nevada, New York. 'Washington, and
Washington, D.C.
pro Peseau holds th B.A., M.A. and Ph:O. degrees in economics.,. , ,. '
He has coauthored a book in the field of industrial organization entiÌ~, "
Size: ,Prots and Executive Compensation in the Large' Co~poration, whiè,h devotes
a chapter to regulated industries.
Dr. Peseaû has published articles În the following professional journals:
Reyiew of Economics and Statistie¡, 6tlantic EcoçmiC Journal. Journal of Financial . '
Management and Journal of Regional Science. His articles have been read befor
the Economec Societ, the Wesrn Econ~mfc' Assocation" the Finan~al
~anagement Ass!?ciation. the Regional Science Assocation and universities in tn~
United Kingdom as' Well as in the United Stte.
He has guest lecturéd on marginal costing methods in seminars in New
~
, ,Jersey and California for the Center ,of Professionfll Advancement. He h. also
guest lectred on cost of capital for the public utlity industr before the Pacic Coast
Gas and Electric Åssociation, and for the Executive Seminar at the Colgate Darden '.
, Graduate School of Business. Univrsit of Virginia.
ì
I,.
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It e Attchment 1
Page 3 of3
" ,Dr. Peseau and his fir have particpated ~ and ,been members of~e
Americ;an EConomic Assciaton, the American An~ncial Associaton, the Wester
Economic Association, the Atlantc Economic Association and th FinancJal, .
Management Assocation. He was formerly a member of th Stff Subcommittee on
Economic of the National Associion of Regulatory Utilit CommissiOner.
Dr. Peseau has been President of Utilty Resourcs, Inc. since 1985.
"
e -
PROOF OF SERVICE .
I hereby cerify tht I mailed the forgoing Prf1léd Testony ofDeis Pesea
ii Docket 03-6056 and 03-7004 by ~veriDg to the u.s. P~t Of,ce copes ~
propely àddres for maling to th followi pens:
Conn Westt
Nevad Power Compay
P.O. Box 10100
Reno) NV 89520
. Cheil Bacan
Nev Powe Compay
P.o. Box 10100
Reno, NV 89520
Tim HaBurau of Conser Protecton
1000 E. Willam str
Carso City, NV 89701
Jo1m Nielse.'
. West R.esource Advocate
2260 Baselin Road, Suite 200
Boulder, CO 80302 .
'.
, .
Jon Wellnghoff
.Beckley Singleton
530 La Vega Blvd. South
La Vega, NV' 89101
Oerd Lopez
Colorado River Commssion
555 E. WaSgton Avenue. Suite 3100
Las Vega, NV 89101,
lamesRo '
RCSln
500 Chesteeld Center, Suite 320 '
Cheseld, MO 63017
e
Michal Alcata
Alcan & Ka LL
1300 S. W. Fift Svenue .Suite i 7S0
Poran, OR 97201
John Gezin
436 Cour Stre~
Reno, NV 89S01
Willam Gehen
Teco Powe Service
702 N. Frain Str
Tam~ FL 33602 ,
Dale Stransky .
Buråu of Conser Prtecon
100 E. Willam Str Suie 200
Carn Cit, NY 89701
Er Witkos
Burea of Consu Prtection
SSS E. Wasngt Suite 3900
La Vegas~ NV 89101
John Nielsen
Energy Projec Directr
Wes Reour Adocate
2260 Baseline Road. Suite 200
Boude, CO 80302
Dated: Seembe 19, 2003
.
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BEFORE THE PUBUC lIILITIES COMMISSION OF NEV..Á' .: ", ';
04 JAH 2 7 PI; 3: 25
Application ofNEV ADA POWER COMPANY for authority
to incree its annual revenue requireent for general ras
charged to all clases of electrc cusomers and for properly
related thereo.
)
)
)
)
)
Docket No. 03.10001 ...._.. ..
Application ofNEV ADA POWER COMPANY for approval
Of new and revised deprecation and amortization raes.
)
)
)
Docket No. 03-10002
PREPARED TESTIMONY OF
DENNIS E. PESEAU
Phase Thre - Rate Destgn
Subnutted by:~~~
Fred Schmidt
Hale Lae Peek Denson and Howard
777 East Wiliam Street, Suite 200
Carson City, NV 89701
[phone]
Attorneys for
SOUTER NEVADA WATER AUTORITY
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
DOKET NO. 03-10001
Direct Testimony of
DENNIS E. PESEAU
On behalf of
Soutm Nevada Water Autor
Phase Thre - Rate Design
PLEASE STATE YOUR NAME AND ADDRESS.
My name is Dennis E. Peseau. My busines address is Suite 250, 1500 Libert
Street, S.E., Salem. Oregon 97302
BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
I am President of Utilit Resources, Inc. My firm consults on a number of economic,
financial and engineering mattrs for various private and public entities.
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
I am testifyng on behalf of the Southrn Nevada Water Authority (SNWA).
DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND AND
EXPERIENCE?
Yes.
::ODM\PCS\lLRNODOSI6979U1 Page 1 of12
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WHAT IS THE PURPOSE OF YOUR TESTIMONY?
My testimony in this rate design phase of this docket addresses tw issues. One, I
discuss a means to help reduce the greatly increased rate subsidy identified by
Nevada Power Company ("Nevada Powerj that does not raise the electric rates of
residential customers above levels proposed by Nevada Powr. Two. i identify and
correct a major error in Nevada Power's marginal cot of service study which affects
all water pumping rate classes.
WHAT CONCLUSIONS HAVE YOU REACHED?
I conclude that:
1. Nevada Power's marginal cost study is flawed and does not follow Commission
orders. An error in the marginal transmission and distribution study has resulted in
a $1.295,188 excess allocation of costs to the water pumping customer classes.
This error is specific only to these WP water pumping classes.
2. The rate subsidy discussed by Nevaa Power tht has increased in this case to
$106 millon per year should be reduced only to the extent that Nevda Power in
this rate case does not reeive authorization to raise its revenue requirement by .it
requested amount. However, reductions to the Company's request to increase
rates could be used to reduce the level of the rate subsidy.
::oMA\(CDOI,RNODOCS\3!JQ\1 Page 2 of 12
e e
1 OY,ER-ALLOCATION OF COSTS TO WP WATER PUMPING CLASSES
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HAVE YOU TESTIFIED PREVIOUSLY THAT THE WATER PUMPING CUSTOMER
CLASSES HAVE UNIQUE USAGE AND INTERRUpnBILfTY CONSIDERnONS
THAT MUST BE ADDRESSED IN ANY NEVADA POWER MARGINAL COST OF
SERVICE STUDY?
Yes. In Nevada Powets last general rate case, Docket No. 01-10001, I testified on
rae design on behalf of the water pumping classes for the Soutern Nevada Water
Authont. In that docket J pointed out that the marginal cost study and resulting water
pumping classes' rates sponsored by Nevada Power were in error. They were In error
because the Company's cost study ignored the usage charactristics of water
pumping classes, instead, the cost study just assumed that these classes' costs were
the same as "otheIWise applicabJe classes." By usage characteristics, I mean the
unique off-peak pattems of energy usage of water pumpers relative to other customer
classes.
DID THE COMMISSION AGREE IN THOSE PROCEEDINGS THAT THE MARGINAL
COST STUDY AND WATER PUMPING CLASSES' RATES PROPOSED BY
NEVADA POWER WERE IN ERROR?
Yes. Ordering paragraph 583 of the Commission order stated:
"NPC's marginal cost of servce study included separate base general rate
energy related information for schedules lGS-WP and LGS-X-WP, but NPC did not
use this information to develop separate rates. Du~ to curtailments,' the rates
proposed would be lower than that for otherwise applicable tariff."
::ODMA\lDOCS\HLRODOC\J69790\1 Page30fl2
e e
DID THE COMMISSION REQUIRE NEVADA POWER TO BASE RATES TO THE
WATER PUMPING CLASES ON THE MARGINAL COSTS OF THESE CLASSES,
RATHER THAN ON OTHER WISE APPLICABLE RATES?
Yes. Ordering paragraph 585 of that same order stated:
"The Commission finds that the proposal of the SNWA to base the schedule
LGS-WP and LGS-X-WP classes' energ BTGRs upon the marginal cost study and
not the classes' otherwise applicable rates is reasonable and approv."
DO YOU HAVE SIMILAR ISSUES WITH RESPECT TO NEVADA POWER'S COST
STUDY TREATMENT OF THE WATER PUMPING CLASSES' USAGE
CHARACTERISTICS AND RESULTING MARGINAL COSTS AND CLASS RATES
IN THE PRESENT PROCEEDINGS?
Yes, as I explain below.
DOES THE MARGINAL COST STUDY SPONSORED 'N THE PRESENT
PROCEEDINGS BY NEVADA POWER COMPLY WITH THE COMMISSION'S
ORDER IN Docket No. 01-10001 WITH RESPECT TO WATER PUMPING
CLASSES' MARGINAL COSTS?
No, the marginal cost study filed doe not comply with the Commission order in the
last general rate case with respect to water pumping marginal cots. Nevada Powts
deviations from the methods ordered in the last case result in its proposing rates in
this case that are highly inequitable and discriminatory to the WP water pumping
classes.
;;ODMA\POO\HLRODOCS\J69790\1 Page 4 of 12
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DOES NEVADA POWER TESTIFY IN THE PRESENT CASE THAT ITS MARGINAL
COST STUDY FOLLOWS PREVIOUS COMMISSION ORDERS?
Yes. On page 3, lines 16-18 of Ms. Walsh's testimony she indicates:
II.. ° The marginal cost of service method utilzed for this case is primarily that
used in previous cases, wit a few enhancments and changes to comply wit
previous Commission orders... "
The enhanceents and changes made by Nevada Powr to comply with ,previous
orders later described in the testimony of Ms. Walsh do not go to the errors in the
study with respect to the water pumping classes that I describe below.
DOES MS. WALSH INDICATE THAT THERE ARE EXCEPTIONS TO HER USING
OF INDIVfOUAll Y IDENTIFIED MARGINAL COSTS IN HER STUDY?
Yes, although she indicate that these exceptions .....are few and consistent with past
practice and/or Commission orders..." (page 12, I. 14-15.) Unfortunately, the
exception to using the available individual marginal trnsmission and distribution
demand cost by Ms. Walsh is very cotly to th water pumping classes.
WHAT 00 YOU MEAN BY YOUR STATEMENT THAT MS. WALSH MAKES AN
EXCEPTION TO USING THE AVAILABLE INDIVIDUAL MARGINAL COST FOR
WATER PUMPERS' TRANSMISSION AND DISTRIBUTION DEMAND COSTS?
Ms. Walsh states on page 12, lines 20-22 of her testimony that .....Optional WP
classes do have marginal cost individually calculated and values shown in Table 1 for
the majority of their cost functions.... It is true that the majority of the WP Of water
pumping cost functions are calculated individually. But Ms. Walsh makes an important
exception, similar to that which she made for the WP classes in the previous case by
::ODMA\PCOOCS\LRNODS\6979O\I PageS of 12
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using "otherwise applicable" classes' dat instead of WP~specifc data that were
readUy available elsewhere in her study. On page 12, lines 22-26 of her tesimony,
Ms. Walsh identifies what I cosider to be her unneessary and highly discriminatory
data "substitution";
-...The exception for WP is for the marginal co of transmission and
distribution costs for the non-otlonsl class from which they came, re-scaled to the WP
glass sales... II (underlining added).
PLEASE EXPLAIN.
I express in my own words this same quotation from Ms. Walsh ina more specfic, but
equivalent way. Ms. Walsh had all the data for each WP water pumping class
necessary to compute their respecive marginal transmission and distribution demand
costs, just as she possessed the equivalent data for the residential, general service
and large general servce classes. For all these other classes that were not water
pumping, she applied each of the respective class' time of use (i.e. peak, mid, off and
other) usage data appropriately to spread the transmission and distribution cost on
the basis of each class' contribution to the particular time periods costs. That Is,
classes with relatively high on-eak usage, fo~ example, receive relatively high
¡¡llocation of the on-peak transmission and distribution cos. and so forth for the mid,
off and other rating or usage periods.
Although Ms. Walsh also had this same appropriate usage data for peak, mid,
off and other time periods for an of the water pumping class schedules (LGS-2-WPS.
LGS-2-WPP, LGS-2-WPT, LGS-3-WPS, LG8-3-WPP, LGS-3-Wpn, she did not use
these classes' data to spread transmission and distribution costs to the respecive WP
;;ODMA\PCDOLRNODOI369O\I Page 6 of 12
e e
classes. Instead, she ignored thes time of usag data and chose annual avege
numbers applied from the LGS classes.
DOES MS. WALSH EXPLAIN WHY SHE CHOSE NOT TO USE THE AVAILABLE
WP USAGE DATA TO DETERMINE WP MARGINAL COST OF TRNSMISSION
AND DISTRIBUTION IN THE SAME FASHION AS SHE DID FOR ALL OTHER
MAJOR CUSTOMER CLASSES?
No. Witout explanation, Ms. Walsh ignores all these available WP time period usage
data and instead Mscales" marginal trnsmission and distribution costs with an average
annyal WP usge scaling factor. That is, she added up aU kwh energy sales fo the
year for a WP class, say LG8-2-WPS, and divided this annual sum by the total kwh
energy sales for the year for what she calls an "otherwise applicable" class, or "non-
optional" class, say LGS-2-S. The result of this gives nothing but an annual
percentage of LG8-2-WPS sales to total LG&-2-S sales, which ignores all of the WP
water pumping time perod or time of usage characteristics.
IS IT CORRECT TO ESTIMATE WP CLASS SHARES OF MARGINAL
TRANSMISSION AND DISTRIBUTION DEMAND COSTS ON THE BASIS OF
AVERAGE ANNUAL. ENERGY CONSUMPTION?
No. Marginal transmission and distribution cots are time sensitive. That is, usage
during peak periods imposes a greater cost to Nevada Power's system than usage
during off peak periods. Accordingly. customer class usage during peak periods
resurts, or at feast should result, in higher costs being sprad to those classes with
relatively more peak period usage. Customer class. rates should be developed
::onMAIPS\lILRNODOC~'\6970\1 Page 7 ofii
e e
accrding to these usage periods to provide price signals to cutomers and, possibly
to provide price incentivs to shift usage to lower cost of peak periods.
WHAT IS THE QUANTITATIVE EFFECT OF NEVADA POWER'S SPREADING OF
MARGINAL TRANSMISSION AND DISTIBUTION DEMAND COSTS TO THE WP
ClASES ON THE BASIS OF ANNUAL AVERAGE, RATHER THAN ON THEIR
RESPECTIVE PEAK, MID AND OFF PEAK USAGES?
The effect is to over-allocate costs to the WP cJasses by $1,295,188 per year. This
occurs because the water pumping classes usage characteristics, compared with most
other custoer classes, shif large amounts of power consumption to the loer cost
mid and off peak time periods. These shifs to the lower cost perids are good for the
transmission and distrution systems and for other customers' cost as well. Nevada
. Power's marginal cost study ignores these benefits by removing the actual WP usage
data and substiting instead an incorrec assumption tht the water pumpers have the
same average usage across all time periods.
WHAT CHANGE TO NEVADA POWER'S FILED MARGINAL COST STUDY
WOULD CORRECT THE PRESENT EXCESS ALLOCATION OF COSTS TO THE
WATER PUMPING CLASSES?
Nevada Power simply needs to follow the same method of using the water pumping
usage data by time period for developing WP marginal costs as it has for every other
major customer class in the study, and as it has done for all major customer classes,
Including the WP classe, in each and every marginal rost study filed previously since
at least 1992. Nevada Power's propose study discriminates against the WP classes
by not allowing them to reduce costs by shifing usage to off peak periods.
::ODMAIPOCLRNODOSU6979O1 Page 8 of 12
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HAVE YOU MADE THE CHANGES TO NEVADA POWER'S MARGINAL COST
STUDY THAT YOU RECOMMENDED IN THE QUESTION AND ANSWER
IMMEDIATELY ABOVE?
Yes. My thre page Exhibit DEP.7 summarizes the changes to WP marginal
trnsmission and distributon demand costs neceary to reflect the actual WP usage
data.
PLEASE EXPLAN.
Exhibit OEP-7 replicates a number of data series from Nevada Power's Certification
marginal cost study. For easy reference, I include as Exhibit DEp.8 select pages from
the Company's cost study in the Applicaion which contains some of these data. At
the top of each of the three pages of Exhibit DEP.7 I present the indivdual class
usage data for all of the LGS, the LGS WP schedules, as well as the uRatio of WP
Kwh to LGS Kwh."
WHAT DO THESE RATIOS SHOW?
These show the ratios of WP to LGS usage for the peak, mid, of and other periods
that should have been used by Nevada Power in spreading marginal transmission and
distribution demand costs to water pumping classes. Also, shown is th total annual
average WP usage that was Incorrectly used in Nevada Power's study. For example,
on page 1 of Exhibit DEP.7 tJe time diffrentiated WP ratio for Nevada Powets peak
period is shown to be 1.34%, which Nevaa Power should have used in order to be
comparable to its treatment of all other cutomer classes. Insted, Nevada Power
used the higher average annual kwh ratio of 1.84%, also shown on page 1 of Exhibit
::ODMA\POOC&'\I.NOIx:S\36979m1 Page 90f 12
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3
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7
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is
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e e
DEP-7. To be consisent with other classes and wi rt past marginal cost stuies,
Nevada Power should have used the peak, mid, off and other time perio raios in
place of its annual average ratio.
DOES EXHIBIT DEP.7 CALCULATE THE WATER PUMPING MAGINAL COST OF
TRANSMISSION AND DISTRIBUTION DEMAND BASED ON THE TIME
DIFFERENTIATED WP USAGE DATA?
Yes. Page 1 of the exhibit applies the WP time diferentiated usage data by rating
period to marginal transmission costs in a manner consistent with Nevada Powets
methods for other major rate classes. Page 1 at the, bottm compares the total
marginal transmission costs sprea to the WP classe using the correct usage data by
time period. As shown, Nevada Power alloces $798,911 in transmission costs to the
WP cfasses, whereas the time period allocation should be $360,173.
WHAT DO PAGES 2 AND 3 OF 3 OF EXHIBIT DEP~7 SHOW?
Pages 2 and 3 of the exhibit correspond to page 1 but apply to distribution substaion
and non-revenue feeders. rather than the transmission cost shown on page 1. Page 2
computes WP marginal substtin costs of $204,996 rather than Nevada Powets
annual average calculation of $545,550. Page 3 computes WP marginal non-revenue
feeder costs of $310,554 rather than Nevada Powr's annual average calculation of
$826,441.
::OMAIIV'I.RNOOOCS\69790\1 Page lOofl2
4
5
6
7
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1 Q.
2
3
WHAT IS THE TOTAL DIFFERENCE IN WP MARGINAL COST OF TRANSMISSION
AND DISTRIBUTION DEMAND FROM CORRECTING NEVADA POWER'S STUDY
TO REFLECT WP TIME OF USAGE?
A. Page 3 of Exhibit DEP.7 indicates that Nevada Powets Study allocates exces costs
to the WP classes of $1,295,188. The SNWA requests that the Commission, order
Nevada Power to correct this inconsistent and harmful defect in its proposed study.
PRESENT RATE SUBSID'(
WHAT IS THE ISSUE WITH RESPECT TO THE RATE SUBSIDY DISCUSSED BY
NEVADA POWER?
Exhibrt L1W-6 in Nevada Powr's cost study calculates that the rates it proposes in this
case result in the residential rate subsidy increasing by $23 milion per year over that
decided in Docket No. 01.10001. The rate subsidy in Nevada Powets study is
approximately $106 milion, whereas in the lat general case it wa approximately $83
million. On pages 22-25 of Ms. laura Walsh's testimony she addresses the stic
issue of how this subsidy might be reduce. She discusses the last Commission
general rate case order wherein the Commission for a number of reasons decided to
suspend movement of rates closer to cots in that case, but predicted revisiting the
issue in this 2003 general rate case. Nevada Power's exhibits then offer alternative
means of reducing the present subsidy. WhiJe the Company is to be commended for
identifying alternative means, unfortunately its presentations result in rates for
residential customers that are higher than Nevada Power originally propose.
::OOMA\I()lHlRNODO~'I?91 Page 11 of 12
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DO YOU HAVE AN ALTERNATIVE PROPOSAL FOR REDUCING THE SUBSIDY
THAT DOES NOT RESULT IN RESIDENTIAL RATES HIGHER THAN THOSE
PROPOSED BY NEVADA POWER?
Yes. My review of the cost of capital and other revenue requirement testimony in the
first two phases of these proceedings indicates that a number of parties are
recommending significant downward adjustments to Nevada Power's requested
Increase in revenue requirement. To the extent that the Commission is persuaded to
authorize revenue requirements below that sought by the Company, some level of
these reductions could go first to reduce rates of customer classes that are currently
paying the subsidy while not increasing residential rates. After some target reducton,
say back to the level of the subsidy in the previous GRC, any remaining reduction
should be shared in some fashion with the residential classe. I recommend this
because the high level of subsidy is bettr to be reduce gradually so as to minimize
any rate shock to residential customers
DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
Yes.
;;OI)MA\POOS\LRNOOOCS\36979011 Page 12 of12
e e Attchment 1
Page 1 of3
STATEMENT OF OCCUPATIONA AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Paseau has conducted ecnomic and financial studies for regulated
industries for the past twenty-eight years. In 1972, he was employed by Southern
California Edison Company as Associate Economic Analyst, and later as Economic
Analys. His responsibilities included review of financial testimony, incremental cost
studies, rate design, econometric estmation ofdemand elasticities and various areas
in the field of energy and economic growth. Also. he was asked by Edison Elecical
Institute to study and evaluate several prominent energy models as part of the Ad
Hoc Committee on Economic Groh and Energy Pricing.
From 1974 to 1978, Dr. Peseau was employed by the Public Utilit
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and financial studies and prepared testimony pertaining to public utilties.
In 1978 Dr. Peseau established the Northwest offce of Zinder
Companies. Inc. He has since submited testimony on economic and financial
matters before state regulatory commissions in Alaska, California, Idaho. Maryland i
Minnesota, Montana, Nevada. Washington, Wyming, the District of Columbia, the
Bonnevile Power AdminíSlration and the Public Utilities Board of Alberta on over one
e e Attchment 1
Page 2 013
.,
hundred occasions. He has conducted marginal cost and rate design studies and
prepared testimony on these matters in Alaska, California, Idaho, Maryland,
Minnesota, Nevada, Oregon. Washington and in the Distnct of Columbia. He has
also conducted cost and rate stdies regarding PURPA issues in the states of
Alaska, California, Idaho, Montana, Nevada, New York, Washingtn, and
Washington, D.C.
Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics.
He has co-authored a book in the field of Industrial organization entitled,
Size, Profits and Executive Compensation In the Large Corporagn, which devotes
a chapter to regulated industes.
Dr. Peseau has published articles in the following professional journals:
Review of Econgmlcs and Statistics, Atlantic Economic Journal, Journal of Financial
Management, and Journal of Regional Science. His artcles have been read before
the Econometric Societ, the Western Economic Association, the Financial
Management Association, the Regional Science Association and universities in the
United Kingdom as well as in the United States.
He has guest lectured on marginal costing methods In seminars In New
Jersey and California for the Center of Professional Advancement. He has also
guest lecured on cost of capital for the public utilit industry before the Pacific Coast
e e Attchment 1
Page30f3
Gas and Electrc Association, and for the Executive Seminar at the Colgate Darden
Graduate School of Business, Universit of Virginia.
Dr. Peseau and his finn have participated with and been members ofthe
American Economic Association, the American Financial Association, the Western
Economic Association, the Atlantic Eoonomic Association and the Financial
Management Association. He was fonnerly a member of the Staff Subcommitee on
Economics of the National Association of Regulatory Utility Commissioners.
Dr. Peseau has been President of Utilty Resources, Inc. since 1985.
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AFFIRMATION
" Dennis E. Peseau. pursuant to NAC 703.710 hereby affrm that the
foregoing prepared testimony was prepared by me or under my diretion and is
, corret to the bet of my knowledge.
Slgn-.~ '.r~
0_ ~7l1
..e e
BEFORE THE PUBUC UTn.mES COMMISSION OF NEVADA
Application ofNEV ADA POWER COMPAN for authorty
to increase its annual revenue reuient for gen rate
chaged to all classe of electic custmer and for properly
related thereto.
Application ofNEV ADA POWER COMPANY for approval
Of new and reised depreciaton and amortation rates.
DENNIS E. PESEAU TESTIMONY
Pbase Thre - Rate Deslg.
Work Papers
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Comparison of Annual Scaling of Marginl Cost and Cost Period Scaling
Kwh UsageClassPeakMidOff Other Total PeakLGS-2S 219.745,127 211.641,143 338.506.134 1.253.012,472 2,022.904,876LGS-2P 5.750,377 5,768.765 10.121,915 39.501,303 61,142,360LGS-2T 529,718 529,282 1,038.548 4,619,734 6,717,282LGS-3S 152.057,158 151,344,631 267.992,836 959,997.859 1,531,392.48lGS-3P 115.749.939 116,368,262 206.915,802 759,704.813 1,198,738.816LGS.3T 12,453,610 12.111.991 25,669,047 100,145.694 150.380.342Total LGS 506.285.929 497.764,074 850,244,282 3.116,981,875 4.971,276.160 Cot
LGS-2S-WP 2,954.581 4.513,214 18.179,426 11,573.345 37.220,566 1.34%LGS-2P-WP 619,127 596.932 1.056,769 3.160,750 5,433.578 10.77%LGS-2T.WP 72,172 177.327 479,108 965,360 1,693.967 13.62%LGS-S.WP 531,406 4,297,122 17,135.268 26,299,801 48,263.597 0.35%LGS.3p.WP 1.078.606 3,590,0$22.963,717 45,636.797 73,269,185 0.93%LGS.3T-WP 4.064.771 6.217.490 19.531,761 51,183.634 61,617.656 32.80%TotlWP 9.340.66 19,392,150 79.346,049 139,419.687 247,498,549 1.84%
LGS Marginal Transmission COst
Class Peak Mid Off Other TotalLGS.2S 6,939,330 812,920 241 70,899 7.823,390LGS-2P 186,662 22,391 7 1,924 210,984LGS.2T 15,271 1.82 1 173 17.265LGS-3S 4.747,758 569,520 175 48,885 5,366,338LGS-3P 3,511,175 420,025 128 35,002 3,966.33lGS.3T 360,005 42,161 16 3,729 405,911Total17,790.218WP Marginal Transmission Cost Using Annua Kwh Scaling WPMargClassPeakMidOffOterTotalPeakLG$-2S.WP 127,681 14,957 4 1,305 143,947 93,303LGS.2P-WP 16,586 1,990 1 171 18,750 20,097LGS-2T-WP 3,851 459 0 44 4.354 2,081lGS-3SWP 149,631 17,94 6 1,541 169,126 16,592lGS.3P.WP 214,610 25,673 8 2,139 242,430 32,719LGS-3T-WP 195,390 22,883 9 2,024 220,305 118,081Total798,911
lGS Marginal SubstatIon Cosl$
Class Peak Mid Off Oter TotalLG8-2S 6,592,480 772.288 229 67,365 7,43,352L.GS.2P 177.332 21,272 7 1,828 200,439lGS.2T
LG8-S 4.510,44 541,054 166 46.441 5.098,110LGS-3P 3,335,675 399.031 122 33,252 3,768,060lGS-3T
Total 16,498,981
.WP Marinal SubstaIon Costs Using Annual Scing WPM
,e e.
Class Peak Mid Off Oter Tota PeakLG5-2S-WP 121.299 14,210 4 1,239 136,752 88.639lGS2P-WP 15,759 1,690 1 162 17,813 19.093
LGS-2T-WP 0 0 0 0 0
LGS-3S-WP 142.152 17,052 5 1,464 160,673 15,763lG5-P.WP 203,883 24.390 7 2,032 230,312 31,083lGS-3T-WP 0 0 0 0 0
Total 545.550
Class
LGS.2S
lGs.2P
lGS-2T
lGS-3S
lG5-SP
lGS.ST
Total
Class
lGS-2S-WP
LGS-2P-WP
LGS.2T.WP
LGS-3s.WP
LGs-P-WP
LGS-3T-WP
Total
LGS Marginal NonRe\fnue Fee Cos'sPeak Mid Of Othe Total
9,986,804 1,169,922 347 102,034 11,259,107
268,636 32,224 10 2,769 303.639
o
7,723,016
5,708,182
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6,832.781
, 5,053,141
619,630
604,48
252
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70,35
50.373
WP Margintil NonRevenue Feeer Costs Using Annual ScalingPeak Mid Off Other Total183,753 21,526 6 1.87723.873 2,864 1 246o 0 0 0
215,343 25,832 8 2,217308,858 36.947 11 3.079o 0 0 0
WPMargin
Peak
207.163
26,984
o
243,400
348.895
o
826,441
134.277
26.923
o
23,879
47,087
o
Total all Scaled Marginal COst 2,170.902
".'e
Mid Of Other
Perid Ratio of WP Kwh to LGS kw
2.13%
10.35%
33.50%
2.84%
3.09%
51.33%
3.90%
5.37%
10.44%
46.13%
6.39%
11.10%
76.09%
9.33%
0.92%
8.00%
20.90%
2.74%
6.01%
51.71%
4.47%
Total
Annual Raio
WP/LGS
1.84%
8.89%
25.22%
3.15%
6.11%
54.27%
4.98%
ina Tranmsission Cost Using Time of Use Kwh ScalingMid Off Other Total17,335 13 6552,317 1 154~O 0 ~16,170 11 1,33912,958 14 2,10321,643 12 1,928
arginal Substatio Cost Using TIme of Use Sealing
111,306
22,569
2,727
34,113
47,794
141,664
360,173
e
Percent $
Diference Diffrence
29.33% -32,641-16.92% 3,819
59.66% -1,627
395.78% -135,013
407.24% -194,636
55.51% -78,640
121.81% -48,738
Percent $
."0 ti e
Mid Of Other Total Diffce Differece
16,469 12 622 105,742 29.33%-31,010
2,201 1 146 21.441 -16.92%3,628
0 0 0 0 0.00%0
, 15.362 11 1,272 32,40 395.78%-128,266
12,310 14 1.998 45.405 407.24%-184,907
0 0 0 0 0.00%0
204,996 166.13%0040,55
at NonRevenue Feeder Costs Using Time of Use SclingMid Of Other Total24,948 19 9423,334 1 222o 0 023,272 16 1.92718.649 21 3,026o 0 0
Pert $
Diference Difference
. 29.33% -46,976-16.92% 5,4970.00% 0
395.78% .194,305
407.24% -280.1120.00% 0
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NPC Distribution Marginal Costs DistributionClass
RM 57468 14.69%~3766 37,853 37,853RS19594150.09%-2306 139.597 139,597
LRS 938 0.24%-16 663 663 .
GS 20602 5.27%-260 14.640 14,640
LG5-1 54660 13.97%-70 39,515 39.515 ~
LGS.2S 25920 6.63%-1 18,771 18,771
LGS-2P 640 0.16%463 463
LGS-2T 308 0.08%223 223 "'iLGS-S 15875 4.06%745 12,242 12,242
LGS-3P 10865 2.78%583 8,452 8,452LG5-T 1301 0.33%73 1,015 1,015
LGS-XS 82 0.02%9 68 26 94lGS-XP 2795 0.71%29 2.322 2291 4.613
LGS-XT 312 0.08%378 60 867 '1.471
LGS-2-WPS 636 0.16%18 479 479 -77.98527
lGS-2-WPP 10 0.02%3 54 54 9.12501
LGS-2-WPT 36 0.01%1 27 27 0
LGS-3.WPS 511 0.15%23 437 437 .. -322.5703
lGS-S.WPP 764 0.20%36 589 589 -45.0197
LGS~3-WPT 193 0.05%40 180 180 "0
SST 0 0.00%0 0
SL 718 0.18%76 -6 590 590 i
RS.PAL 137 0.04%99 99
GS-PAL 349 0.09%253 253
AIWP 0 0.00%0 0
. 391181 2283 -6445 279136 3185 282321 -856.4502
283298
Cost PwrFac AddlFac Total Cost RR
Class RR Percent Adj Contracts Cost RR Base
RM 155,112 10.95%155,172 155.172
RS 563,365 39.77%563.365 563.365
LRS 3.078 0.22%3,078 3,078
GS 50.902 3.59%50.902 50.902
LGS-1 22.886 16.23%14 1 229,901 229.901
lGS-2S 134,597 9.50%44 134.641 134.641LGS-P 3,800 0.27%1 6 3,807 3,807
LGS-2T 540 0.04%a 540 540
LGS~3S 95,932 6.77%34 95.966 95.966
LGS-3P 72,287 5.10%26 36 72,349 72,349
lGS-3T 8,364 0.59%2 8,366 8,366
LGS-XS 1,060 0.07%4 1,064 1,06
LGS-XP 37.184 2.62%203 75 37.462 37,462
LGS-XT 42,473 3.0CWo 21 75 42,569 42,569
LGS-2.WPS 2.346 0.17%2 2,348 2,348
LGS-2-WPP 383 0.03%1 384 384
..e e
lGS-2-WPT 94 0.01%94 94
LGS-3-WPS 1,983 0.14%1,984 1,984LGS-3WPP 2.930 0.21%2.930 2.930
LGS-3-WPT 3,666 0.26%3.666 3,666
SST 0 0.00%12 0 0
SL 5,978 0.42%5,978 5,978Rs-AL 140 0.01%140 140Gs-AL 375 0.03%375 375AlP00.00%0 0
1,416,537 365 1,93 1,417,083 ,1,419,524
1,417,081
244
p'e e
with Scaling Adjustment ~ Transmisn Costs
Tota Adjust5746814.72%37,944 37,944 ,9778 10.91%7281
195941 50.20%139,908 139,908 39783 44.38%296249380.24%665 665 188 0.21%140206025.28%14,673 14,673 2578 2.88%19205466014.00%39,602 39,602 13808 15.40%10282259206.64%18,812 18.812 7823 8.73%58640.16%465 465 211 0.24%157
308 0.06%224 224 17 0.02%13158754.07%12,267 12,267 5366 5.99%3996
10865 2.78%8.469 8.469 3966 4.42%2953
1301 0.33%1.017 1.017 406 0.45%302820.02%69 95 60 0.07%4527950.72%2.327 4,618 2050 2.29%15273120.08%604 1,471 2746 3.06%2045558.01473 0.14%423 -56 423 144 0.16%107 -32.6410879.125091 0.02%60 7 60 19 0.02%14 3.819349360.01%27 0 27 ~6 0.01%4 -3.117909248.42975 0.06%203 -233 203 169 0.19%126 w135.0132298.98028 0.08%253 -336 253 242 0.27%180 -194.6361930.05%180 0 180 220 0.25%164 -76.64046
0 0.00%0 0 0 0.00%0
718 0.18%591 591 62 0.07%461370.04%99 99 0 0.00%0
349 0.09%25 253 0 0.00%0
0 0.00%0 0 0.00%0390324.55 279,136 -618 89642 100.00%66752 -40.2293
w129a.679
Present Percent Firs First First Rrs First FirstPercentRevIncreaseCapRellocRemainPercentAlCap
10.95%144051 7.72%o .155171.7 18.39%1764.4 172.81539.76%424559 32.69%464866 989.27 0 0.00%0 46.8660.22%2803 9.81%3069 8.913007 0 0.000/0 0 3.0693.59%46716 8.96%0 50902.08 6.03%5787.69 56,69016.22%238967 -3.79%0 229901.4 27.25%26140.36 256,0429.50%144561 w6.88%0 134640.a 15.96%15308.97 149,9500.27%3934 -3.22%0 3807.46 0.45%432.9176 4,240
0.04%347 55.59%397 142.889 '0 0.00%0 3976.77%104259 -7.95%0"95965.69 11.37%10911.54 106,877
5.11%75826 -4.59%0 7234.35 8.57%8226.3 80.5760.59%8654 -3.33%0 8366.169 0.99%951.2541 9.3170.08%1188 ~10.42%0 1064.245 0.13%121.0073 1,1852.64%36816 1.75%0 37461.87 4.44%4259.507 41,721
3.00%40123 6.10%'0 .42568.64 5.05%480.16 47,4090.17%2145 9.45%0 2347.7 0.28%266.9393 2,615
0.03%315 22.04%360 24.4263 0 0.00%0 360
.e e
0.01%94 0.49%0 94.4567 0.01%10.73996 105
0.14%2298 .13.66%0 1983.997 0.24%225.5854 2.210
0.21%3317 -11.67%0 292.791 0.35%333.1245 3,2630.26%3905 -6.11%0 3666.327 0.43%416.8705 4.0830.00 0 O.otk 0 0 0.00%0 0
0.42%8719 -31.43%8719 -2740.514 0 0.00%0 8,7190.01%150 -6.42%0 140.371 0.02%15.960 156
0.03%410 -8.48%0 375.2129 0.04%42.66264 418
0.00%0.00%0 0 0.00%0 0
1293999 9.49%95934.99 843737
..e e
Generatio Energy w/o Tota w/O Energy RRSavingsDemandHooverHooversPercetw/o Hoover97780.109817 7317.131 5088 96350 147238 10.45%112,890397630.445989 29nO.55 222305 302974 525279 37.2B%402,7411880.00106 140.6853 1061 1965 3046 0.22%2,33525780.028901 1929.184 154 29247 44136 3.17%34,300138080.154795 10332.88 77373 157330 234703 16.66%179,95178230.0877 5854.154 42843 100535 14378 10.17%109,9312110.002365 157.8968 1194 291 4145 0.29%3,176170.000191 12.72154 89 307 396 0.03%30453660.060156 4015.517 28887 74996 103883 7.37%79,64939660.04461 2967.861 21689 57676 79365 5.63%60.8514060.004551 303.8203 2295 6691 9186 0.65%7,043600.000673 44.89956 322 878 1201 0.09%92120500.022982 1534.068 10918 2955 40474 2.87%31,03227460.030784 2054.903 15107 36762 51889 3.68%39,784111.3589 0.001246 83.33277 -24 632 1767 2399 0.17%1.83922.81935 0.000256 17.07631 3 132 267 399 0.03%3062.882091 3.23e-05 2,156744 .2 8 77 85 0.01%6533.98683 0.000381 25.43322 -100 99 2189 2286 0.16%1,75447.36398 0.000531 35.4469 .145 201 3244 3445 0.24%2,641141.3595 0.001585 105.783 -58 797 3612 4409 0.31%3.38000000.00%0620.000695 46.39621 291 6675 6966 0.49%5,34100056560.00%430001591590.01% '12200000.00%0,89201.77 1 66752 -38 49220 91655 1409125 1 1080403
First Secnd Reveue Secnd Second Second second Third% Change cap For Reai Remain Percet All CapRR % Change Cap19.97%157721.4 15,094 0 0 0 157721.4 9.49%09.49%0 0 0 0.00%0 464866 9.49%09.49%0 0 0 0.00%0 3089 9.49%021.35% 5385.15 3,205 0 0.00%0 53485.15 14.49%07.15%,0 0 229901.4 38.79%7729.633 263771.4 10.38%03.71%0 0 134.6 22.71%4526.819 154476.3 6.84%07.79%0 0 3807.46 0.64%128.0125 4368.39 11.04%014.41%0 0 0 0.00%0 397 14.41%02.51%0 0 95965.69 16.19%322.511 110103.7 5.61%06.26%0 0 72349.35 12.21%2432.494 83008.14 9.47%07.670Æi 0 0 8366.169 1.41%281.2832 9598.706 10.92%0-0.23%0 0 1064.245 0.18%35.78151 1221.034 2.78%013.32%0 0 37461.87 6.32%1259.524 42980.9 16.75%42150.6418.16% 45936.82 1,472 0 0.00%0 45936.82 14.49%021.89% 2455.811 159 0 0.00%0 2455.811 14.49%014.29%0 0 0 0.00%0 360 14.2eoÆi 0
".e e
11.91%0 0 94.457 0.02%3.175777 108.3724 15.29%107.620
-3.85%0 0 1983.997 0.33%66.70497 2276.287 -0.94%0
-1.63%0 0 2929.791 0.49%98.50399 3361.42 1.34%0
4.56%0 0 3666.327 0.62%123.2674 4206.465 7.72%00.00%0 0 0 0.00%0 0 0.00%00.00%0 0 0 0.00 0 8719 0.00%0
4.22%0 0 140.371 0.02%4.719465 161.051 7.37%0
1.92%0 0 375.2129 0.06%12.615~430.4908 5.00%0
0.00%0 0 0 0.00%0 0 0.00%0
19.929 592746.9
e e
. NPC Scaling
Hoover Energy . Tota Adjusted SNWaAdjTotal;: Cost RR Cost RR Difference dOnly-2980 109,910 155,04 155,172 .127-9055 393,686 562,908 563,365 -458
-63 2,272 '3,076 3,078 .2
34,300 50,860 50,902 -42
179.951 .:229,749 229,886 -138
109,931 134,527 134.597 -70
3,178 3,799 3,800 -2
304 539 54 -1
79,649 95,887 95.932 -45
60,851 ,72,256 72,287 -32
7,043 8,361 8,364 -4
921 1,060 1,060 0
31,032 37,172 37,184 -12
-838 38,946 42,462 42,473 -11
1,839 2,425 2,346 79 79
306 374 383 -10 -10
65 97 94 2 2
1,754 2,317 1,983 334 33
2.641 3,411 2,930 481 481
3,380 :3,724 3,666 58 58o .0 0 0.5,341 .5,977 5,978 -1
-2 41 140 140 0
122 .375 375 -1
0 0 0 0
-12938 1067465 ~.1416537 1416537 ...58E-12 944.5003
Rev for Third . Third Third Third Third Fourt
Reali Remain . Percnt Alice CaRR % Change Cap0000157721.4 9.49%0
0 0 0 0 464866 9049%0000030699.49%0
0 0 0 0 5345.15 14.49%0
0 229901.4 0.414095 34.1189 264115.6 10.52%001340.6 .0.242512 201.5314 154n.9 6.00..0
0 3807.46 0.006858 5.699046 4374.089 11.19%0
0 o :0 0 397 14.41%0
0 95965.69 0.172852 143.6424 110247.4 5.74%0072349.35 .0.130314 108.293 83116.44 9.61%0
0 8366.169 0.015069 12.52257 9611.229 11.06%001064.245 0.001917 1.592973 1222.627 2.91%0830.2632 o .0 0 42150.64 14.49%0
0 o i 0 0 45936.82 14.49%000002455.811 14.49%0000036014.2%0
..e e
0.751843 0,0 0 107.6206 14.49%0
a 1983.997 .0.003574 2.969667 227.251 -0.82%0
0 2929.791 0.005277 4.385342 3365.805 1.47%0
0 3666.327,0.00660 5.487700 4211.953 7.850Ai 0
0 0 0 0 0 0.00%0
0 0 0 0 8719 0.00%0
0 140.371 0.000253 0.210109 161.2611 7.51%0
0 375.2129 0.00066 0.561623 431.0524 5.13%0
0 0 0 0 0 0.00%0831.0151 555190.6 4.61E+08
.AI e e
Certifcation Kwh
LGS~2S-WP 2,954.581 4,513.214 18,179,426 11,573,345 37,220,56 LGS.2S 219,745,127LGS-2P-WP 619,127 596,932 1,056,769 3,160.750 5,433,518 LGS.2P 5,750,3nLGS-2T~WP 72,172 177.327 479,108 965,360 1,693.967 LG8-2T 529,718LGS-3S-WP 531,406 4.297.122 17,135,268 26.299.801 48,263.597 LGS-aS 152.057.158LGS-3P.WP 1,078,606 3,590,065 22,963,717 45,636.797 73,269,185 LGS..P 115.749,93LG8-3T.WP 4.084,771 6,217,490 19.531,761 51,783.63 81,617,666 lGS-3T 12.453.6109,340,663 19.392,150 79,346,049 139.419,687 247,498,549 506,285,929
LGS-2S.WP 7.94%12.13%48.84%31.09%100.00%LGS-2S 10.86%LGS-2P-WP 11.39%10.99%19.45%58.17%100.00%LGS-2P 9.40%LG8-2T-WP 4.26%10.47%2828%56.99%100.00%LG8-2T 7.89%LGS.3S.WP 1.10%8.90%35.50%54.49%100.00%LGS-3S 9.93%LG5-3p.WP 1.47%4.90%31.34%62.29%100.00%LGS-3P 9.66%LGS-3T.WP 5.00%7.62%23.93%63.45%100.00%LGS-3T 8.28%3.77%7.84%32.06%56.33%100.00%10.18%
Peak Only Percent
LGS.2S.WP 11.52%11.60Æi 70.88%100.00%LGS-2S 28.54%LGS.2P-WP 27.24%26.26%46.50%100.00%LGS-2P 26.57%LGS~2T.WP 9.91%24.34%65.76%100.00%LG$-2T 2525%LGS--WP 2.42%19.56%78.02%100.00%LGS-3S 26.61%lGS-3P.WP 3.90%12.99 83.10%100.00%LGS-P 26.36%LGS.3T.WP 13.69%20.84%65.47%100.00%lGS-3T 24.79%8.64%17.94%73.41%100.00%27.3%
Last case Certifiatio Kwh
LG5-2$-WP 2,594,784 3,456,756 16,088.819 7,654,423 29,79,782
LGS-2P.WP 110,542 131,481 306,113 790,036 1,338.172
LGS-2T-WP 89,968 188,171 44,921 927,859 1,654,919
lGS.3S-WP 1,135,933 2,668.807 15.162,796 33.72,011 52,669,547
LG8-3P-WP 1.966,055 3,910,641 17,589,600 39,665,609 63,131,905
LGS-3T-WP 2.332,418 5.762.965 23,918,299 72,296.858 104,310,600
8.,,760 16.118.821 73,514,548 155.056.796 252.919.925
LG5-25-WP
lGS-2P-WP
LGS-2T.WP
LGS-3S-WP
8.71%
8.26%
5.44%
2.16%
11.60
.9.83%
11.37%
5.07%
54.00%
22.88%
27.13%
28.76%
25.69%
59.04%
56.07%
64.00%
100.00%
100.00%
100.00%
100.00
o-tt ,e
LGS-3P-WP 3.11%6.19%27.86%62.83%100.00%LG8-T-WP 2.24%5.52%22.93%69.31%100.00%3.25%6.37%29.07%61.31%100.00%
."e e
211,641,143 338,506,134 1,253,012,472 2,022,904,876
5,768,765 10,121,915 39,501,303 61,142,360
529.282 1,038,548 4.619,734 6,717.282
151.34,631 267,992,836 959,997,859 1,531.392,484
116,368,262 206,915.802 759,704,813 1,198,738,816
12,111.991 25,669.047 100,145.694 150,38,342
497,764,074 850,244,22 3.116,981,875 4,971.276,160
10.46%16.73%61.94%100.00%9.43%16.55%54.61%100.00%
7.88%15.46%68.77%100.00%
9.88%17.50%62.69%100.00%9.71%17.26%63.38%100.00%
8.05%17.07%66.59%100.00%
10.01%17.10%62.70%100.00%
27.49%43.97%100.00%
26.66%46.77%100.00%
25.23%49.51%100.00%
26.49%46.90%100.00%
26.51%47.13%100.00%
24.11%51.0%100.00%
26.84%45.85%100.00%
..,"e e
CERTIFICATE OF SERVICE
i hereby certfY that I have'this day sered a copy of
South em Neva Water Authority's
Prefiled Testùony of Dens Peasea, Phase il-Rate Design upon each of the parties listed
below by placing the same in the U.S. Mail posage preaid, or electrnically, to the following:
Kathlee Drakulich
Sier Paeìfc Power
6100 Neil Road
Reno, Nevad 89520
kdlichØl~.C(m
smcdonald sppc.com
nellianõ(evp.co
csilvICl(lppc.com
Staf Counsel
Public Utilties Commssion of Nevaa
11 SO East Wiliam Strt
Carson City, NY 89701
trbertSi£uc.state.nv.us
AlBina Burtnshaw
Public Utilities Commission
101 Convention Center Drive, Suite 250
La Vegas, NV 891109
abunens(auc.state.nv. us
Tim Hay
Attrney Gener's Bureau of Consumer Protection
1000 East William$ Suite 200
Carson City, NV 89701
tdh~ag.state.nv.us
Eric Witkos
Attorney Genera's Bureau of Consumer Prtection
555 E. Wasngton St., Suite 3900
Las Veg~ NV 89101
epwitkos~ag.state.nv.us
Robe Crowell
Crowell, Susich. Owen & Tackes
P.O. Box 1000
Cason City, NY 89702
rcowellØ)advocacy.nct
"e e
Doris Knesek
USAN
P.O. Box 1823
Carn City, NV 89702
dori~usan.carn-city.nv.us
Lawrence GoJlomp
USDE
1000 Indepenence Ave., SW
Washington, D.C. 20585
Lawrence.GallompØPg.doe.gov
Dale Swan
Exeter Associates, Inc.
5565 Sterett Place, Suite 310
Columbia, MD 2104
dswn€ùexeterassociiile.com
Mark Russell
Mirage Casino-Hotel
3400 Las Vega Blvd. South
Las Vega NY 89109
mnssell(t,mirgc.co
mascr!ltálaw.com
Richar Emmons
Michael Kostinsky
Harah's Operting Company, Inc.
One Har's Cour
La Vegas, NY 89 i 19.4132
mkstrinsky(âbarr.com
remmns(iars.com
Dan Reaer
Shawn Blicegui
SO West Liberty Street, 81. i 100
Reno, NY 89501
drasertiIooelsawyer.com
seliceguiCálionelsawyer .com
mbowanCiionelsawyer.com
Mae Main.Ker and Phil Wiliamson
Bureau of Consumer Prtection
1000 E Willam St.. Suite 200
Carson City, NV 89701.3117
nuer.state.nv.us
pwilI iatã.state.nv .us
.~1...e e
BiU Kocenmiser
6005 Plumas St., Suite 301
Reno. NY 89509
biUy(cqalns.com
Martha Ashcraf
3993 Howa Hughes Parkway
Suite 600
La Vegas. NY 89109
rnashcraft€ylrlaw .com
Michael P. Alcantar
Donald Brookhyser
Alcant & Kahl LLP
1300 SW Fifth, Suite 1750
Portland. OR 97201
deb(ã.kIaw.com
mpúia-klaw.co
James Ross
RCS, In.
500 Chesereld Center, Suite 320
Chesterfield. MO 63017
jimross~-cs-inc.com
Michael Kurtz
Boehm, Ku & Lowr
36 East Seventh Street, Suite 21 10
Cincinnat, OH 45202
mklawtaoLcom
MikePinnu
Chemcal Lie Company
3700 Hulen Street
Ft. Worth. TX 76107
mpinau~hemjcalljme.com
J: ". ..-'-
Sctt Crgie
Prest, Alms Consulting
6005 Plumas Suíte301
Reno. NV 89509
e e
Dated this 27th day of Januar, 200.
-e
BEFORE THE PUBLIC UTILITIES COMMISSION OF NMOA - .,' i : : !
Docket No. 02-11021
Direct Testimony of
Denis E. Peseau
on behalf of
the. Southern Nevada Water Authori
Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
A. My name is Dennis E. Peseau. My business addres Is Suite 250, 1500
Libert Street, S.E.1 Salem, Oregon 97302.
Q. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED?
A. 1 am Preident of Utilty Resources, Inc. My firm consults on a number of
economic, financial and engineering matters for various private and public
, entiles.
Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
A. I am tesifying on behalf of the Southern Nevada Water Authority (SNWA).
Q. DOES ATTACHMENT 1 ACCURATELY DESCRIBE YOUR BACKGROUND
AND EXPERIENCE?
A. Yes.
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Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
A. In this Docket No. 02-11021, Nevada Power Company ("Nevada Power¡
seks authority to adjust the current Deferred Energy Accunting Adjustmnt
("OEM") rate and Base Tari Energy Rate ("STERn) such that the proposed
adjusted rates result in an overall rate reduction of 5.6% for residential
customers and a rate reduction of 5.1 % for nonreidential customers. These
percntage decreases are the result of Nevada Power proposing to amortiz
its additional accumulated DEA balances of $195 rniilion over a three year
period, but reduce its BTER in this case by almos 20% over the present level
to net to the reultant proposed overall rate decreases.
In its Application and filing, Nevada Power also requests two specific
waivers from deferrd energy accunting provisio. Nevada Power firs
requests a waiver to deviate from regulations to der and carry forward to the
next deferrd energy period Athe accrued but unpaid costs associated wih the
disputed (Enron, Cal Pine, Morgan Stnley, Reliant, Sempra, Trans-Canada)
claims of terminating suppliers", which it claims total $229 milion.
(Appliction, Page 15). Nevada Power makes a secnd request to deviate
from the regulations and seeks Commission approval for a new methodolog
for settng the BTER in this proceeding.
The purpose of my testimony is to propose certn adjustments to the
DEA rate and BTER rate based upon my differing opinions as to the
appropriate levels of prudent fuel costs incurrd by Nevada Power in it tet
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year Octber 2001-September 2002. My testimony also makes
recommendations on Nevada Power's requests to deviate from nonnal
deferred energy accounting regulaions.
Q. WHAT CONCLUSIONS HAVE YOU REACHED REGARDING THE
PRUDENCE OF THE $195.7 MILLION IN ADDITIONAL OEA RECOVERY
SOUGHT BY NEVADA POWER IN THESE PROCEEDINGS?
A. i concJude that in this case Nevada Powets request is overstate by at least
$90.8 milion. This overstatement appears to be the result of imprudent and
unauthorized purchases for fuel that, peculiarly, were made at the exact same
time for this test period as transactions that were found to be imprudent dunng
the previous test period in Docket No. 01-11029. In oter words, in the very
same period of time, February-Apr" 2001, in which Nevada Power was found
in-cket-No.O--14029--Aae-ade imprttt-andcesse-pei
purcases, i find in the present case that imprudent transactons made atthat
time also aff an amount of Its test year Ocober2001-8eptember 2002
expenses.
In paricular, I conclude that
1. Although Nevada Power indicates in its filing that it incurred
$265.9 millon in net natral gas and transportat costs in th
test year, the Company incurred only $140.8 millon of actual
costs for delivred natral gas. Nevada Power lost the
difference. a net of some $125 million. by speculating in
financial derivtives.
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2. The Company neglected in this filing to reduce tet year
purchased power costs to comply with the Commission order in
Docket No. 01-11029 that found that Nevada Power had
imprudently overbought power during early 2001and that
Nevada Power was required to reuce the DEA for not
acquiring 25% of it forward poer requirements in late 1999 at
a price based upon a "Meroll Lynch" proxy for the price of
forwrd powr. I did not have accss to necessary
documentation to complete eithr the overbought or Merril
Lynch adjustent as J explain below. Although appropriate for
the Commission to continue its precedent in this case, I have
not developed the related adjustments and have focused solely
on the new Issue of imprudence as a result of speculation in
natural gas financial deriatives.
3. The BTER rate set in this case should be adjusted upward in a
manner that approximately offets the $90.8 millon
disallowance to OEM balances i am proposing, pius any and all
other adjustments the Commission finds appropriate in this
easei including th Merrill Lynch adjustment, so 8S to preserve
the abilit of Nevada Powr to reduce rates to reidential and
nonresidential customers by 5.6% and 5.1 % respecvely but
also maintain the cash flow level request by Nevada Power in
this case.
NEVADA POWER'S GAS COSTS
AND FINANCIAL DERIVATIVES
Q. WHAT iS THE ISSUE WITH RESPECT TO THE TEST YE RECOVERY
OF NATURA GAS COSTS SOUGHT BY NEVADA POWER?
A. In Nevada Power's Exhibits E-2, Line 21 and E-3, Page 2 of 2, line 26, the
Company claims that it incurred Test Period Natural Gas Costs of
$250,256,132, net of inventory adjustment. This amount is carried forward
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with other test year fuel and purchased power cots to fonn the basis for
establishing and collecting test year costs through an adjusted DEM ra.
The $250,256,132 of gas costs is deried from Nevada Power Exhibit
E-11.6, Page 3 of 6, Lines 21-31, Column (aa) as the difference betwen
column (aa) subtotal of $265,860,683 and an adjustment of $15,604,551.
Line 21 indicates that Total (delivere) Gas and Transportation costs in th
test year were only $140,830,145. Line 23 of this same exhibit show a line
labeled "Less:Sales," that is, the revenues deri by Nevada Power from the
sellng off of any excess or unuse natural gas. But the sales revenues on
Line 23 are added to, rather than subtracted from, the Une 21 total gas costs.
In other words, by adding the sales revenue figure of Line 23 to Line 21,
Nevada Power is in effect indicating that it paid parties in the test year
$125,030,538 to take it excess gas. I initially assumed that the accounting
here was simply in error, wi an inadvertnt errr in sign, from negative to
positive.
The issue here is just what this "les: Sales " figure of $125,030,538
represents, and why is the figure being added to tet year costs and proposed
to be charged to ratepayers?
-5-
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Q. HAVE YOU DETERMINED THE SOURCE OF THE $125,030,538 THAT
NEVADA POWER INCLUDes AS A NATURAL GAS COST?
A. Yes. In a partal response to Data Request SNWA 17, a copy of which is
shown in my Exhibit _ (DEP-1), Nevada Power explains that the
$125.030,538 is the sum of actal sales revenues for its excess gas, and
losses it incurred in the use of financial derivatives, or financial trdes during
th test year. The figure of $125,030,538 is the sum of the sales revenues
from resellng excess natural gas (and therefore a negative entr) and the
actual loss of $133,184,681 the Company incurred by making "financial
trades. ø This is why I qualified in my conclusions above that Nevada Power
lost a "net" of $125 milion. It actually lost the $133.2 million.
Q. WERE AN ACTUAL OR PHYSICAL QUANTITIES OF NATURAL GAS
PURCHASED OR RECEIVED IN THIS FINANCIAL TRDING?
A. No. the $133,184,681 that Nevada Power is attempting to recver did not
purchase a single molecule of gas. Nevada Power paid an additional sum of
$140,830,145 for the actual gas that it burned in the test year.
Q. WHERE IN NEVADA POWER'S FILING IS THE TOPIC OF THE LOSSES
FROM FINANCIAL DERIVATIVES OF $133.2 MILLION ADDRESSED?
A. This topic is neither addressed nor explained in the Company's filng, excet
for a one page vague reference to hedging strategy in the testímony of witess
~
e e
Lorelei Reid, Direct, Page 4, Line 12, to Page 5, Line 15. This general
discussion never reference any of the financial consequences or
circumstance under which these financial derivatives were entered or even
that Nevada Power incurrd such loses.
Q. WHICH OF THE NEVADA POWR WITNESSES ARE RESPONSIBLE FOR
ADDRESSING THE PRUDENCE OF TEST YEAR NATURA GAS
EXPENSES?
A. The testimony of Mr. Coyle and the desition of Mr. Branch both identify Ms.
LoreLei Reid as the only witness addresing the issue of the prudence of test
year natural gas expenses.
Q. WHAT DOES MS. REID TESTIFY TO REGARDING THE COMPANY'S
FINANCIAL OR "HEDGING" STRTEGY FOR NATURAL GAS?
A. Fro a literal reading of her testimony, Page 4, Line 12 to Page 5, Line 15. i
inferred that at the September 5,2001 Risk Management Committee ("RMC")
meeting, which was just prior to the October 2001 start to the test year in this
cae, the RMC approved some form of hedging strategy for test period
supplies of natural gas. Had this happened, the timing would have been
almost perfectly consistent wi the hedging strategies that Nevada Power and
the RMC followed in the year prior. That is, on or about September 20, 2000
Nevada Powr began engaging in hedging stregies (basis swaps and fixed
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for floating swps) gradually over a course of six or sev months for the
Docet No. 01-11029 test year, which began October 2000.
But, whn I reviewe the September 5, 2001 RMC minutes referenced
by Ms. Reid in th present case, , noed that the minutes refct a request
by her and subsequent approval by the RMC to hedge only 10,000 Dthlday for
Nevada Power. Her testimony, Page 5, Line 5, indicates that the Company's
needs were approximately 150,000 Dth/day. No RMC minutes subsequent to
September 5, 2001, nor did the confdential gas purchase trnsaction sheets,
indicte any later hedgIng activities.
Q. WHAT DID YOU CONCLUDE FROM THESE MINUTES, AND MS. REID'S
TESTIMONY?
A. I concluded that Nevada Power eiter took a gas purchase position that was
indexed to actal markt prices for it remaining gas needs of approximately
140,000 Dtday, or had conducted hedging activties prior to the September
5, 2001 time fre but was without a reference by or any discusion of in Ms.
Reid's testimony. The lattr conclusion seemed most plausible, as I could not
understand' how the hedging position of the relatively modest quantity
of10,OOO otdaycould have led to the huge test year losses of $133.2 milron.
A gas purcase position that would have been indexed to the market pnce
could not have produced any financial loes.
-8.
e e
Q. HAVE YOU BEEN ABLE TO DETERMINE THE SOURCES AND CAUSES
OF THE $133.2 MILLION LOSSES FROM HEDGING?
A. Yes. Several months prior to September 5, 2001, over a period of just four
spefic days, February 22, and April 11, 12 and 27, Nevada Power entered
into a limited number of very high prd basis hedges that produced the
overwhelming percentage of it test year financial losses. The taking of these
huge positions was inconsistent with an appropriate buy over time hedging
strategy that was in pla, as well as inconsistent wih the gas hedging
strtegy that Nevada Power had implemented in the purchase of its Docket
No. 01-11029 test year natural gas supplies. As I show below, had Nevada
Power remained with its bu-over-time strategy, it could have reduce its test
year natural gas cots that it attributes to financial derivaties in the present
case test year by at least $91 millon.
Q. WHAT NATURA GAS PROCUREMENT POLICY WAS IN EFFECT AT
NEVADA POWER DURIG THE PERIOD IN WHICH THE TEST YER GAS
HEDGES WERE MADE?
A. There was no written natural gas procurement strateg In effect during the
time frame that th hedging that took place on February 22, April 11 ,12 and
27.2001 (Reid dep., page 104, fines 12-24 and page 162, Lines 9-15). In
addition. there were no discussions that could be recalled by Ms. Reid
concerning these hedges prior to the February 22 or April 11 , 12 and 27,2001
.g.
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purcases despite statements by Nevada Power that suc discussions and
pre-approvals are usual pracice. Although Company protocol reuired
signatures on trades by superiors, the approvals for the trdes in question
here we not obtained until after the trdes had be executed (Reid dep.,
Page 55, Line 1 to Page 56. line 24, and Page 143, Lines 3~16).
Q. ARE THERE DOLLAR VALUE UMITS ON THE RISK ASSOCIATED WIT
THE FINANCIAL TRANSACTIONS THAT NEVADA POWER PERSONNEL
CAN ENTER INTO?
A. Yes. During the period in question, the dollar value limit for Ms. Reid to enter
into natural gas transactions was $2 millon per trade. I am unable to explain
how the February 22 and April 11 , 12 and 27 trades could have been entered
into consisent with this restricon, given the evenual $133.2 mOUon losses
associated wi them.' Ms. Reid's total of only six individual transactons on
February 22 and April 11,12 and 27 for basis swaps alone totaled loss
positions of over $90 millon. One trade was conducted on February 22, two
trades conducted on Aprill1. one trade on April 12 and tw trdes conducted
on April 27. The loses associate wi each trade ranged from over $5
millon individually for one trde, to over $30 million.
1The doliar value limits of $2 mllion were increased to $5 milion subject to
Board approval, later at the May 23, 2001 RMC meeting.
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Q. CAN YOU DETRMINE WHETHER THE RISK MANAGEMEN COMMITEE
WAS OPERAnNG UNDER ANY DEFINED GAS PROCUREMENT
DISCIPUNE?
A. Minutes of an RMC meeting date February 29, 2001, Page 2. attached as my
Exhibit _ (OEP-2) indicate that an members approd a motion to It ...
continue the current buy over time sttegy with respec to Nov. -Mar. 2002 ..."
with repect to natural gas purchases. This same motion, however, require
that u... by next meeting an outline of a fuel procurement strte with respec
to coal/gas be prepared assuming no divestiture of generaton l1... No such
outline was prepared for the next RMC meeting of March 14,2001, nor was
any discussion or outline prepared prior to any of the February 22 and April
11, 12 and 27 trdes made by Ms. Reid. I wish to make clear here that these
February-April financial trades at that point in time were not for the coming
symmer months, but for the following 2002 winter and summer months.
QUANTIFYING THE LOSSES OF
THE GAS FINANCIAL DERIVATIVES
Q. JUST WHAT DID NEVADA POWER DO IN TERMS OF TRANSACTIONS
WITH FINANCIA DERIVATIVES TO INCUR $133.2 MILLION IN LOSSES?
A. There are two fundamental components to delvered gas costs: the actal or
physical gas ("commodit") cost. and the transporttion cost to the point of
recipt ("pipeline" or Mbasis"). Unless Nevada. Power holds contract capacit
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on the pipelines serving Southern Nevada subject to FERC cost of service
rates, the cost of each of these two components varies in today's gas markets
under natural gas deregulation by the FERC. Therefore, in order for Nevada
Powr to completely fix a test yer price of gas delivere to it systm, which it
apparetly wished to do, the Company hedged both commodit prices ("fixd
for floang or FFSWAp.) and transporton delivery prices ("basis swap").
The $133.2 million in financial hedging losses were the result of the market
pnce of both commodity and basis fallng dramatically aftr the hedges were
put in place. From Exhibit 1 attched to the deposition of Lorelei Reid, the test
year losses for each hedge can be sen as:2
Commodity $36.8 million loss
Basis: $99.7 millon loss
Q. SHOULD NEVADA POWER HAVE HEDGED GAS COMMODITY ANDIOR
BASIS IN THE MANNER IN WHICH IT DID?
A. Absolutely not At least three issues need to be addressed prior to entering
such hedges:
1. Should hedges or fied..rice financial derivatives be used at all,
or should the gas have been bought at indexed prices with no
possible financial impact on the Company or it customers?
2. Did Nevada Power possess or feel that it posseed superor
trading prowess or knowledge to ''bat the market," which in this
instance meant that it knew that both commodity and basis
prices would be higher over the October 2001-September 2002
2 Reid Oepositin Exhibit 1, pa 18 Grand Total for marK to market losses for FFSWAP
(commodity) and page 32 Grand Total for mar to market losse for BASISSWAP.
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test year, than the hedges it conducted In the Februar and April
2001 time period?
3. If Nevada Power did not posess superior market knowledge or
abilties, Uien a hege should always be done in increments,
over time, to avoid taking a .price view" that is, making a bet that
prices would continue upwrd.
Q. PLEASE ADDRESS THE ISSUE OF WHETHER FIXED PRICE HEDGES
SHOULD HAVE BEEN ENTERED.
A. In retropect the answer is easy. No. Gas costs wold have been $133.2
million lower absent the hedges. But the issue hee regarding hedes Is
whether or not Nevada Power should be taking on such financial risk when it
was anticipating to be or actally was under a defrred energy mechanism.
The corollary issue is whether this nsk shouJd be borne by shareholders or
ratepayers.
Q. WHY DO YOU STATE THAT NEVADA POWER COULD HAVE AVOIDED
THE USE OF FINANCIAL DERIVATIVES AND ASSOCIATED FINANCIAL
RISK BY SIMPLY ENTERING INTO GAS CONTRACTS WITH PRICES
INDEXED TO MARKET PRICES AT THE TIME OF GAS DELIVERY?
A. Financial hedges are nothing more than bets betwn a part and
counterpart. One part bets that prices are going to rise and the counterpart
bets that price will decrease. In each financial hedge that was underken by
Nevada Power, the Company wa bettng that gas prices would continue
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upward. That is all that a financJal hedge is: a contractal commitment to
make a financal (only) settlement that is based upon the relaionship betwn
the hedged contract price, and the actual market price at the time of gas
delivery.
With gas that is purchased with prices that are Indexed to markt
pnces, no bet has been made, and no financial gains or losses are incurred.3
In such cases, Nevada Power simply receives and pays for natural gas at th
prevailng market price and has no additional financial responsibilit.
Q. DID NEVADA POWER POSSESS SUPERIOR TRAING ABILmES OR
INFORMATION WHEN EXERCISING THE TEST YE HEDGES?
A. No. As l explained above. there is no evidence of anything oter than a buy
over time gas purchase strateg in place at the Company prior to the
February-April financiat hedges and there we not even any discussions of
pending expeced commodity or basis price increases at the time in February
and April 2002 when the hedes were made. Again, unless Nevada Power
held strong, informed convictions that commodity and basis price were going
to rise above the then record level, then the financial hedges it enteed could
only have resulted in monetary losses.
3 Ms. Reid acknowledges this In reard to index prices u...Since the leinated supply contracts
were priced at index, the terminations had no financial impact on the Company or its customers... .Direct, page 4, J 2-5). -14-
e e
Q. WERE THERE IN FACT DISCUSSIONS OR FORECASTS PRESENTED TO
NEVADA POWER THAT COMMODIT AND BASIS PRICES WERE GOING
TO DECREASE, NOT INCREASE AS IT BET?
A. Yes, and subsequent price decreases that actually did ensue are wha
eventually red to the large financial losses. In March 2001 the Invetment
banking firm of Goldman, Sachs & Co. made a preentation to Sierra Pacifc
Resources. A copy of the Goldman, Sachs & Co. presentation accompanies
the minutes of the RMC meeting of March14, 2001. This preentation shows
commodit and basis prices well belo those that Nevada Power entered into
on April 111 12 and 27, 2001. Knowedge of these forecasts, but exercising
the hedges anywy, greatly increased the financal risk of the Company's April
2001 hedges for the test year in this proceeding.
Q. WHY DO YOU MAINTAIN THAT IN THE ABSENCE OF SUPERIOR
MARKET KNOWLEDGE, HEDGES SHOULD ONLY BE IMPLEMENTED IN
INCREMENTS, OVER TIME?
A. If Nevada Power did not have a "price vi," that is, a strng analysis or view
that prices were going to rise, but stiR wanted to fix its test year gas prices, the
best proceure is to buy over time. This is sometimes referred to as price
averaging. Buying over time is an acknowledgment that one does no expect
to, at any point in time, beat the market. As commodites such as natural gas
have price pattrns that are cyclical, buyng over time moderate oreliminate
-15-
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price risk. Some supplies are purchased at point on the price cycle below
average prices; some supplies are purchased at points on the price cycle
above average prices. Many studies indicate that commodit price
, movements are somewhat random and unpredictable and. in order to remove
timing risk, should be bought overtime, thereby maxmizng the probabilites of
buying at averages over tie. My Exhibit _(DEP-3) is an excerpt from the
Company resnse to an oral reuest made at the deposition of Lorelei Reid
and contains a WEFA consulting report made to Nevada Power that
underscores the point that comodit prices and unpredictable.
Q. DID, IN FACT, NEVADA POWER ENTER THESE COMMODITY AND
TRANSPORTATION HEDGES AT THE "WRONGu TIME?
A. Yes. Neva~a Power clearly entere thes transactions at the top or high side
of the price cye. During the FebruaryApril 2001 time frame, both gas
commodit and market basis price were at all time reord levels. Lockin into
hedges at this time is imprudent unless Nevada Power had strong information
and advice that prices were to continue setting new record levels. As one
might expect with commodity prices that are cyclical, actual gas commodity
and basis prices plummeted two months af the executin of the hedges and
huge financial loses ensued. My Exhibit_(DEP-4) show the historical
behavior of gas commodity and basis prices before, during and after the
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February- April hedging. Nevada Power's timing could not have been worse,
as both of thes prices plummeted in the following two months.
Q. DID NEVADA POWER USE A BUY OVER TIME HEDGING STRATEGY FOR
ITS DOCKET NO. 01-11029 TEST YEAR NATURAL GAS PURCHASES?
A. Yes. The test yer for Docket No. 01-11029 was October 2000-8eptember
2001. From a review of files oftransaetions sheets for gas hedging provided
by Nevada Power, I was able to determine that the Company's hedging
positions in this prior deferre energy test year ocurrd over an approximate
six month period beginning in September 2000. Over this period, Nevada
Power purchased approximately equal quantities of gas in a disciplined
manner over time.
If the Commission rules that it was prudent for Nevada Power to use
financial derivatives at all in acquiring natural gas suppUes, thn I recommend
that the Commission Impose a buy over time hedging stratey that re-rices
Nevada Power's present test year hedges according to a six month gradual
purchase period.
Q. WHY DO YOU MAKE THIS RECOMMENDATION?
A. I realiz that dealing in financial hedges is risky busines. Financial
derivatives do not reduce gas costs over time. they only introduce price
certinty. But there is no means to know ahead whether these certin price
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are above or below market. In orer to benefit at all from thes financial
hedges, the hedging must be done gradually over time.
BENEFICIARIES OF GAINS FROM NEVADA
POWER SPECULATION IN FINANCIAL DERIVATIVS
Q. DID THE COUNTER PARTIES TO THE FEBRUARYwAPRIL FINANCIAL
HEDGES WITH NEVADA POWER MAE SUBSTANTIAL MONETARY
GAINS?
A. Yes. In these few hedging trnsacton, Nevada Powts losses were the
countrparties' gains. Counterparts gained over $133 milion on these fe
financial hedges, in a penod of a fe days.
Q. WHO BENEFITED FROM NEVADA POWER'S HEDGED
TRANSACTIONS?
A. Interestingly, only three counterparties were involved in all of the commodity
and basis trnsactions with Nevada Power.
GAS COST ADJUSTMENTS TO
REFLECT PRUDENT HEDGING
Q. HOW DO YOU PROPOSE TO ADJUST THE FINANCIAL LOSSES FROM
NEVADA POWER'S HEDGING TO REFLECT A GRADUAL, BUY OVER
TIME PROCUREMENT STRTEGY?
-18-
ti e
A. I propo to re-price the actal hedging transactions made by Nevada Power
by using the actual market prices for these hedging instruments that existed at
mid-month in each of the six month prior to the period of gas deivery. In
other words, rather than use the commodit and basis prics that Nevaa
Power locked into because of its concetraed purchase, i use the actal
market prices of such financial deritives that Nevada Power would have
experienced had it followe it buy over time strtegy.
Q. PLEAE EXPLAIN.
A. My Exhibit _ (DEP-5) refct two hedging straies. Th left-most box of
this exhibit, "NPC Acquisitions," shows the actual commodity (NYMEX Fixed
for Floating sWaps) and basis (50Cal Basis Swaps) transactions that Nevada
Power entred into. The purchases are broken into the typical gas contract
wintr and summer periods, November 2001--arch 2002 and April 2002-
October 2002, respectively.
For example. the commodity hedges entered by Nevada Power for the
gas in winter of the test year were for 70,000 MMBTUlday at an average
wintr price (for the comodity only) of $4.91. For the summer, the position
was for 55,000 MMBTU/day at an average price of $3.10.
Similarly, the winter basis or transportation component of gas also had
a position of 70,000 MMBTU/day, but was entered at an average price of
.19-
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$4.14. The summer position of 50,000 MMBTUlday had an average price of
$4.94.
Q. WHAT DOES THE BUY OVER TIME STRATEGY IN YOUR EXHIBIT
_(DEP-5) SHOW?
A. The right-most box of Exhibit _(DEP-5) shows the diferences in the
financial commodit and basis price that would have ocurred had Nevada
Power more closely adhere to It buy over time straegy. and had it not
atempted to time the market in the February and April time frme.
The Buy Over Time Strategy re-pnces Nevada Power's trades
accrding to mid-month commodity and basis tres in each of the six months
prior to seasonal requirements. The reprlced positions result in commodity
price of $3.95 and $2.78 for winter and summer period, respectively. The
re-priced positons result in basis prices of $1.04 and $.04 for winter and
summer periods, repetively.
Q. WHAT DOES YOUR EXHIBIT _ (DEP-6) SHOW?
A. Exhibit _ (DEP-6) computes the adjustment to test year natural gas cost
that Is necessary to reec the reduced comodity and basis prices that
should have been experienced under Nevada Power's stated purchasing
policy.
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The total financial derivatives cot is computed for Nevada Power's
financial derivatives cost as well as the financial derivatives cost of the buy
over time strategy. Had Nevada Power followed it buy over time stratey i its
test year natural gas cots would have been $90,763,715 lower. This amount
of unnecessary additional cot was incurred imprudently and should be
removed from the OEM balances in this case.
Q. EXHIBIT _ (DEP-6) REFLECTS NATURA GAS COST DIFFERENTALS
FOR ONLY THE ELEVEN MONTH PERIOD NOVEMBER 2001..
SEPTMBER 2002. WHY?
A. Although Octber 2001 is in the current te year, the gas supplies for this
month wer obtained as part of the summer acquisitons made for the
previous test year. As I find no fault with the procurement policies from the
last test year, l make no adjustment for October 2001.
SOUn-WEST GAS COMPANY COSTS OVER SAME PEBIOO
Q. DID YOU COMPARE THE PURCHASE STRATEGIES AND RESULTING
GAS COSTS WITH OTHER NATURAL GAS PURCHASERS IN THE
REGION?
A. Yes. My Exibit_CDEP-7) compares the unit gas cots experience by
Nevada Power and Southwest Gas Company over the course of the test year.
While Nevada Power paid an average price of $6.39/D in this tes year,
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Southwest Gas paid an average of only $3.88/Dth. The Commission has
determined that the average cost paid by Southwest Gas was prudent for this
period in the most ret PGA case. Had Nevada Powr an average pnce of
$3.88/Dth. its test year gas cots would have been $98.4 millon lowr.
OVERBOUGHT AND MERRILL lYNCH ADJUSTMENTS
Q. WHAT ARE THE ISSUES WITH RESPECT TO YOUR REFERENCES TO
THE OVERBOUGHT AND MERRILL LYNCH ADJUSTMENTS?
A. In Docket No. 01-11029 the Commission found that Nevada Power had
continued to purchase power even after it had reached its stated objectve
of107% of average peak loads. The Commission quantified the amount of
imprudent cots associate with the excess purchases and denied the
recoery of such costs. In the present case, Nevada Powets load and
resource balances appear to indicate a lesser, although significant amount of
excess purchase in certin months of the test year. Nevada Power has
proposed no adjustment in this case for excess purchases. I have not been
able to estimate the amount of any imprudent expenses for an overbought
position in this case; due in part to lack of full access to necessary documents
data. I did not participate in the FERC procedings for the terminated
purcased power contract, nor did I have access to the tenns and conditions
for the Duke Energy contract renegotiations. I have not reviewed the Duke
contracts as they are confidential and have not been given to me.
-22-
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WIth repect to the Merrll lynch adjustment, I did not consider this
issue in Docket No 01-11029, although I understand that the Commission ordered
that this adjustment be made. Nevada Powr has appa~entl not followe
through in this case 'with the Commission ordere Merñll lynch adjustment.
Alhough I have not been able to foJlowthrough with an independen Merrill Lynch
calculation of my own in the present case, I do not disagree with the Commission
order on this issue. I have also seen the Nevada Power response to MGM 6-01 in
this case that contains additional details of the terms and conditions of the Merrll
Lynch transaction. I understand that certain other parties are addressing this
issue In the present case.
SUMMARY AND CONCLUSIONS
Q. PLEAE SUMMARIZE YOUR REOMMENDATIONS AND CONCLUSIONS.
A. My review and recommended adjustments in this case have been limited to
the test year natural gas cots incurre by Nevada Power. My review
indicates that Nevada Power lost $ 133.2 milion through financial derivtives
intended to speculate that gas commodit and basis prices were going to rise,
despite a lack of analysis to support this speclation.
I have re-priced these hedging losses to reflec the level of losses that
would have been incurre by Nevada Powe if it had followe its stated
strategy of purchasing on a "buy over time" basis. My analysis Indicates that
an amount of $90.8 millon of losses were the reult of imprudent decisions
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resulting from the Company deviating from its ow strategy. I reme1h
the Commission order Nevada Powr to remove $90.8 milion from its
proposed OEM balance.
The BTER issue has been a moving target throughout discovei and
depositions in that Nevada Power has request approval of the new
purchased por contract. but has not responded to requests to demonstrate
the eff of these contract prices and provisions on the BTER. Thus the
rationale and justition given in the direct testimony is not applicable. The
costs developed in his testimony are no longer a reliable basis upon which to
estimate fuel and purcasd powr cots for the BTER. Natural gas price
have also increased somewhat since the filing of Mr. Branch's testimony.
Without information on the degree of hedging undertaken by the Company
and the terms of the proposed contracts, I cannot reliably quantify a BTER. I
propoe that the Commission order Nevada Power to exactly offet the OEA
adjustments that i, and others propose. and which the Commision accepts,
with an upward adjustent to the BTER proposed by Nevada Power in this
case.
Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
A. Yes.
-24-
~e e Exi~it (DEP 1)
Page 1 or2.
NEVADA POWER COMPANY
RESPONSE TO INFORMATION REQUEST
DOCKET NO.:02-11021 REQUEST DATE: Jan 29, 2003
WITNESS:REQUEST NO.: SNWA 17
REQUESR:Dennis Peeau RESPONDER:Rice, Bruce
REQUEST:
Regarding Exib E 11.6, paes 2 and 3 of 6:
Unes 23 of paes 2 and 3 of 6 sh pove en fo -Sales-. saies revenues shoud
be us to reduce toal gas cots, yet line 23 is added to line 21, incasng tota gas
cots:
a. Should tine 23 actuay show negati dolla values to rect offse to
ga cots? Pleae exla.
b. Why were th fine 23 Sale revenues reeced as netie values in the
corrponding schedules in Dock No. 01-11029?
c. If NPC intends for lin 23 rerenced above to actlly be poive in th
filing. is NPC paying part to take it gas supplies? Please exlain.
d. Pleas proide all woer. supong docuenton and invoice
pertinng to all Exibit E- 11.6.
RESPONSE:
The "sales" shown on line 23 represent net actvity of sales (gas sold
to ~stomers) and financial trdes (hedges). Generaly, NPC .
subtracts the safes of gas from total gas and transporttion costs,
thereby reducing total gas costs.
The expenses of th financial trades (hedges) were greater than the
sales for the test period ending September 2002. This resulted in a
positive amount that is added to total gas and transportation costs.
Please see Uie attached spreadsheét Uiat details by month the
amounts for sales and financial trades for both the currnt filing as
well as Docket 01-11029.
.'
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Docket No. 02.11021
Sourn Nevada Water Autority
Adjustment for Ov Time Buying
NPC Financial Traes
Nymex FFSWps
Nov,01~Mar,02 A.rlO2-8pt02 TotalMMBtu/Oay 70,000 55.000Volume (MMBtu)1°1570,000 9,615,000 20.185,000Total Cost 51,928,900 29.778.525 81,707,42$IMMBtu 4.91 3.10 4.05
So Basis Swaps
Nov,01-Mar,02 Apr,02-5pt.02 TotalMMBtu70,000 50,000Volme (MMBtu)10,570.00 9,150,000 19,720.00Total Cost 43.752.250 45,155,250 88.907.500$/MMBtu 4.14 4.94 4.51
NPC Hedging Cost 95,681,150 74,933.775 170,614,925
Over Time Hedging Cost 52,745.055 27,106,155 79,851,210
Adjustment (42,936,095)(47,827,620.0)(90,763,715)
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Page 1 of3
STATEMENT OF OCCUPATIONA AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conducted economic and financial studies for regulated
industrs for the pas twnty-eight years. In 1972, he was employed by Southern
California Edison Company as Associate Economic Analyst, and later as Economic
Analyst His responsibiltie included review of finanCial testimony, Incremenl cost
studies, rate design, econometrc estimatin of demand elasticities and various areas
in the field of energy and economic growt. Also, he was asked by Edison Electicl
Institute to study and evaluate several prominent energy models as part of the Ad
Hoc Commit on Economic GÌ' and Energy Priing.
From 1974 to 1978, Dr. Peseau was employed by the Public Utilit
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and finanCial studies and prepared testimony pertining to public utlies.
In 1978 Dr. Peseau established the Nortwet offce of Zinder
Companies, Inc. He has since submittd testmony on economic and financial
matters before state reuiatry comissions in Alaska, California, Idaho. Maryland.
Minnesota, Montana, Nevada, Washington. Wyoming, the Distric of Columbia, the
Bonnevile Power Administration and the Public Utiltie Board of Albert on over one
hundred occions. He has conducted marginal cot and rate design studies and
"..;
I
e eæchment1
Page 2013
prepare testimony on these mattrs in Alaska, California, Idaho, Maryland,
Minnesota, Nevada, Oregon, Washington and In the District of Columbia. He has
also conducted cost and rate studies regarding PURPA issues in the staes of
Alaska, California, Idaho, Montna, Nevada, New York. Washington. and
Washington, D.C.
Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics.
He has co-authored a book in the field of industrial organization entitled,
Size. Profits and Executi Copensation in the lerge CorporatiQ.n. which devote
a chaptr to regulated industries.
Dr. Peseau has publishe articles in the following professional journals:
Review of Economics and Statistics. Atlantic Economic Joyrnal, Journal of Financii1
Managemeot, and Journal of Regional Scen~. His art have been read before
the Econometric Society, the Western Economic Association, the FinancIal
Management Assation, the Regional Science Association and universities in the
United Kingdom as well as in the Unite states.
He has guest lectured on marginal costing methods in seminars in New
Jersey and Califrnia for the Center of Professional Advancement He has also
guest lecred on cost of capital for the public utilty industry before the PacJfic Coast
Gas and Electic Association, and for the Executie Seminar at the Colgate Darden
Graduate School of Business, Universit of Virginia.
0..:. ,
. '
. .e 4tchment 1
Page 3 ot3
Dr. Pesau and his firm hav participated with and been members of the
Amerin Economic Asocation. the American Financial Association, the Western
Economic Assocation, the Atlantic Economic Association and the Financial
Manageent Association. He was formerly a member ofth Sta Subcommittee on
Economics of the National Associion of Regulatory Utility Commissioners.
Or. Peseau has been President of Utilit Resources, Inc. since 1985.
4 . l .e e
AFFJRMA TION
J, Dennis E. Peseau, pursuant to NAC 703.710 hereby affirm that the
foregoing prepared testimony was prepared by me or under my direction and is
correct to the best of my knowlede.
Signed ¡l't&e-t1
Dated -J1øu/- i ¿tli¿
".:
.. ..
i
2
3
4
5
6
7
8
9
¡ 10~8
oN.. 11:iBo
ii~ 12.. ii,= u'g 13
. ~ ~(I Z 14
Ql r;
~=... 15¡...c;
Øl~ i:
ii ~ 16~.. ~ 170..
ii'" is
:=
19
20
21
22
23
24
25
26
27
28
0_.:.
e -
PROOF OF SEVICE
I hereby cefy tht I maied the foregoing Prpar Testmony of Dens Pes in
Docket 02-1 1021 by delivering to the U.S. Post Offce copies thof, prperly addresd for
miuling to the following persons:
Bet Ellot
Nevad Power Company MS 3A
6226 W. Sah Avenue
La Vegas NV 89151
Timothy Hay
Consumer Advocate
Bureau of Conswner Protection
1000 E. Wiliam Strt, Suite 200
Caron Cityt Nevaa 89701
Lawrnce Gollomp
U.S. Depaent of Energy
1000 Independence Avenue SW
Washigton, DC 20585
Staf Counel
Public Utiities Commission
1150 East WiUiam Street
Car City, NV 89701
Jon WeIIngboff
Bekley Singleton Chtd.
530 La Vegas Blvd. South
Las Vega, NY 89101
Mark Russell
Mirage Hotel & Cano
3400 La Vega Blvd. South
Las Vega, NV 89109
Erc Witkosk,
Nevad Attorney General'5 Offce
555 E. Washigtn St., Suite 3900
Las Vega, NV 89101
::OOMA\PS\HLRNODOS\3234n\i Page 1 of2
. I I
1
2
3
4
5
6
7
8
9
18
10
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1 ~12
§lj 13
i Ž 14
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J~O 17
I) f'
'i I"isti
19
20
21
22
23
24
25
26
27
28
e ~
Tam Polito
Bureau of Consumr Protection
1000 E. Willia Street, Suite 200
Caron City, NV 89701
Robe Crowell
Crowell, Susich, Ow & Tookes, Ltd.
P.O. Box i 000
Caon City, NV 89702
Joyce Newm
Utility Shaholde Associaton
P.O. Box 1823
Caron City, NV 89702
Gerald Lopez
Colorao River COmmssion of Nevada
555 East Wasingon Avenue, Suite 3JOO
Las Vegas NV 89101
David J. Gildersleee
Nevada Energy Buyers Netrk
8685 W. Sah Avenue, St. 200
Las Vega, NV 89117
Dale Swa
Exetr Associates, Inc.
12510 Prospety Drive, S1. 350
Silver Sprg, MD 20904
, James D. Salo
Colorad River Commsson of Nevada
555 Eat Wasngton Avenue St. 3100
Las Vega, NY 89101
Dated: Marh 7, 2003
_lsi,An PEEK
D ¡SON AND HOWARD
777 E. Willam Str Suite 200
Carso City, Nevad 89701
::ODMA\P&'\NODOCS2347J\1 Page2of2
" :
Dean J. Miler
McDEVI & MILER LLP
420 West Banock Street
P.O. Box 2564-83701
Boise,ID 83702
Tel: [phone]
Fax: [phone]
joe(fmcdevitt-miller.com
Ida Pu Jtilties Commissio
Offi(,:~1 lIie SecretaryRECEIVED
NOV 30 2O
Bo, Id
Attorneys for Applicant
BEFORE THE IDAHO PUBLIC UTILITS COMMSSION
IN THE MATTER OF THE APPLICATION
OF UNTED WATER IDAHO INC. FOR
AUTORITY TO INCREASE ITS RATES Case No. UW.W-0404
AND CHARGES FOR WATER SERVICE IN
TH STATE OF IDAHO
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
DIRCT TESTIONY OF DENNIS E. PESEAU
1 Q.
2
3
A.
4 a.
5 A.
6
7
8 a.
9 A.
10
11 a.
12
13 A.
14 Q.
15
16 A.
17
18
19
20
21
22
Please state your name and address.
My name is Dennis E. Peseau. My address is 1500 Libert
Street, S.E., Suite 250, Salem, OR 97302.
By whom and in what capacity are you employed?
I am President of Utility Resources, Inc. Utilty Resources, Inc.
consults on a number of economic, financial, engineering and
regulatory matters for private and public entities.
On whose behalf are you testifying in these proceedings?
I am testifying on behalf of United Water Idaho Inc. ("United". or
"the Company").
Does attachment 1 to your testimony describe your professional
career and educational background?
Yes.
What is the purpose of your direct testimony in these
proceedings?
I am sponsoring Exhibit 14, a cost of service study ("COSS") of
the water system of United, and making rate design
recommendations based in part on the COSS. The reason i
state that my rate design recommendations are based only "in
part" on the COSS is an acknowledgement that here in Idaho,
and usually elsewhere, implementation of effcient, fair and
equitable rates to United's customers requires a good deal of
Peseau,Oi 1
United Water Idaho Inc.
1
2
3
4
Q.
5 A.
6
7
8
9
10
11
12
13 Q.
14
15 A.
16
17
18
19
20
21
22
23
practical judgment in addition to the cost guidelines given us
from the COSS.
Have you previously testified before the idaho public utilties
commission on cost of service and rate design matters?
Yes. I have testified before this Commission on such matters on
numerous occasions dating back to 1980. I have represented
various customer groups previously on COSS and rate design
issues involving electricity and natural gas. i believe that this
case is the first water system COSS and rate design study that I
have prepared in the State of Idaho, although I have testified in
water cases on several occasions in Oregon, Nevada and
California.
What conclusions have you reached from your studies and
analyses?
I conclude that:
1. The customer charges now in place are significantly below
customers' cost of service and should be raised. i propose that
these charges be raised by approximately 36%.
2. Customer class distinctions in the present case remain
according to meter size.
3. There is substantial difference in seasonal commodity costs
of service between the winter and summer and the present 25%
commodity rate differential should be maintained.
Peseau.Oi 2
United Water Idaho Inc.
1 a.How is your testimony organized?
2
3
4
A.Prior to my presenting the detailed COSS and rate design
proposals, I focus initially on a review of some of the water
system cost of service and rate design issues that United,
5 Commission Staff, and intervenors and therefore, this
6 Commission considered in the prior rate case No. UWI-W-98-3
7 and subsequent Order No. 28043. In that case, a number of
8 different COSS and rate design proposals were presented and
9 evaluated. The issues considered there provide a perspective
10 for the COSS and rate design enhancements I discuss below.
11 ' SIGNIFICANT COSS AND RATE DESIGN ISSUES
12 a.What significant COSS and rate design issues arose in the 1998
13 rate casethat remain pertinent in the present proceedings?
14 A.Leaving aside for the moment the many technical COSS issues
15 pertaining to functionalizing and classifying the numerous cost
16
17
categories involved in describing the United system, there were
threshold issues in the prior rate case.
18
19
a.Please briefly explain these threshold issues.
A.The first issue pertained to the consensus conclusion that the
20 revenues collected under United's customer charges fell
21 significantly short of covering the costs of serving customers.
22 Customer costs are defined as the costs associated with
23 customer billng, meters, service and fire protection. As
Paseau, Di 3
United Water Idaho Inc.
1 customer costs comprise a significant percentage of customers'
2 bils and they cannot be "avoided" by reducing water
3
4
consumption, customers tend to prefer low customer charges.
The issue in the present case is just how much to raise the
5 present level customer charges, given the continuing disparity
6 that I find between these rates and customer cost of service.
7 A second important issue was the means by which customer
8 classes were to be defined. For a number of reasons, United's
9 customer classifications, for purposes of COSS have been
10
11
based on meter size, not classes such as residential,
commercial, industrial or public authority. In Case No. UWI-W-
12 98-3 it was recognized by Commission Staff and United that the
13 sampling, load profile and other usage pattern data necessary to
14 construct meaningful residential, commercial and other rate
15
16
classes would be very costly and diffcult to develop. i consider
cost distinctions by meter size to be the reasonable classification
17 of costs and continue this practice in the COSS I develop.
A third important rate issue taken up in Case No. UWI-W-98-18
19 3 was the design of the usage or commodity rate. This usage-
20 sensitive or commodity portion for rate design is especially
21 important in that it is here that customers confront the price
22 signals that form the basis for effcient water usage as well as
23 conservation decisions.
Peseau, Di 4
United Water Idaho Inc.
1 In the 1998 rate case, the then-existing seasonal rate
2 structure was re-examined in light of certain customers'
3
4
frustration or confusion over facing different commodity rates
during different times of the year. The sense seemed to be
5 "Shouldn't it cost me the same to bathe in the summer or the
6 winter if my consumption is somewhat flat year-round"? I argue
7 below that the answer to this question is "No, but the good news
8 for you is that appropriately seasonalized rates result in your
9 total annual bils for water used to bathe being less for you than
10 in the absence of seasonalized rates." That is, the cost of a bath
11 in the winter is lower by a greater amount than the cost ofa bath
12 in the summer is higher, if your annual consumption is relatively
13
14
flat. As shown more formally below, the reason that annual bils
for relatively flat demand water customers are reduced by
15 seasonalizing commodity rates is that, compared to other
16
17
customers, their consumption occurs relatively more in the winter
or "off-season" rate period. With effective communication, these
18 customers' frustration with differentiated bils could not only be
19 softened but perhaps be offset by the knowledge that their level
20 (Le., effcient) consumption is rewarded by the seasonal rate
21 structure in the form of less expensive annual bills. The
22 reduction in these annual bils is made up from customers that
23 do not have level consumption, such as irrigation loads. The
Peseau, Di 5
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11 a.
12
13 A.
14
15
16
17
18
19
20 a.
21
22 A.
23
higher percentage of revenues paid by higher summer
consumption is as it should be, for the summer period is shown
below to have the higher costs of service. So long as there is a
reasonable cost basis for seasonal rate differentiation, seasonal
rates are fair, equitable and "bettet' than flat annual rates.
Previously, the basis for seasonalizing the Company's rates was
informed judgment. The COSS undertaken for United in the
present case actually distinguishes and differentiates commodity
costs by seasons rigorously rather than relying solely on
judgment.
Did you consider proposing an inclining or inverted block rate
structure here similar to proposals in uwids last rate case?
Yes. As part of my preparation for the present case, i read much
of the record in Case No. UWI-W-98-3 where the topic of
inverted rates was discussed. i note that after the Commission
considered the issues pertaining to commodity rates, Order No.
28043 concluded that seasonal rather than inverted block rates
be implemented, although there was a dissenting opinion on the
issue.
What is your recommendation with respect to the commodity rate
issue?
There is no perfect means to estimate commodity costs and
transfer these costs to rate design. Ultimately judgment not only
Peseau, Di 6
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30 a.
31
32
about costs but also rate stabilty, understandabilty and other
equity issues must be addressed.
I do, however, prefer and in this case recommend continued
but improved use of seasonal over inverted block rates. While
over the years I have estimated and recommended both
seasonal and inverted block rates, I believe in this case
rate making goals are better served with a seasonal rate
structure, perhaps modified by a minimal initial summer
consumption block.
As Commission Staff and others discussed in Case No.
UWI-W-98-3, and in my opinion hold true in this case, seasonal
rates:
1. Are able to be estimated formally within the COSS and
give more formal foundation and understanding of
seasonal cost differences;
2. Although not as simple as annual flat commodity rates,
are much simpler and more understandable compared
with multiple block rates; ,
3. Assure a better price signal to and promote
conservation by customers than do inverted block
rates;
4. Allow customers at all times to know the rates they
face, while they may never know the rate they face at
any particular point in time with an inverted block rate
structure.
Did commission staff in case no. Uwi-w-98-3 correctly point out
that the COSS in that case did not tell us directly how costs vary
by season?
Peseau,Oi 7
United Water Idaho Inc.
1 A.Yes. However, in the COSS I offer here, we have seasonalized
2 costs. While this formal seasonal estimation does not eliminate
3 the need for judgment in designing rates, it does nevertheless
4 give a good initial indication of seasonal cost differentiation, and
5 a rate objective to move toward over time.
6 POSSIBLE SUMMER INITIAL LOW-COST RATE BLOCK
7 a.In your testimony above, you referred to a possible "initial
8 summer consumption block" within a seasonal rate structure.
9 What do you mean by this?
10 A.My critique of inverted block rates pertains to the diffculty and
11 potential confusion associated with multiple blocks that are
12 designed to cover large consumption increments, for example as
13 in the case of base blocks, shoulder blocks and peak usage
14 blocks. In such instances, it is not possible to adequately define
15 these blocks within a cost of service study.
16 However, there are certainly reasons that a noncost-based
17 initial low block rate can be considered for purposes of assisting
18 in keeping the annual costs of small usage customers to a
19 minimum. We have begun attempting to develop the type of bil
20 frequency analysis necessary to estimate a reasonable size for
21 this initial summer block. Due to the need to gather additional
22
23
data and perform statistical analyses, I have not included an
exact initial block proposal here. We anticipate being able to
Peseau,Oi 8
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
a.
A.
a.
A.
schedules, as well as the summary cost of service rates for
seasonal usage, as well as customer costs. The last 2 lines of
each page of the schedule, "Existing Revenue" and "Percent
Change from Current", show the full cost of service rates and the
change in the present rates necessary to achieve cost of service
rates. Again, I do not recommend movement to full cost of
service. However, I use the cost and present rate information
shown on Schedule 1 to reach the rate design recommendations
that i make in the following section of my testimony.
What does schedule 2 show?
The 2 page Schedule 2 provides the overall summary results of
the COSS. The column "Total Amount" on pages 1 and 2 show
the aggregate amounts of operating expenses and rate base
related data necessary to adjust the period ending July 31, 2004
figures to May 31, 2005. The remaining columns summarize the
steps of the service component analysis by breaking these total
rate year balances into volume, base demand, excess maximum
day, excess maximum hour, customer related O&M, customer
meters and services and fire protection.
What is the next step in your COSS?
The next step is shown in Schedule 3. This schedule provides
the actual allocation of functionalized costs. A common allocation
method, and one recognized by this Commission, is the "Base-
Peseau, Oí 10
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10 a.
11 A.
12
13
14
15
16
17
18
19
20 a.
21 A.
22
23
schedules, as well as the summary cost of service rates for
seasonal usage, as well as customer costs. The last 2 lines of
each page of the schedule, "Existing Revenue" and "Percent
Change from Current", show the full cost of service rates and the
change in the present rates necessary to achieve cost of service
rates. Again, I do not recommend movement to full cost of
service. However, I use the cost and present rate information
shown on Schedule 1 to reach the rate design recommendations
that I make in the following section of my testimony.
What does schedule 2 show?
The 2 page Schedule 2 provides the overall summary results of
the COSS. The column "Total Amount" on pages 1 and 2 show
the aggregate amounts of operating expenses and rate base
related data necessary to adjust the period ending July 31, 2004
figures to May 31, 2005. The remaining columns summarize the
steps of the service component analysis by breaking these total
rate year balances into volume, base demand, excess maximum
day, excess maximum hour, customer related O&M, customer
meters and services and fire protection.
What is the next step in your COSS?
The next step is shown in Schedule 3. This schedule provides
the actual allocation of functionalized costs. A common allocation
method, and one recognized by this Commission, is the "Base-
Peseau, Di 10
United Water Idaho Inc.
1
2
3
4 a.
5 A.
6
7
8
9
10
11
12 a.
13 A.
14
15
16
17
18 a.
19 A.
20
21
22
Extra Capacity Method." This method separates total costs into
the components of base cost, extra capacity cost, customer cost
and fire protection costs.
What are "base costs" in the base-extra capacity method?
Base costs represent those costs incurred by the Company for
average, flat or base load levels of water production and
consumption by customers. Base costs represent a form of
"optimal system" costs as they are the costs of a system utilized
at a 100% system load factor that requires no additional peaking
facilties or other capacity costs. Base costs are those O&M and
capital costs for serving customers at a constant annual rate.
What are "extra capacity" costs?
As the name implies, extra capacity costs are those O&M and
capital costs that are over and above the base costs. They are
costs for meeting maximum peak demand in excess of average
demand and include supply, treatment, pumping and distribution
facilties costs.
What are customer costs?
As in most utilty functions, water system customer costs are
those costs incurred by the Company to provide service to
customers independent of the actual level and rate of water
consumption. In the present study these costs include the three
Peseau, Oi 11
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9 o.
10
11
12 A.
13
14
15
16
17
18
19 o.
20 A.
21
22 o.
23
24 A.
25
26
functions: customer commercial, customer meters and customer
services. The,AWWA Manual M1 defines customer costs as:
Costs directly associated with serving customers,
irrespective of the amount of water use. Such costs generally
include meter reading, biling, accounting, and collecting
expense, and maintenance and capital costs related to meters
and associated services. (page 324)
Are you aware that the commission staff has recently proposed
that customer costs for electric utilties be defined more
narrowly?
Yes. However, for United's water system, the above definition
should continue to be used for cost of service analysis. All
categories of the customer service above are independent of
water use. These services are sized initially for customers and
do not vary by annual or seasonal demands. Allocating any of
these fixed costs to the commodity portion of seasonal rates
would distort the usage sensitive water rate.
What are fire protection costs?
Fire protection costs include the O&M and capital costs of fire
hydrants.
How did you apply the base-extra capacity method to derive the
costs associated with these components?
The base-extra capacity method formally estimates the base or
average demand system costs, the excess maximum day
system demand costs and the maximum hour system demand
Peseau, Di 12
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15 a.
16 A.
17
18
19
20
21
22
23
costs. The method recognizes that extra costs are incurred for
meeting maximum day demands over average system demand,
and that even greater costs are incurred for facilities required to
meet maximum peak hour demands. Accordingly, the base-
extra capacity method allocates the total costs of supply,
pumping, treatment, T&D, customer, fire protection, general plant
and intangibles on the basis of average and peak demand. The
actual allocations are made from calculated "factors" or
allocators. The results of this step of allocating to the service
components for the period ending May 31, 2005 are shown in
Schedule 3. Schedule 4 of my exhibit provides the details of the
derivation of these factors. Schedule 4 also provides the
derivation of all other component, function and seasonal
allocators.
What do schedules 5-13 show?
Schedules 5-13 provide detailed account information that breaks
costs into functions. The functional categories used the COSS
are:
1.Intangibles
2.Source of supply
3.Pumping plant
4.Water treatment
5.Transmission and distribution
Peseau, Oi 13
United Water Idaho Inc.
1 6.Customer meters and service
2 7.Fire protection
3
4
8.General plant
a.What does schedule 14 show?
5 A.Schedule 14 provides rate year pro forma customer and billng
6 information by meter size and revenue count at existing rates
7 and equivalent meter counts. This information is used to derive
8 unit customer costs from aggregate customer costs.
9
10
a.What does schedule 15 show?
A.Schedule 15 reports private fire service information similar to that
11 presented in Schedule 14.
12 SEASONALIZED COST OF SERVICE
13
14
a.What is the issue you address with respect to cost
seasonalization?
15 A.Although United has had seasonal water rates in effect for some
16
17
time, the degree of the winter/summer rate differentiation has not
before been based on the cost of service study. The issue i now
18 address is the formal estimating of the Company's seasonal cost
19 differences in the context of the COSS. It is not my intent to
20 argue that seasonal rates should be set equal to seasonal cost
differences but rather that the actual cost differences be21
22 recognized as one important variable in setting final commodity
23 rates in this case.
Peseau,Oi 14
United Water Idaho Inc.
1 a.
2
3 A.
4
5
6
7
8
9
10
11
12 a.
13 A.
14
15
16
17
18
19
20
21
22
What does your COSS analysis show with regard to United's
seasonal cost differences?
As in all cost of service analyses, there is no single "correct "
method to seasonalize costs. Judgment is required. I develop
two alternative methods to seasonalize cost of service to provide
the Commission insight into the new analyses and give a
reasonable range of discretion in setting seasonal rates if it
chooses to order seasonal rates.
As developed below the two analyses find that the seasonal
rate spread based on cost of service falls in the range of 25-
70%.
Please explain the seasonal cost analysis.
The seasonal cost study begins with the identification of the
appropriate annual functional and component cost categories
that are usage sensitive, and therefore, eligible for
seasonalization. The COSS identifies volumetric, base demand,
excess maximum day and excess maximum hour costs as usage
sensitive. The annual dollar amounts for these cost categories
are summarized in Schedule 1. The total of these usage
sensitive costs in rate year May 31,2005 is $26,636,100, a very
significant percentage of the total revenue requirement of $38.1
millon.
Peseau, Dj 15
United Water Idaho Inc.
1 The various categories identified above each has a unique
2 seasonal characteristic and must be separately estimated. For
3 example, volumetric costs vary directly with seasonal usage.
4 Cost of chemicals is such an example. The more water
5
6
produced, the more chemical used. Purchased water costs also
vary directly with the amount purchased. Base capacity costs,
7 which are incurred to meet annual average demand also vary
8 directly by seasonal usage and therefore should be allocated by
9 respective seasonal winter/summer usages.
10 The peak or excess maximum demand costs, however, vary
11 disproportionately higher during summer months. Seasonal
12
13
allocators for the excess maximum day and excess maximum
hour demands therefore require considerably more analysis.
14 a.How does the COSS develop seasonal cost allocators for the
15 two categories excess maximum day and excess maximum
16 hour?
17 A.To accomplish this, average monthly usage, maximum day
18 usage and maximum hour usage is computed for each month of
19 the test year. From these data twelve monthly day and hour
20 "excesses" over the respective average monthly demands are
21 calculated.
Peseau, Di 16
United Water Idaho Inc.
1
2
3
4 a.
5 A.
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
I computed the two alternative seasonal cost allocators by
using two different definitions of summer and winter peak
consumption.
Please explain,
For the first seasonal allocator, I computed the maximum excess
maximum day and hour figures for the single highest peak
excess for each season. I then compared the summer single
month excess demand with the winter single month excess
demand and used the relative differences to seasonalize the
costs. The resulting seasonal allocations derived are:
Seasonal Costs AllocatedSummer Winter
Excess Day
Excess Hour
77.4%
70.0%
22.6%
30.0%
Schedule 4 provides the detailed calculations.
A second alternative seasonal allocator is developed from
the same excess demand data. However, for this second allocator,
I summed, by season, all months of positive excess demand and
used the sum of the total month summer excess demands to the
sum of the total monthly winter demands to calculate the allocator.
This second allocator results in the following cost allocations:
Seasonal Costs AllocatedSummer Winter
Excess Day
Excess Hour
87.8%
87.9%
12.2%
12.1%
Peseau, Di 17
United Water Idaho Inc.
1
2
3 a.
4
5
6 A.
7
8
9
10
11
12
13
14
15
16
17 a.
18 A.
19
20
21
22
How are the seasonal excess demand allocators combined with
the volumetric and base capacity cost allocators to reach a
seasonalization of all these costs?
This step is shown for each of the two alternative excess
demand allocators in Schedule 1. As shown in the now entitled
"Total," the total seasonal costs allocated to the winter and
summer seasons are $8,172,948 and $18,463,152 respectively
for the single excess peak alternative allocator and $6,555,866
and $20,080,233 for the "sum of all months" excess demand
allocator.
On these same tables, the columns designated as winter
and summer show the actual amounts of each category, that is
volumetric, base capacity, excess maximum day and excess
maximum hour capacity allocations to season.
How are the cost of service-based rate differentials determined?
The "Unit Cost" row on Schedule 1 reports the winter and
summer unit rates required to exactly conform to cost of service.
The unit rates under the single peak excess demand allocator
are 1.1073 and 1.389 for winter and summer respectively. This
is a 25% seasonal rate differential.
Peseau, Di 18
United Water Idaho Inc.
1 a.
2
3
4 A.
5
6
7
8
9
10
11
12 a.
13
14
15 A.
16
17
18
19
20
21
22
Do you propose that the commission adopt an "either/ot' policy
on the choice between the 25% and 70% seasqnal cost
differences?
No. As with aU cost of service studies, this COSS serves as a
check on the reasonableness of existing rates and provides an
indication of the possible direction of movement in the future.
This Commission has for decades used cost of service studies
as a point of reference and a point of departure. There are, of
course, numerous other considerations and factors that weigh on
the Commission in setting rates and rate design that are fair,
reasonable and in the public interest.
Do you have recommendations for the commission in regard to
the degree of cost-based seasonalization to adopt in these
proceedings?
Yes. First, as a point of reference, the present 25%
winter/summer commodity rate differential now in place appears
reasonable as it falls in the lower end ofthe range derived in the
COSS. Second, as an indication of direction, the range of
seasonal differentiation in the COSS suggests that the present
25% differential perhaps should not be reduced in this case and;
over time, the Commission may look to broader seasonalization
should future studies support this.
Peseau, Oi 19
United Water Idaho Inc.
1 am in these proceedings very comfortable in
2
3
recommending that the present 25% seasonal rate spread be
continued. A corresponding and very important aspect of
4 continuing with the 25% seasonal rate differential is that the
5 public already has faced this differential for many years and,
6 since it also is supported by the COSS, would not require
7 considerable education attached to making major changes to the
8 present differentiaL. This issue is, to a large extent also a rate
9 design issue and is discussed in the context of complete rate
10 design below.
11 RATE DESIGN
12 a.What is your overall rate design proposal?
13 A.i recommend that the Commission adopt a rate design that:
14
15
16
17
18
19
20
21
22
23
24
25
26
1 . Raises private fire protection rates at the overage
percentage increase in revenue requirement of 21.5%.
2. Raises customer charges by an approximate 36% over
present levels.
3. Adopts seasonal commodity rates that have a 25%
winter/summer differential.
4. Maintains the present distinction among customers on
the basis of meter size.
a.Why do you recommend a uniform rate increase for private fire
27 protection equal to the average system rate increase?
28 A.As this class is not metered, there is a lack of comparable known
29 and measurable data for private fire protection that is available
Peseau, Oi 20
United Water Idaho Inc.
1 for the general service class. Rather than make additional
2 assumptions, i recommend the uniform average system rate
3 increase for this class.
4 a.Why do you recommend that customer charges be raised by
5 36%?
6 A.Again, I begin with references to the COSS. Schedule 1
discussed above not only reports the COSS results on seasonal7
8 costs, but also shows a companson of existing customer costs to
9 present customer charges. For example, page 1 and page 2 of
10 Schedule 1 indicates that to move customer charges to full cost
11 of service, revenues from this rate component would have to be
12 raised from $7.3 milion to $11 milion. And, while i know that
13 considering the raising of customer charges is typically
14 unpopular, the COSS results show that the present customer
15 charges would need to be raised about 51 % if brought 100% in
16 line with customer costs. I do not recommend this.
17 In this case i recommend that customer charges be raised to
18 a level that would approximately move one-half the distance from
19 existing to cost of service. Raising the present customer charge
20 by the average of the overall requested rate increase, 21.5%,
21 and the COSS level of 51%, for an approximate 36% increase
22 would achieve this objective.
Peseau.Oi 21
United Water Idaho Inc.
1 Q.
2
3 A.
4
5
6
7
8
9
10 Q.
11
12 A.
13
14
15
16
17
18
19
20 Q.
21
22
What is the outcome of not moving customer charges a
significant distance toward cost of service?
Any and all costs not recovered in customer charges must be
collected in commodity rates that are already well above rates
that equal cost of service. In this case, both summer and winter
commodity rates are considerably higher than justified on a cost
of service basis. I believe that an increase of 36% in customer
charges fairly balances the goals of gradualism and cost-based
rates.
Does raising the customer charges "mute" the seasonal
commodity rate price signals?
No. Commodity rate price signals should reflect cost causation.
At proposed rates, customer charges wil continue to be
approximately $1.1 milion below cost of service. Therefore, far
from having "muted" commodity price signals, proposed
commodity rates recover about $1.1 millon above cost of
service. Again, i do not propose a move to full cost of service
now, or probably anytime in the near future, but that some
substantial increase be made in this case.
Do you have other reasons for recommending that the
winter/summer commodity rate differential be kept at 25%, which
is at the lower end of your range?
Peseau, Oi 22
United Water Idaho Inc.
1 A.
2
3
4
5
6
7
8
9 a.
10
11
12 A.
13
14
15
16
17
18
19
20
21 a.
A.22
23
Yes. As I discussed above the 25% seasonal differential has
been in place for some time. But in addition, this Commission
has favored gradual implementation of seasonal rates. For
example, in the face of a broad range of seasonal cost
differences in the recent Idaho Power Company general rate
case, this Commission adopted a low end of a seasonal cost
differential range of 12.5%. The present United seasonal
commodity rate differential is twice that adopted for Idaho Power.
How might the issue of customers that have flat monthly loads
be addressed with regard to the issue of summer bils being
higher than for the same uses in the winter?
This is the "baths costing more in the summer" issue I referred to
in the introduction to my testimony. While seasonal rates
obviously cause different levels of biling for the same
consumption occurring in different months, customers need to be
made aware that there are nevertheless benefits of seasonal
rates. For a customer whose consumption is relatively "flat" or
level over the year, demonstrations can be made that seasonal
rates result in his paying lower annual amounts than in the
absence of seasonal rates.
Please explain.
The following table demonstrates that level consumption under
the seasonal rates proposed in this case reduce annual
Peseau. Di 23
United Water Idaho Inc.
1 customers bils. The table compares the annual bils of a
2 customer using the Company average monthly consumption of
3 10 CCF per month. Here it is assumed that this customer uses
4
7
this 10 CCF in every month of the year:
Seasonal
, Use Flat Rate Rate Seasonal
Month (CCF))$/CCF $/CCF Flat Bil Bil
January 10 1.29 1.11 $12.90 $11.10
February 10 1.29 1.11 $12.90 $11.10
March 10 1.29 1.11 $12.90 $11.10
April 10 1.29 1.11 $12.90 $11.10
May 10 1.29 1.39 $12.90 $13.90
June 10 1.29 1.39 $12.90 $13.90
July 10 1.29 1.39 $12.90 $13.90
August 10 1.29 1.39 $12.90 $13.90
September 10 1.29 1.39 $12.90 $13.90
October 10 1.29 1.11 $12.90 $11.10
November 10 1.29 1.11 $12.90 $11.10
December 10 1.29 1.11 $12.90 $11.10
Total $154.80 $147.20
The COSS estimates that the average annual
commodity rate in this case is $1.29 per CCF.And, as shown in
5
6
8 Schedule 1, page 1, the proposed seasonal commodity rates in
9 this case are $1.11 and $1.39 per CCF for the winter and
10 summer seasons, respectively. The table prices out the level
11 consumption of 10 CCF under the average annual versus the
12 seasonal rates for this customer. In this instance, the customer
13 saves $7.60 per year, or over 5% with the seasonal rates. Thus
14 while this customer may pay more for a bath in the summer than
15
16
in the winter, he pays less for the two over the course of the
year.
Peseau, Di 24
United Water Idaho Inc.
1 Q.Does this conclude your direct testimony?
2 A.Yes.
Peseau, Oi 25
United Water Idaho Inc.
Dean 1. Miler
McDEVITT & MILER LLP
420 West Banock Street
P.O. Box 2564-83701
Boise,ID 83702
Tel: [phone]
Fax: [phone]
joeØ)mcdevitt-miller.com
Ida Pubj¡, '. ,.;¡ties Commission
Of r-fi0f¡ SecretaryRECEIVED
NOV 30 200
Bose, Idaho
Attorneys for Applicant
BEFORE THE IDAHO PUBLIC UTIITIS COMMSSION
IN THE MATTER OF THE APPLICATION
OF UNITED WATER IDAHO INC. FOR
AUTORITY TO INCREASE ITS RATES Case No. UW-W-04-4
AND CHAGES FOR WATER SERVICE IN
TI STATE OF IDAHO
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ATTACHMENT 1 TO THE
DIRECT TESTIONY OF DENNS E. PESEAU
STATEMENT OF OCCUPATIONAL AND
EDUCATIONAL HISTORY AND QUALIFICATIONS
DENNIS E. PESEAU
Dr. Peseau has conducted economic and financial studies for
regulated industries for the past thirt years. In 1972, he was employed by
Southern California Edison Company as Associate Economic Analyst, and later
as Economic Analyst. His responsibilties included review of financial testimony,
incremental cost studies, rate design, econometric estimation of, demand
elasticities and various areas in the field of energy and economic growth. Also,
he was asked by Edison Electrical Institute to study and evaluate several
prominent energy models as. part of the Ad Hoc Committee on Economic Growth
and Energy Pricing.
From 1974 to 1978, Dr. Peseau was employed by the Public Utiity
Commissioner of Oregon as Senior Economist. There he conducted a number of
economic and financial studies and prepared testimony pertaining to public
utilties.
In 1978 Dr. Peseau established the Northwest offce of Zinder
Companies, Inc. He has since submitted testimony on economic and financial
matters before state regulatory commissions in Alaska, California, Idaho,
Marylan~, Minnesota, Montana, Nevada, Washington, Wyoming, the District of
Columbia, the Bonnevile Power Administration and the Public Utilties Board of
Alberta on over one hundred occasions. He has conducted marginal cost and
rate design studies and prepared testimony on these matters in Alaska,
California, Idaho, Maryland, Minnesota, Nevada, Oregon, Washington and in the
District of Columbia. He has also conducted cost and rate studies regarding
PURPA issues in the states of Alaska, California, Idaho, Montana, Nevada, New
York, Washington, and Washington, D.C.
Peseau,Di
Attachment No. i
Page 1 of 2
Dr. Peseau holds the B.A., M.A. and Ph.D. degrees in economics.
He has co-authored a book in the field of industrial organization
entiled, Size. Profis and Executive Compensation in the Large Corporation,
which devotes a chapter to regulated industries.
Dr. Peseau has published articles in the following professional
journals: Review of Economics and Statistics, Atlantic Economic Journal,
Journal of Financial Management, and Journal of Regional Science. His articles
have been read before the Econometric Society, the Western Economic
Association, the Financial Management Association, the Regional Science
Association and universities in the United Kingdom as well as in the United
States.
He has guest lectured on marginal costing methods in seminars in
New Jersey and California for the Center of Professional Advancement. He has
also guest lectured on cost of capital for the public utiity industry before the
Pacific Coast Gas and Electric Association, and for the Executive Seminar at the
Colgate Darden Graduate School of Business, University of Virginia.
Dr. Peseau and his firm have participated with and been members of
the American Economic Association, the American Financial Association, the
Western Economic Association, the Atlantic Economic Association and the
Financial Management Association. He was formerly a member of the Staff
Subcommittee on Economics of the National Association of Regulatory Utilty
Commissioners.
Dr. Peseau has been President of Utilty Resources, Inc. since 1985.
Peseau.Di
Attachment No. i
Page 2 of 2
Dean J. Miler
McDEVIT & MILLE LL
420 West Banock Street
P.O. Box 2564-83701
Boise, ID 83702
Tel: [phone]
Fax: [phone]
joe(gmcdevitt-miler.com
Attorneys for Applicant
BEFORE THE IDAHO PUBLIC UTILITIE COMMISSION
IN THE MA ITR OF THE APPLICATION
OF UNITED WATER IDAHO INC. FOR
AUTHORITY TO INCRASE ITS RATE Case No. UW-W-04-04
AND CHAGES FOR WATER SERVICE IN
TH STATE OF IDAHO
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
EXHIBIT 14 TO THE
DIRECT TESTIMONY OF DENNIS E. PESEAU
United Water Idaho
Cost of Service Study
Seasonallzation and Comparison to Current Rates
Alloation of Nel Revenue Reulremenllo General Wat Serice and Fire Proction
General General Priate
Water Water Public Fire Public Fire Fire Prite Fire
Net Revenue Ser Service Serv Servic Servce Servce
Cost Component Requirement Perce Dolars Percnt Dolars Pernt Daars
Volumetric 4,706,249 99,500%4,682,718 0,435%20,472 0.065%3,059
Base Çaciy Cost 9,250,852 99,50%9,20,598 0.435%40,241 0,06%6,013
Excess Maximum Day Cot 9,158,346 95,699%8,764,407 1.971%180,510 2,330%213,30
Excess Maximum Hour Cost 4,381,129 90,94%3,984,377 4,595%201,296 4,461%195,58
Customr Expense 3,821,726 98.194%3,752,687 1,806%69,039
Custoer Meiers end Service 6,734,929 6,734,929
Fire Hydrants 88,281 100.00%88,281
Total Cost of Servic 38,141,514 37,123,716 530,800 486,998
Summary Rales or Revenues by Component
Base on Ralio 01 Maximum Excess Demand by Season
Priva Fire
Coponent Winter Summer Custoer Proteon Totl
Volumetri 1,685,778 2,996,940 20,472 3,059 4,706,249
Base Capciy 3,313,65 5,890,943 40,241 6,13 9,250,852
Exce Maximum Day Capaci 1,978,517 6,785,889 180,510 213,30 9,158,346
Excess Maximum Hour Capaty 1,194,997 2,789,38 201,296 195,456 4,381,129
Custr Expense 3,752,687 69,039 3,821.726
Cuslomr Meters and Serves '6.734,929 6,734,929
Public Fire Proteon 88,281 88,281
Private Firr Proecn 0
Total 8,172,948 18,63,152 11,018,17 486,998 38,141,514
Usage (CCF)7.380,841 13.290,982
Unit Costs ($ per CCF)1,1073 1,389
Existing Revenue ( $/CCF or $)0,9825 1,2281 7,296,820 518,175 31,389,327
Percent Change fro Current 12,704%13,114%51,003%-6,017%21.511%
Ratios of Summer Commodity Rate to Winter Rate 1,2545151
_fl 14e-No,__u___ltl,P.lci2
United Water Idaho
Cost of Service Study
Seasonallzation and Comparison to Current Rates
Summar Rates or Revenues by Compoent
Base on Ratio of Sum of Monthly Exce Demands by Seasn
Compoent Winler
1,685,778
3.313,655
1,072,492
483,94
Volumetric
Base Capacity
Excess Maximum Day Capaciy
Exces Maximum Hour Capacity
Customer Expense
Customer Meters and Seices
Public Fire Protection
Private Flrr Protecion
Total
Summer
2,996,940
5,890,943
7,691,914
3,500,437
Custmer
20,472
40,241
180,510
201,296
3,752,687
6,734,929
88,281
Usage (CCF)
6,555,866 20,080,233 11,018,417
7,380,841 13,290,982
Unit Costs ($ per CCF)
Existing Revenue ( $/CCF or $)
Percnt Change fr Current
0,8882 1.511
Priata Fire
Protaclon
3,059
6,013
213,430
195,56
69,039
486,998
Totl
4,706,249
9,250,852
9,158,346
4,381,129
3,821,726
6,734,929
88,281
°
38,141.514
0,9825 1,2281 7,296,820 518,175 31,389,327
21,511%-9,595% 23,021% 51,00% -6,017%
Ratis of Summer Commodit Rate to Winter Rate 1,700934
&l No. 14CaNo,_P_,Un__1,P.2012
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United Water Idaho
Cost of Service
Allocation and 8easonalization Factors
Servic Compont Anocto
Custome FweDeptionNsmeVolumeBaseMax Dey Ma Hour Cus Ei Servce Hydn..To"l
Volumeet V1 100,000%100,000%
Base 01 100,000%100,00%
Base.MaDay 02 50,251%49,749%100,000
Base. Me. Dey. Ma Hour 03 28,351%28.068%43,581%100.000%
O&M - So of Supply ES 65,00%17,58%17,412%100,00%
O&M . Wate Tretment EW 63,000%18,593%18.407%100,00
O&M.T&D ET 20.00 22,681%22,454%34,864%100.000%
Customr O&M C1 n,OO%23,00%100,00%
Customr Services C2 100,00%100,00%
Customr Meter C3 0.00%
Fire Hydran"F1 100.00 100.00%
Plant in Seric P1 0,000%27,451%27.176%22.222%0,00%22,646%0,505%100.00%
Payrol Allotor L1 25,874%10,957%10,848%7,638%34,203%10,217%0.262%100.000
O&M less Gel. Intagible, Dep & Am E1 31,943%11.574%11,458%5,515%30292%9,048%0,170%100.000
O&M les Depr and Amoriztion E2 30,356%13,771%13,633%6.498%24,651%10.912%0,180%100,00
Ra Base RB 0,443%3U168%30,758%15,265%0,36%21,774%0.332%100,00
Payrol Alloator 2 4 6 7 8
Intangibes °
Sourc of Supply 545,355 ES 354,481 95,917 94,958 0 0 0
Pumpng Plant °
Water Tretment 274,168 EW 172,726 50.976 50,466 0 0 0 °
Transmssion & Distbution 537,427 ET 107,485 121,895 120,676 187,371 0 0 °
Mele and Serces 1,089,626 Cl 0 0 0 °83,012 250,614 0
Flre ProteCton 6,437 F1 °0 °0 0 °6,437
Generl 935,126 241,954 102,466 101,441 71,429 319,644 95,53 2,454
Total 3,388,139 878,64 371,253 367,541 258,799 1,158,856 346,152 8,892
Percet 0.258739743 0,109574398 0,10878682 0,07638395 0,3420332 0,10216576 0,0026243
MonUy Aveage and Maximum Demnd
Ma. Hr.Max Max Day-
Month Ma. Hour (GPM Av ,De
98,823.89 31 38,549,28 29,465.76
97,372,25 30 37,097,64 19,527.51
68,207,11 31 7,932,49 8,742,78
45,205,45 30 0.00 0,00
24,734,22 31 0,00 0.00
24,555:11 31 0,00 0,00
24,719,50 29 0,00 0,00
34,002.16 31 0,00 0,00
80,220,67 30 19,946,06 8,182,40Ma~101,98,n 31 41,712.15 16,863,80Jun-106,833,00 30 46,558,39 25,744.47Ju~98,008,28 31 37,733,68 29.985.87
Max 106,833,00 60,274,61 46,558,39 29,985,87
AYg 30,288,75
ExhlltN..14Ci.. No, l/01
Ptu, Unlld Wi..
So_Ie 4, Pagel of2
United Water Idaho
Cost of Service
Allocation and Seasonalization Factors
Units
Millio Gallons pe DayPert
General
Water
Servic '
43.616
99,50%
Prte FlraPrecton
0,028
0.06%
Seasonal AUocaUon Fact
Raos of Single Meximum Seosl Ei Deand
Exce Max Day Amt Pornt
Winter 8,742.78 22,574%
Summer 29,98,87 77426%
38,728.65
Exc Max Hor
Winter 19,94,06 29,992%
Summer 46,558,39 70,008%
66,504,44
Ratios of Seasol Sum of Monhly PoslI Exces Deands
Winte 16.925,18 12,237%
Summer 121,387,41 87,763%
138,312,60
Exces Max Hour
Winter 27,878,55 12,146%
Summer 201,651.12 87,85%
229,529.67
Stlk:. Alloca Flllor
Component
Annual Consummptio
Maximum Day Demad
Maximum Hour Demand
Number of Bills
Public Fire
Protelon
0,191
0,435%
Milios Gallons per Day 86,795 1,080 1,080
Excess Max Day 43.180 0.889 1,052
Percent 95.699%1.971%2,330%
Millions Gallos por Day 153,840 6,460 6,460
Exces Max Hour 110,660 5.591 5,428
90,944%4,596%4.461%
450,067 8,280
98,194%0,000%1,80%
Total
43,835
100,00%
88.955
45,120
100.000%
166.80
121,679
100,00%
458,347
100,000%
Ex_No. 14C..No,--
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14
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30
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1
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0
Or
a
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n
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7
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7
30
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a
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34
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To
t
a
l

D
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a
t

M
a

3
1
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2
0
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5
No
t
e
:

A
l
l
o
c
e
d

e
a
s
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d

o
n

N
e

P
l
a
n
t

(

P
I
S
-
I
A
e
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d
v
a
n
c
e
)
Un
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t
e
d

W
a
t
e
r

I
d
a
h
o
Co
s
t

o
f

s
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r
v
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c
e

S
t
u
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y
Tw
e
l
v
e

M
o
n
t
h
s

E
n
d
e
d

M
a
y

3
1
,

2
0
0
5
Fu
n
c
t
l
o
n
a
l
i
z
a
t
l
o
n

o
f

N
e
t

D
F
I
T
(A
)
(8
)
(e
)
3,
2
2
0
2,
1
1
5,
7
7
9
1,
0
3
2
45
8
4
36
,
1
3
0
11
8
.
9
7
3
29
7
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3
4
11
7
.
2
9
8
8,
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1.
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30
,
5
2
8
4,
0
8
8
6.
5
2
3.
8
4
4.
6
9
5
79
,
2
1
0
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0
3
2
.
51
.
2
4
8
(D
)
3,2
2
0
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l
(G
I
(H
I
(I
I
(J
)
(K
)
2,
6
4
4
5,
7
7
9
1,0
3
2
45
,
8
4
0
36
,
1
3
0
11
6
,
9
7
3
29
7
,
3
4
2
11
7
,
2
9
8
8,
9
4
6
1,5
9
8
30
,
5
2
8
4,
0
8
6
6,
5
2
9
3,
8
4
3
4,
6
9
5
79
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2
1
0
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3
2
51
,
2
4
6
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6
8
5
.
9
1
0

,

4
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7
2

2
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5
6
9
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5
9
2

.

2
,
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0
3
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2
5

4
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2
,
7
3
9
,
4
5
6
3
0
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5
4

1
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0
4
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Ed
"

No

14
c.
.
N
o
l
J
..
.

U
n

W
I
_.
.
1
0
,
.
.
.
.
.
.
(A
)
De
r
n
d

D
e
b
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t

a
t

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l
y

3
1
.

2
0
0
4
Al
l
o
a
t
r
30
1
.
1
0
Or
g
a
n
i
z
o
n
La
n
d

&

l
a
n
d

R
i
g
h
t
s
,

W
a
æ

R
I
g
h
t
s
,

5
0
S
30
2
0
De

l
a
k
a
w
o
d

W
e
l
l

l
e
a
s
30
3
0
La
n
d

&

L
a
n
d

R
I
h
t

W
a
l
e
r

T
r
e
l
m
n
t
la
n
d

&

l
a
d

R
I
h
i

T
r
a
n
s
m
i
s
s
i
o
n

a
n
d
30
3
4
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t
r
i
b
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t
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o
n
30
3
-
La
n
d

&

L
a
n
d

R
i
g
h
t
s

G
e
n
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r

P
l
a
t
30
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2
0
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r
c
t

&

I
m
p
r
o
m
e
n
t

-

5
0
S
30
-
3
0
si
r
r
a

&

I
m
p
r
o
m
e
n
t
s

-

W
t
r

T
r
t
St
c
t
u
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e

&

I
m
p
r
o
m
e
n
t
s
.

T
r
a
n
s

&
30
-
4
Di
s
t
r
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b
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t
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n
30
-
5
0
St
r
r
e
s

&

I
m
p
r
o
v
e
m
e
n
t
s

-

G
e
n
l

P
l
n
t
30
5
-
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l
n
g

&

i
m
p
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d
i
n
g

R
e
s
e
r
i
r
s

-

5
0
S
30
6
-
2
0
la
,

R
i
v

&

O
t
e
r

I
n
t
k
e
30
7
-
2
0
We
l
l
s

&

S
p
r
n
g
s
30
6
-
0
In
f
i
l
r
t
i
o
n

G
a
r
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e
s

&

T
u
n
n
e
30
9
-
2
0
SU
p
p
l
y

Ma
i
n
s

31
0
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2
0
Po

G
e
e
r
t
i
o
n

E
q
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p
m
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t
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w
r

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l
e
c
i
c

P
u
m
p
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n
g

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q
l
p
m
n
t
-
31
1
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2
0
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o
f

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u
p
p
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y
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_

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l

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p
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f

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w
r

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u
n
g

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q
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r
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n
s
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31
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4
0
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,
32
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3
0
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t
e

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r
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a
t
m
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t

e
q
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p
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l
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r

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t

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q
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p
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.

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e
b
r
n
e
s
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s
t
b
u
t
i
o

R
e
s
r
v
o
i
r
s

&

S
t
a
n
d
p
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p
e
33
0
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0
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e
d

T
a
n
k

P
a
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g
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a
n
s
.

&

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I
s
t
b
,

M
a
i
n
s

&

A
c
s
s
o
r
i
e
s

.
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7
0
5
2
%
33
1
-
4
Tr
a
n
s
,

&

D
l
s
l
b
.

M
a
i
n
s

&

A
c
o
r
e
s
4
10
0
.
7
5
8
1
2
5
(4
0
,
2
,
8
1
1
)
(5
4
.
6
2

(
3
,
1
4
2
,
3
8
2
)
(2
2
,
2
6
6
,
8
8
)
34
,
5
5
,
4
30
,
1
2
1
7
8
%
33
5
-
Hy
r
a
4
1,0
7
1
,
4
0
5
(5
7
.
7
8
9
1
(6
,
9
8
)
(9
8
,
7
6
0
)
39
8
,
8
9
0,
3
4
7
6
6
%
33
_
Be

P
r
n
t

D
e
v
c
e
4
.
.
0,
0
~
~
%
33
-
4
Ot
h
e
r

P
l
a
n
t

&

M
i
s
e
,

E
q
u
i
p
m
.

T
r
a
n
s
,

&

D
i
s
b
.
4
88
,
4
1
(1
,
9
4
0
)
86
,
5
0
1
0.
0
7
5
4
0
%
4 T
o
l
a
l
41
,
8
5
6
,
3
7
2
36
,
3
0
4
9
%
55
5
,
0
4
6
30
3
-
5
La
n
d

&

L
a
n
d

R
i
g
h
t
s

-

G
e
n
e
r
l

P
l
n
t
5
21
3
.
3
1
21
3
.
3
8
3
0,
1
8
5
%
30
4
-
5
St
c
t
t
e
S

a
n
d

I
m
p
r
e
m
e
t
s

-

G
e
n
e
r

P
l
a
n
t
5
3,1
9
3
.
_
(5
9
,
7
4
4
)
2.
5
9
.
9
4
2.
2
6
3
5
5
%
33
9
5
0
Ot
r

P
l
n
t

&

M
i
s
e
,

E
q
u
i
p
n
t

-

G
e
l

P
l
a
n
t
5
15
,
7
9
1
(2
,
5
5
4
)
13
,
2
4
4
0,
0
1
1
5
4
%
34
Of

F
u
r
i
t
r
e

a
n
d

E
q
u
i
p
n
l
5
18
4
,
5
7
(1
,
1
3
1
)
(5
6
,
9
2
7
)
11
9
.
5
2
1
0,
1
0
4
1
8
%
Ea
t
l
b
N
o
l
.
e-

N
o
,

u
w
_
_U
n
l
W
.
.
Sd
u
1

1
2
,

P
I

1

0
1
2
34

A
M

1

F
M

S
y
s
m

-

M
a
p
p
i
n
g
34
8
0
S

c
o
t
e
r

H
a
r
d
r
e

&

S
o
f
a
r
~
I
F
M
S
/
W
A
N
/
P
e
o
e
S
34
1
-
5

T
r
a
n
s
p
r
t
t
i
o
n

E
q
u
i
p
m
e
n
t
34
.
æ

S
t
r
e

E
q
u
i
p
m
e
n
t
34
.
æ

T
o
o

S
h
o
p

a
n

G
a
r
a
e

E
q
u
i
p
m
e
t
34
3
-
5
0

C
o
n
i
n
e
(

S
p
a
c
e

M
o
n
i
t
o
,

G
e
r
a
t
o
r
,

T
r
e
c
h

S
h
i
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l
34

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a
b
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r
y

E
q
u
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p
t
34
5
.
5
0

P
o
_

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p

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q
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t
p
m
t
34
5
.
5
0

P
o
r

O
p
a
t

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q
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t
p
m
e
n
t
34
1
.
5
0

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o
m
m
u
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c
s

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q
u
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p
m
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n
t
34
7
-
5

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i
s
c
l
a
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u

e
q
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p
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e
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-
5

O
t
e
r

T
a
n
g
i
b
l
e

P
r
r
t
34
8
-
5

M
a
s
t

P
l
a
n
33
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e
r
c
e
33
~

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e
t
e

a
n
d

M
è
e
r

I
n
s
l
l
a
t
i
o
n
s
~
C
u
s
t
e
r

i
n
f
o
n

S
y
t
e
m
Un
i
t
e
d

W
a
t
e
r

I
d
a
h
o
Co
s
t

o
f

S
e
r
v
l
c
e
S
t
u
d
y
Tw
e
l
v
e

M
o
n
t
h
s

E
n
d
e
d

M
a
y

3
1
.

2
0
0
5
Fu
n
ç
t
o
n
a
l
i
z
a
l
o
n

o
f

P
r
o
p
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r
t

T
a
x
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s
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S

a
l

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u
l
y

3
1
.

2
0
0
4

A
å
v

a
t

A
c
c
u
m

D
e
p
r

N
e
t

P
l
a
n
t

f
o
r
In
c
l
u
d
i
n
g

P
H
F
U

C
I
A
C

a
t

7
1
3
1
1
2
4

7
1
3
1
1
2
0
0
4

7
/
3
1
/
2
0
0
4

P
r
o
p
T
a
x

P
u
r
i
a
s

%

A
l
l
o
c
a
I
o
n
5
5
5
2
,
9
1
0

(
5
8
,
7
5
2
)

(
3
5
,
8
4
2
)

-
0
,
0
3
1
2
4
%
5
1
,
7
2
3
,
5
6
3

(
1
6
6
,
7
4
2
)

1
.
5
5
6
8
2
1

1
,
3
5
6
6
%
5
2
,
1
7
0
.
1
0
5

(
2
.
0
6
5
,
4
7
9
)

8
0
4
,
6
2
8

0
,
7
0
1
3
3
%
5
1
3
4
,
1
1
1

(
1
3
4
,
1
1
1
)

(
0
)

0
,
0
0
0
0
0
5
2
4
,
4
4
1

(
1
5
,
0
9
5
)

9
,
3
5
3

0
,
0
0
8
1
5
%
5
4
5
5
,
9
4
5

(
3
5
7
,
5
5
6
)

9
8
,
3
8
9

0
,
0
8
5
6
%
5
8
2
,
5
3

8
2
,
5
3
3

0
,
0
5
4
5
0
%
5
1
1
8
,
8
4

(
1
8
.
7
2
9
)

(
8
4
,
8
4
5
)

1
5
,
0
8
9

0
,
0
1
3
1
3
%
5
5
8
,
8
1
7

5
8
8
1
7

0
,
0
5
1
2
7
%
5
8
2
,
8
8
2

(
1
2
1
,
6
9
9
)

1
5
8
,
8
1
7
)

-
0
,
0
5
1
2
7
%
5
1
.
3
0
0
,
4
7

(
n
,
4
0
0
)

(
3
0
6
,
2
9
3
)

9
1
8
.
7
5
4

0
,
7
9
0
6
%
5
1
0
7
,
8
2
1

2
1
,
1
1
2

1
2
8
.
7
3
3

0
,
1
1
2
2
1
%
5
.

0
,
0
0
0
0
%
5
2
6
.
3
8
1

(
1
3
7
,
6
0
6
)

1
3
0
.
7
7
5

0
,
1
1
3
9
9
%
5
T
o
t
l

8
.
8
3
0
.
3
0
2

5
.
7
7
1
0
%

8
8
,
3
4
8
3
8
,
8
2
4
,
7
8
8

(
8
,
2
8
1
,
8
2
5
)

1
6
0
2
,
7
4
0
)

(
8
,
9
1
1
,
6
1
7
)

2
1
.
0
2
8
,
8
0
4

1
8
.
3
2
8
9
3
%
6
1
1
,
5
5
,
4
8

(
1
9
1
,
5
1
7
)

(
2
,
1
7
2
,
4
5
0
)

9
.
2
1
1
.
4
8
1

8
,
0
2
9
0
%
6
1
.
7
9
5
,
0
8
9

(
5
8
7
,
0
5
0
)

1
.
2
0
8
0
1
9

1
,
0
5
2
9
3
%
6
T
o
t
l

3
1
,
4
4
.
1
0
4

2
7
.
4
1
0
7
7

4
1
9
,
0
2
7
Gr
a
n
d

T
o
t

1
,
5
2
8
,
6
9
8
(5
4
4
,
8
2
)
54
.
8
2
6
23
,
0
3
9
,
0
5
4
(5
2
.
9
8
3
.
5
8
)
(7
,
0
7
2
,
3
3
7
)
(!
l
,
2
7
3
,
8
3
3
)
11
4
,
7
2
9
.
0
2
6
10
0
,
0
0
%
1,
5
2
8
,
8
9
Ex
l
b
l

No
.

1.
Ca
N
o
,
_
_.
.
_
W
I
__
1
2
,
.
.
2
0
1
2
Un
i
t
e
d

W
a
t
r

I
d
a
h
Co
s
t

o
f

S
e
r
v
i
c
e

S
t
u
d
y
Tw
e
l
v
e
.

M
o
n
t

E
n
d
d

M
a
y

3
1
.

2
0
0
5
Fu
n
ç
t
l
o
n
a
l
l
z
a
t
i
o
n

o
f

O
&
M

E
x
p
e
n
s
e
s
(D
)

(
E
)

(
0
1

(
H
I

0
)

I
J
)
So
u
r
c

o
f

P
u
m
p
i
n
g

W
a
t

T
r
a
n
s
m
i
8
s
i

M
e
t
r
s

a
n
d

F
i
r
e
__
_

O
p
e
r
a
t
n
g

E
x
p
e
n
s
e
s

a
t

J
u
l
y

3
1
,
2
0

A
l
l
o
c
t
o

T
o
t
l
s

I
n
t
a
n
g
i
b
l
e
s

S
U
P
"

P
l
a
n
t

T
r
e
t
m
e
n
t

&

D
i
s
t
b
u
t
o
n

S
e
r
v
c
e

P
r
o
t
e

G
e
n
e
r
a
l
Pa
y
r
U
t
o
O
&
M

C
o
s
t

Ty
p

1
&
2

3
,
1
5
5
,
5
8
4

5
0
7
.
9
2
3

2
5
5
.
3
5
0

5
0
.
5

1
.
0
1
4
,
8
3
6

5
,
9
9
6

8
7
0
.
9
4
1
Th
n
f
P
l
a
n

9
2
7
0
0

9
0
,
1
5
6

1
4
,
5
1
2

7
.
2
9

1
4
,
3
0
1

2
8
,
9
9

1
7
1

2
4
,
8
8
3
He
a
f
t
h

c
a
r
e

9
2
6
1
0
1
4
0

5
2
3
,
1
8
3

8
4
.
2
1
3

4
2
,
3
3
7

8
2
.
9
8

1
6
8
,
2
5
9

9
9
4

1
4
4
,
4
0
1
Pe
s
i
o
n

9
2
6
-
0
0

8
2
.
7
6
7

1
0
0
.
5
6
2

5
0
.
5
5

9
9
.
1
0
1

2
0
0
,
9
2
5

1
,
1
8
7

1
7
2
.
4
3
PE

9
2
6
1
0
5
1
1
0
6
/
1
1
0

6
1
4
.
8
4
7

9
8
,
9
6
6

4
9
.
7
5
3

m
,
5
'
l

1
9
7
,
7
3
5

1
,
1
6
8

1
8
9
,
6
9
Pa
y
l
l

Ov
a
r
h
s

9
2
2
-
0

(
8
5
9
,
7
9
5
)

(
1
3
8
,
3
9
3
)

(
6
9
,
5
7
5
)

(
1
3
6
,
3
8
1
)

(
2
7
6
,
1
0
)

(
1
.
6
3
4
)

(
2
3
7
.
3
0
)
Oe

E
a

R
e
f
r
e
n
l

C
o

A
m
o
r
t
a
t

9
2
6
-
5
9
0

(
p
o
r
t
)

1
5
2
,
2
0
8

1
5
2
.
2
0
Pu
r
c
a
s
e

W
a
t
e

6
0
2
,
(
0
0

1
0
7
,
7
8
8

1
0
7
.
7
8
8
Ta
n
k

P
a
i
n
t
g

A
m
r
t
l
i
l
d

6
7
2
-
0
0

3
,
_
Po
w
r

8
2
3
-

1
,
2
4
2
,
5
3
Am
o
r
t
z
a
t
o
n

o
f

D
e
a
m

P
o

6
2
3
-
Ch
e
i
c
a
l
s

6
4
1
-
0
Wa
t
e
r

Q
u

T
e
s
n
g

(
O
u
i
d
e

L
a
b

O
n
l
y
)

6
4
2
-
0
Ma
j
o
r

M
a
n
t
c
e
:

l
Y

l
e
v
l

V
e
r
y

L
o
!
!
U
U
1
1
1

V
a
r
i
o
u
s
Co
l
u
m
b
i
a

W
a
t
e
r

T
t
e
a
t
e
n
t

P
l
a
n
t

M
i
s
e

O
p
-

T
e
l
e
e
.
Wa
l

Q
u
l
i
t

T
e
s
t
n
g
,
N
a
t
l

G
a
o
o
t
e
r
Ut
i
U
e
s
s
e
n
l

A
l
a
n
n

-
.
l
I
r
i
n
g
.
S
a
n
i
o
n
Va
r
b
l
e

C
o

S
a
v
i
n
g
s

D
u
e

t
i

C
W
T

O
p
e
r
U
o
n
s
Tr
a
n
s
p
r
t
t
i

E
x
Cu
s
t
o
m
e

P
o
g
e
Ou
t
s
i
d
e

C
o
m
p
u
t
e
r
Ou
l
i
d
e

C
o
ø
c
(A
)
(B
)
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UNITED WATER IDAHO
Cost of Service Study
Summary Bil Analysis for Pro Forma Rate Year
THRU MAY 2005 RESIDENTIAL
i:quivaem
Meter and
Bills Servic Equivalenl
2005 Rended Custoni Revenue Multpl Mete Curre Rate
BILLS & CUSTS
MeIer 5IS"61,486 13,581 1 13,581 14,57
Size 314"264,239 47,373 1,1 52,110 14,57
1"34,798 5,800 1.4 8,120 19,19
1112"705 117 1.8 211 31.05
2"396 66 2,9 193 44.88
3"8 1 11 14 82.494.0 14 0 13126
O.0 21 0 252,63
S"0 29 0 381,2
Flat Rate Servic 269 45
Total 401,633 66,984
WATER USE USE DIST
Winter 4,601,552 34%0,9825
Summer 6999 377 66%1.2281
Total Use 13,600,929
COMMERCIAL
isiiia
Rendere Custors
BILLS & CUSTS
Meter 5/"2,984 497 1 497 14,57
Size 314"12,606 2,101 1.1 2,311 14,57
1"14,426 2,404 1.4 3,366 19,19
1112"8,991 1,499 1,6 2,697 31.05
2"8,06 1,343 2,9 3,896 44,68
3"606 101 11 1,112 S2,49
4"205 34 14 479 131,26
6.16 3 21 63 252,63
8"6 1 29 30 381,2
Flat Ra Service
Total 47,903 7,984
WATER USE USE DIST
Winter 2,751.251 40%0.9825
Summer 4,200567 60%1.2281
Total Use 6,951,818
PUBLIC AUTHORITY
isiiia
Rendered Customer
BILLS & CUSTS
Meter 5/8"9 2 1 2
Size 314"57 9 1,1 10
1"152 25 1,4 35
1112"105 18 1.6 32
2"202 34 2,9 98
3"6 1 11 11
4"0 14 0
6"0 21 0
6"0 29 0
Flat Rate Service
Total 531 8l
WATER USE USE DIST
Winter 28,039 24%
Summer 91038 76%
Total Use 119,076
EihlNo14c.No___,lJd_,
S_'4, Polof2
UNITED WATER IDAHO
Cost of Service Study
Summary Bil Analysis for Pro Forma Rate Year
OTAL ALL SECTORS
Tolal
Tolal Bills Cuslomen
BILLS & CUSTS
MeIer 5/8"84,479 14.080 1,230,856 1 14,080 14,57
Size 3/4"296,901 49.4l3 4,325,843 1,;54,432 14.57
1"49,376 8.229 947,53 1.4 11,521 19.19
11/2"9,801 1.634 30,326 1,8 2,940 31,05
2"8,661 1,443 388,699 2,9 4,186 44.88
3"620 103 51,141 11 1,137 82.49
4"205 34 26,922 14 479 131.28
6"18 3 4,524 21 63 252.63
8"6 1 2,371 29 30 381,2
Flal Rate Service 269 45 14604:0 0 54.29
Total 450,067 75,056 7,296,820 -88,867
WATER USE USE DIST
Winter 7,380,841 36%7,251,6n 0.9825
Summer 13290982 64%16,32265 1,2281
Total Use 20,671,823 23,574,332
Totl Revenue 30,871,152
_No,14CIHNil.P_UnW..S,_'4, PI i of i
Prite Fire Hydrants
3.
Subtotal
Public Fire Hydrants
6"
UNITED WATER IDAHO
Cost of Service Study
Pnvate Fire Protection Revenue at Current Rats, Bils and Equivalent Connections
170 1,00 170.00
4059,111 12.62%
690 4,00 2760,00 87.18%
Total Equivalent Conneions
8.280Total Prate Fire Proction Bßls
31659,111
NOTE: . Access to hydrants for street cleaning by Ada County DPW
ExhRNo.14
CHI No.IJ__.UnidWaI,
S_it 15, I'l 011
Dean J. Miler
McDEVm & MllER LLP
420 West Bannock Street
P.O. Box 2564-83701
Boise, ID 83702
Tel: [phone]
Fax: [phone]
joe (Smcdevitt -miler.com
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U¡ ill ¡ itS COhl'IISSION
Attorneys for Applicant
BEFORE THE IDAHO PUBLIC UTU..TIES COMMISSION
IN THE MA TIR OF THE APPLICATION
OF UNITED WATER IDAHO INC. FOR
AUTHORITY TO INCRESE ITS RATES Case No. UWI-W-04-04
AN CHAGES FOR WATER SERVICE IN
THE STATE OF IDAHO
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
REBUIT AL TESTIMONY OF DENNIS PESEAU
1 Q.Please state your namè and business address.
2 A.My name is Dennis E. Peseau. My business address is Suite 250,1500
3 Liberty Street, S.E., Salem, Oregon 97302.
4 Q.By whom and in what capacity are you employed?
5 A.I am President of Utilty Resources, Inc. My firm consults on a
6 number of economic, financial and engineering matters for various
7 private and public entities.
8 Q.On whose behalf are you testifying in this proceeding?
9 A.I am testifying on behalf of United Water Idaho Inc.
10 Q.Are you the same Dennis E. Peseau who prefied direct testimony in
11 these proceedings?
12 A.Yes.
13 Q.What is the purpose of your testimony?
14 A.As a follow-up to my direct testimony, I wil address rate design issues
15 discussed by Staff witness Sterling and Idaho Rivers United Witness
16 Wojcik. Additionally, United Water has asked me to analyze and
17 critique Staffs proposal to employ a 13-month average rate base.I
18 wil discuss the rate base issue first, followed by a discussion of rate
19 design issues,
20 Q.Please describe the Staff proposal to employ a 13-month average rate
21 base, as you understand it.
22 A.Staff calculates a rate base by averaging the monthly balances from
23 July 31, 2003 though July 31, 2004 for Plant in Service, Customer
D. Peseau, Re - 1
United Water Idaho Inc.
1 Advances and Contrbutions in Aid of Constrction. Except for
2 investment associated with the Columbia Water Treatment Plant
3 (CWTP) post-test year investments, though December 31,200, are
4 treated as if it occurred in the last month of the test year, and in
5 consequence, that investment is included in rate base at 1/13 of the
6 amount actually invested. (See Hars, Di. Pg 6).
7 Q.In contrast, how did the Company calculate its proposed rate base?
8 A.The Company employed an end of period or year end rate base using
9 the twelve-month period ended July 31,200. Normalizing and
10 anualizing adjustments were made to the test period and known and
11 measurable adjustments to revenue, operating expense and rate base
12 through May 31, 2005. (See Healy, Di. Pg 2). In addition, as
13 described in the testimony of Company Witness Wyatt at pp. 10-13, an
14 adjustment was made to reflect the impact on revenue and expense of
15 post test year plant additions, and to match revenue, expense and rate
16 base, in accordance with the policy stated by the Commission in Idaho
17 Power.
18 Q.Is the year end methodology proposed by the Company consistent with
19 prior Commission orders with respect to United Water and its
20 predecessor, Boise Water Corporation?
21 A.Yes. I have reviewed the previous four rate orders for United
22 Water/Boise Water, commencing in 1993 with Case No. BOI-W-93-1,
23 Order No. 25062. (See also, Case Nos. BOI-W-93-3, Order No.
D. Peseau, Re - 2
United Water Idaho Inc.
1 25640; UWI-W-97-6, Order No. 27617 and Case No. UWI-W-OO-1,
2 Order No. 28585). The year-end with pro-forma adjustments method
3 proposed by the Company in this case is identical, in all material
4 respects, to the method proposed by the Company, and accepted by the
5 Commission in these previous cases.
6 Q.Is the effect of Staff s proposed change in rate making methodology
7 material?
8 A.Very much so. According to Staff witness Hars, the 13-Month
9 Average rate base is approximately $12 milion lower that the Rate
10 Base fied by the Company. Solely due to the difference in rate base,
11 Staff's revenue requirement is approximately $2 milionlower than the
12 Company's. A $12 milion reduction in rate base, compared to the
13 Company's total rate base of $140 milion represents a 9% reduction,
14 solely from a change in rate making methodology.
15 Q.What conclusions have you reached with regard to Staffs position to
16 change from the policy of an end of period rate base to a thirteen-
17 month average rate base for the Company in these proceedings?
18 A.I conclude that:
19
20
21
22
23
24
25
26
1.Staff has erred in its conclusion that United Water Idaho
did not normalize revenues completely to May 31,2005
and so did not cause a "mismatch of expenses and
revenues" as Staf alleges.
2.The Company's rate base, expense and revenues treatment
in its fiing are consistent, while Staff's are not;
D. Peseau, Re - 3
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
3. There is a fudamental test used below thatthe
Commission can use to distinguish between when to apply
the thirteen month average rate base method it uses for the
electric utilities, and the year end rate base method it has
used for some time for the more capital intensive United
Water Idaho.
4. Because Stas case is so inconsistent, and unless the
Commission continues with the methodology it used in the
four previous United Water Idaho rate cases, there wil
result an absolute inability for United Water Idaho to ear
its allowed rate of retur, and shareholder property wil be
confiscated.
United Water Idaho Matches, but Staff Mismatches Revenues and Expenses
16 Q.What is the issue with respect to the matching of revenues and
17 expenses in this case?
18 A.Staff alleges in this case that the Company's filing, although entirely
19 consistent with and nealy identical in method to its previous thee rate
20 case filings, does not match normalized revenues with normalized
21 expenses. The issue here is whether or not it is necessary in the case
22 of United Water to change from its established end of period rate base
23 method to a thirteen-month average method proposed by Staff in order
24 to match revenues and expenses.
25 I argue that in at least two respects, the year-end or end-of-
26 period rate base method is more appropriate for a water utilty with the
27 Company's characteristics. I say this knowing that for some time the
28 Commission has endorsed and approved the thirteen-month average
29 rate base period for the electrics Idaho Power and A vista, which it
30 regulates.
D. Peseau, Re - 4
United Water Idaho Inc.
1 Q.What is the first reason it is appropriate to allow United Water to
2 establish rates based upon an end-of-period rate base?
3 A.The first reason is for accuracy and ease of application. For a water
4 utilty that has its investment, and therefore rate base growing as
5 quickly as the Company, it is far easier to anualize revenues to end of
6 period, than to reverse the numerous expense and rate base entries. In
7 the recent Idaho Power rate case No. IPC-E-03-13, I testified:
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Q.
A.
Q.
A.
How should this mismatch be corrected?
There are basically two alternative remedies available. The
first would be to reverse the anualizing entres and
properly match test year averages on both sides of the
ledger. The second alternative is to anualize revenues in
the same maner as rate base and expenses.
Do you have a preference between these two alternatives?
On the whole, I think anualizing revenues to 2003 year-
end levels is the preferable course for two reasons. First, it
is much simpler to anualize revenues than to back out
Idaho Power's annualizing adjustments from numerous cost
and rate base categories. Moreover, annualizing revenues
produces a more forward-looking result than reversing the
expense and rate base annualizations.
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
anualization of expenses. Order No. 25880, pp. 3-4. In
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.
(Peseau direct, Case No. IPC-E-03-13, Pages 5-6)
31 Q.Has, in fact, Staff failed to properly match its proposed thirteen-month
32 expense and rate base estimates with corresponding revenues?
33 A.Yes. This can be demonstrated by determining that Staf used
34 essentially the same level of anualized revenues, those for the period
D. Peseau, Re - 5
United Water Idaho Inc.
1 ending May 31, 2005 that are contained in the Company's fiing. In
2 following its suggestion to use the thirteen-month average rate base,
3 Staff should also have reduced the May 31, 20051 anualized revenues
4 in the Company's fiing back to the actual test year revenues centered
5 at Januar, 200. But Staff did not. The test year revenues used by
6 Staff are actually the very same test year revenues developed by the
7 Company for its end of period method, with one very small exception.
8 On Company Exhibit 8, Page 2 of 2, proposed test year revenues are
9 $31,534,832. To verify that Staffs case calculates anualized
10 revenues identically to the end of period May 31, 2005 calculated by
11 the Company, I refer to Staf Exhibit 126. On this exhibit (column (6),
12 line (12)) appears the same anualized revenue levels of $31,
13 534,832.2 In other words, Staff mismatches rate base and expenses on
14 a thirteen-month average basis, with a higher level of revenues
15 calculated on a forward anualized period May 31, 2005. Thus there
16 is a gross mismatch.
17 Contrastingly, the Company's filng is consistent, in that it
18 matches the higher level of end of period May 31, 2005 revenues with
19 its end of period expenses and rate base. Staf, on the other hand,
20 mismatches these components by using the smaller than actual rate
21 base, its thireen month average, with the 'higher level of end of period
IThese May 31, 2005 annualized revenues are derived by adjusting twelve-month ending July 31,200
revenues for South County, weather normalization and growt though May 31, 2005.
~his figure is adjuste by $5,628 for Carriage Hil on Staff Exhibit i i i, Page 2 of 2.
D. Peseau, Re - 6
United Water Idaho Inc.
1
2
3
4
5
6 Q.
7
8
9 A.
10
11
12 Q.
13
14 A.
15
16
17
18 Q.
19
20 A.
21
22
23
revenues. This is a mismatch that eventually guarantees an under
recovery of revenues sufficient to ear the allowed rate of retur.
Again, in my opinion, the most appropriate means by which to most
accurately match the Company's expenses and revenues is to use the
end of period rate base.
For puroses of consistency between the rate base treatment of the
local electrics, and United Water should the Commission require
United Water to use a thirteen-month average rate base?
No, there are significant and peculiar differences here that, in my
opinion, argue strongly for allowing United Water to continue with its
end of period rate base method. This second reason is argued below.
Does not Staff argue that the Commission has recently changed
policies regarding rate base treatment?
Yes. Staf Witness Mr. Lobb, on Pages 6-9, suggests that because the
Commission approved the thirteen-month average rate base methods
fied by Idaho Power and A vista, that consistency requires this policy
be extended to United Water.
Did the Commission orders in those cases mandate use of an average
test year for all utilties?
Not as I understand them. Order Numbers 29505 (IPCo) and 29602
(A VU) advised utilties that when proposing post-test year additions to
rate base a corresponding revenue and expense adjustment should be
made. United Water has attempted to comply with that directive in
D. Peseau, Re - 7
United Water Idaho Inc.
1
2
3 Q.
4
5 A.
6
7
8 Q.
9 A.
10
11
12
13
14
15 Q.
16
17
18
19 A.
20
21
22
23
this case. Neither order, however, advised utilties that an average test
year must be presented.
Have Order Numbers 29505 and 29602 created some level of
uncertinty among companies regulated by the Idaho Commission.
I believe so. Neither Order identified the calculations used to produce
the proxy adjustment and the IPCo Order indicated that the proxy was
not intended as precedent for use in futue cases.
Are the Idaho Power and A vista cases distinguishable in other ways?
Yes. In each case the utilty, as par of its initial Application, proposed
use of an average test year, which was, with some modifications,
accepted without dispute in each case. In both cases the question of
average versus year-end test year was not a debated issue. Neither
case reflects a conscious policy decision to require an average test year
in all cases for all utilities.
Are there examples of instances in which the Commission has
simultaeously used an average rate base for some companies and a
year-end rate base for others, depending on the circumstaces of each
company?
Yes. In Case BOI-W-93-3, fied in December of 1993 and decided in
August of 1994, the Commission employed a year-end test year for
Boise Water. At about the same time the Commission in Case No.
IPC-94-5 (fied in June of 1994, decided in February of 1995)
employed an average rate base for Idaho Power Company.
D. Peseau, Re - 8
United Water Idaho Inc.
1 Q.Do you agree that requiring United Water to use a thirteen-month
2 average rate base in setting rates would place the Company in a
3 position consistent with Idaho Power and Avista?
4 A.No. First let me acknowledge that in some if not many circumstances
5 normalizing and anualizing accounting adjustments ca be made that
6 make the thirteen-month average rate base and year-end rate base
7 nearly financially equivalent. But such is not the case for United
8 Water.
9 Q.Why?
10 A.The key determinants of whether use of a thirteen-month average rate
11 base and a year-end rate base wil produce rates that generate revenues
12 sufficient to keep the utilty financially whole for the first year or so
13 after those rates go in effect are 1) capital intensity and 2) growth in
14 rate base per customer.
15 That is, once rates are set in these proceeings, for
16 example, if each new customer added to the system requires greater
17 (less) than the average investment per customer then rates charged
18 each new customer wil cause a retur shortfall (excess) on average
19 investment. In the 1990s, many electrc utilties, including Idaho
20 Power, were able to freeze and even reduce existing rates despite
21 significant anual rates of customer and rate base growth, with no
22 adverse financial consequences. In fact, some utilties were able to
23 ear returns in excess of allowed returs and agreed to share these
D. Peseau, Re - 9
United Water Idaho Inc.
1 excess returs with ratepayers. The reason that this was possible was
2 because new customers were able to be served with incrmental
3 investment or rate base of less than system average rate base per
4 customer. At fixed rates therefore, these new customers cost less than
5 system average rate base cost to serve and provide higher than average
6 revenue margins than set in the prior rate case.3
7 In such cases where the rate base additions to serve a
8 growing customer base is below or equal to average cost, the
9 application of either a thirteen month average or year-end rate base
10 should be nearly financially equivalent. But for capital intensive
11 utilities that incur above average rate base costs to serve new
12 customers, the thirteen-month average rate base is far less likely to
13 produce rates that generate revenues necessar to produce the allowed
14 returns. This is tre simply because a thireen-month rate base is not
15 as current or "forward-looking" as the year-end rate base adjusted for
16 rate base additions.
17 Under what such capital intensive and growth category does UnitedQ.
18 Water service fall?
19 The Company definitely qualifies as a capital intensive utility thatA.
20 must make higher than average cost incremental rate base additions to
21 meet its growing load.
3The technical term is that the marginal cost to service new customers is less than the average cost to serve,
and existing rates are matched to average, not marginal costs.
D. Peseau, Re - 10
United Water Idaho Inc.
1 Q.Do you have evidence that recent customer and usage growth
2 experienced by the Company has been met with higher than average
3 rate base costs per customer?
4 A.Yes; This is shown in the following table. This table simply
5 calculates the percentage changes in rate base costs per customer (in
6 two different ways). As shown, rate base cost per customer has grown
7 recently by over 20%, while customer or usage growth has been
8 approximately 2% or less.
9 Q.Do the high rates of growt in rate base cost per customer reflect the
10 large cost increment resulting from the Columbia plant addition?
11 A.Yes, and Staff has, in my opinion acted responsibly in incorporating
12 the Columbia plant in rate base for the entire test year. But my point
13 here is that the recent large rate base additions, and those planned in
14 the coming year wil be at incremental costs higher than rates in
15 place. Under these circumstaces, a forward looking end of period
16 rate base calculation wil do much more to reduce (but wil not
17 eliminate) the Company's earings attrtion than wil a thirteen-month
18 average rate base calculation.
19 Q.Are there other factual circumstaces that United Water faces that
20 compound this earings attrition and revenue shortfall?
21 A.Yes. Not only is the Company experiencing incremental investment
22 that is higher than average, it also is adding customers whose revenues
23 or bils are below system average. I understand that this decrease in
D. Peseau, Re - 11
United Water Idaho Inc.
1 revenue per new or growth customer is due largely to a high
2 percentage of such customers taking service in areas where alternative
3 sources of irrigation water are available and thus only use United'
4 Water service for domestic purses. This phenomenon only
5 accentuates revenue shortall between rate cases.
United Water Idaho
Change in Rate Base per Billng Unit
Test Year
Ending July Pro Forra
31,2004 Year Ending Percent
Item Adjusted May 31,20005 Change
Rate Base(1)$113,575,180 $140,148,149 23.40%
Commodity Use (CCF) (2)20,407,679 20,671,823 1.29%
Rate Base per CCF $5.57 $6.78 21.72%
Bils Rendered (3)440,686 450,336 2.19%
Rate Base Per Bil Rendered $257.72 $311.21 20.76%
Source:
(1) Exhibit No.1, Page 1 of 9. (revised)
(2) Exhibit 6, Schedule 3, Pages 7, 13 and 22.
(3) Exhibit 6, Schedule 3, Pages 9 and 22.
6
7 What conclusions do you draw from this?Q.
8 I conclude that Commission consistency does not and should notA.
9 require the same rate base evaluation methods between the electric and
10 water utilities that it regulates.
11 In fact, I conclude that consistency, defined as equal
12 opportunities to ear the allowed rates of retur granted, actually
13 requires maintaining the long-time end of period method used for
D. Peseau, Re - 12
United Water Idaho Inc.
1 United Water. I am not at all persuaded by Staffs proposal to make
2 all utilties fit into a thirteen-month average rate base valuation.
3 Has the Commission in the past relied on analysis similar to yours, asQ.
4 discussed above?
5 Yes, in 1993, when the Commission abandoned use of an average testA.
6 year in Order No. 25640 the Commission said;
7
8
9
10
11
12
13
14
15
16
17
18
According to Staff, Boise Water's rate base would be $1,163,281
lower if calculated based on a 13-month average as opposed to
year end. While it might be advantageous to ratepayers to have a
lower rate base, no pary challenges Boise Water's proposal to
utilize a year end rate base. Boise Water's customer base and its
investment in plant are both growing rapidly. A year-end
calculation of rate base for a utility experiencing rapid growt is, in
this case, a more accurate reflection of that utilty's investment in
plant. In light of the foregoing and the absence of objection, we
find that a year-end calculation of rate base for Boise Water is fair,
just and reasonable.
19 Wil the use of Staffs thirteen-month average rate base cause UnitedQ.
20 Water to suffer rates of return attrition from the very first year rates are
21 in effect?
22 Yes.4 This earnings attrition or rate of return shortfall is shown in myA.
23 rebutt Exhibit 17.
24 What doe Exhibit 17 show?Q.
25
"Tis conclusion is reached even assuming that Staff corrects its revenue mismatch by deducting $752,289
from its normalized revenue estimate.
D. Peseau, Re - 13
United Water Idaho Inc.
1 A.Exhibit 17 compares the actual or realized rates of retu under Staff s
2 proposed thirteen month average rate base to the fair or allowed rate of
3 return that it proposes. The right-most column of the exhibit
4 summarzes the total rate of return on equity and overall rate of retu
5 that result from Staff s changing from the present year-end method to
6 the thirteen-month average rate base method. Stas proposal ensures
7 an overall rate of retum shortall of 88 basis points, the difference
8 between the proposed 8.10% overall rate of return and the 7.22% rate
9 of return that results solely from not including the ending rate base
10 investment.
11 Thus, according to this exhibit, Staff s proposal, and the
12 high marginal cost of serving new customers virtally assures that
13 United Water wil suffer earings deficiencies from the time that new
14 rates go into effect.
15 Q.In your opinion would such an earings shortall constitute a denial of
16 shareholders of an opportunity to ear a fair rate of retur
17 commensurate with investments with commensurate risks?
18 A.Yes. In my effort over the years to estimate fair rates of return for
19 utilities, I have relied upon the financial interpretations of certain key
20 court decisions in evaluating the reasonableness of rate making
21 adjustments. Three key decisions are the Bluefield (Bluefield Water
22 Works v. Public Servo Comm'n, 2672 U.S. (1922)), Hope (Federal Power
23 Commission V. Hope Natural Gas, 320 U.S. 591 (1944)) and more recent
D. Peseau, Re - 14
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Q.
A.
Q.
A.
Q.
A.
Duquesne (Duquesne Light Co. v. Barasch, 488 U.S. 299 (l989))cases,
My interpretation has always been that irrespective of the method or
actual estimate for the fair rate of return, a check of reasonableness is
always that the sum of the rate case decisions allow for, or even ensure
the opportunity for the utilty to ear the fair rate ofreturn determined
in the case.
In your opinion does Staff's proposed thirteen-month average rate base
method allow United Water the opportunity to ear its allowed return?
No, as I have explained, Exhibit 17 shows that Stas thirteen-month
average rate base causes actual returs to be below the fair or allowed
return. This in my opinion results in a denial of fair earings and a
confiscation of shareholder property
Turning now to the Staff recmmendation to allow in rate base 1/13 of
post test year investment, what is the practical effect of this proposal?
It means, obviously, that the Company is denied a retur on up to 92%
of post test year investment in plant that is devoted to public service
during the rate period.
To the extent the proposal is aimed at solving a perceived problem of
mis-matched revenue and expense, does it make sense?
It does not. It canot conceivably be tre that the revenue producing
or expense reducing effects of new investment are of such a magnitude
that 92% of the investment should be disallowed.
D. Peseau, Re - 15
United Water Idaho Inc.
1 Q.Is the end result of the Staff proposal out of proportion with the end
2 result of adjustments recently made by the Commission in other cases
3 to take into account revenue producing, expense reducing effects?
4 A.Yes it is. In the recently concluded A vista rate case, the Commission,
5 with some reluctance, employed a varant of a proxy approach
6 developed in the preceding Idaho Power Company rate case. (See
7 Order No. 29602, pgs 16-17). This resulted in approximately 12% of
8 post test year investment being excluded. Without debating the merits
9 of the adjustment methodology in A vista it is obvious that Staf s
10 proposal in this case produces an end result totally disproportionate to
11 the end result believed to be reasonable by the Commission in A vista.
12 Rate Design and Cost of Service Issues
13 Q.Are there numerous differences in the cost of service and rate design
14 issues proposed by you and by Staff witness Sterling?
15 A.No. In fact, there is really only one significant difference between the
16 rate design proposal I offer on behalf of United Water Idaho and that
17 proposed by Mr. Sterling. That difference is in the level at which to
18 set the bimonthly customer charge. I propose a bimonthly customer
19 charge of $19.86 while Mr. Sterling proposes to keep in place the
20 present bimonthly customer charge of $14.57. I argue this issue
21 below.
D. Peseau, Re - 16
United Water Idaho Inc.
1 Q.Is there a significant difference in your cost of service analysis on
2 seasonal commodity cost differences and the seasonal rate design
3 proposed by you and Mr. Sterling?
4 A.No, in fact there is no difference that I can determine. In my direct
5 testimony, I explained that for the first time we were able in this case
6 to incorporate an actual seasonal cost of service study to set
7 parameters for seasonal rate differences. That is, the seasonal rate
8 design I propose and Mr. Sterling endorses is based on seasonal cost
9 differences. In this regard Mr. Sterling indicates:
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Q. Do you believe that the 25 percent summer/winter rate
differential should be maintained?
A. Yes, I do. By having a commodity rate that is 25 percent
higher in the summer than in the winter, customer are sent a strong
conservation signal that helps to lessen United Water's peak
summertime demands. Furermore, I agree with United Water
witness Peseau's conclusion from his cost of service study that
there is a substatial difference in commodity costs of service
between the winter and summer.
Q. Do you believe that the summer/winter commodity rate
differential should be increased to more than 25 percent?
A. No, I do not ....
(Sterling, Direct, Page 58, Lines 12-25)
I point out the agreement between Staf and Company on the seasonal
25 rate design issue because both Mr. Sterling and Idaho Rivers United
26 (IRU) witness Mr. Wojcik go on to discuss possible inverted rate
27 alternatives to the present seasonal rate design structure. And, while I
28 strongly believe that, given the initial consumption block design
29 agreed to between Company and Community Action Parership
30 Association of Idaho (CAPAI), and the discussion in rebuttal by Mr.
D. Peseau, Re - 17
United Water Idaho Inc.
1 Wyatt agreeing to Staff's proposal to move toward monthly billng,
2 additional rate inversion should be avoided. Additionally, I do not see
3 the nee at this time to follow Mr. Sterling's proposal to begin a
4 separate docket to review other rate designs until such time as the
5 present one is evaluated. Any consideration of new, alternative rate
6 design proposals, perhaps including inverted rates, could be postponed
7 to a the next genera rate case, provided paries express their interests
8 and undertake discovery early in the process. Inverted rates should not
9 be attempted in the present proceedings.
10 Level of Customer Charges
11 Q.In light of the potential move to a monthly billng cycle, what is your
12 recommendation with regard to the appropriate level of customer
13 charges?
14 A.I disagree with Mr. Sterling's suggestion that there is any economic
15 justification for limiting or restraining customer costs to the narow
16 definition of "direct costs" of meter reading and biling. The only
17 other cost categories included in my customer cost of service study are
18 the direct costs of meters and services. I canot think of any cost more
19 directly related to individual customers than those of their own meter
20 and service line. These two items can serve the individual and only
21 the individual customer and are the most direct cost imaginable.
22 Placing these direct and individual customer costs on the
23 commodity rate in the name of conservation only ensures that these
D. Peseau, Re - 18
United Water Idaho Inc.
1 fixed costs wil not be recovered by the Company between rate cases,
2 and wil be made to be subsidized by customers whose consumption
3 canot be shifted (have "inelastic" demand) after subsequent rate cases
4 attempt to distribute these revenue shortalls.
5 Q.What is the problem you see in keeping customer charges far below
6 actual costs of service?
7 A.While I do not favor moving customer charges to full cost of service at
8 this time, I neverteless recommend that they be raised to some degree
9 in every rate case. Absent this, United Water Idaho and the
10 Commission wil be facing significant revenue shortall and rate equity
11 problems.
12 Q.Please explain the revenue shortall problem.
13 A.Both the Staff and IRU discuss keeping customer charges below costs
14 in order to facilitate conservation. I am absolutely in support of
15 facilitating any and all conservation that results from rate design based
16 on costs. This is precisely how so-called "economic efficiency" and
17 responsible consumption are promoted.
18 The problem is that collecting the capital costs of physical,
19 fixed customer meters and service lines outside a customer charge by
20 spreading it as if they were volumetric or commodity costs canot be
21 argued to promote economic levels of conservation. This is best done
22 within the seasonalization of the commodity costs that is contained in
23 my cost of service study_
D. Peseau, Re - 19
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Q.
A.
In the context of proper rate design and the recovery of
allowed revenue requirement for United Water, "force" or excessive
levels of conservation do nothing but leave capital costs and therefore
allowed rates of return unrecovered. Taken as a fixed customer
charge, meter and biling costs, both expenses and capital, afford some
level of revenue stabilty for this extremely capital cost intensive water
utilty company.
Has not the Commission recently decided to omit certin fixed costs
from the monthly customer charges of both Idaho Power and Avista?
Yes. However, there is a long history and rationale for this costing
method in the electric utility industry. The proportionately larger
share of variable costs for electric utilities as a percentage of total cost
of service, and the common practice of laying off of some customer-
related costs to the transmission and even generation functions has
allowed for historically lower monthly customer charges.
But for a utilty as capital intensive as United Water, the
subsidizing of the cost of dedicated meters and service lines in usage
sensitive commodity rates wil lead to revenue shortalls for Company.
Can the revenue shortfalls caused by a highly subsidized customer
charge be lessened by more frequent rate cases?
Yes. In this instance, however, more frequent rate cases result in the
customer charge subsidy being transferred from United Water
shareholders to other customers. Not only do more frequent rate cases
D. Peseau, Re - 20
United Water Idaho Inc.
1 involve higher administrative costs for the Company, the Commission
2 and others, but are likely to result in more inequitable rates among
3 customers, over time.
4 Q.Why does significant under-recovery of customer charges cause
5 inequities among rates of customers?
6 A.The costs of meters and service lines benefit none other than the
7 specific customer for whom the meter and service is installed. Staffs
8 limiting of customer charges reflective only of meter reading, biling
9 and customer accounting results in 65% of customer-specific costs
10 being shifted to the usage-sensitive commodity rate. Consequently,
11 those in a position to invest in devices to reduce water consumption
12 avoid payig their reasonable share of their own meters and service
13 lines.
14 Q.Isn't this type of pricing good for conservation?
15 A.No. As valuable and socially responsible that the conserving of our
16 water is, equitable pricing requires that conservation be induced
17 primarily though rates that reflect costs, in this case commodity costs.
18 My seasonal commodity rate differentiation accomplishes this.
19 Furter and additional adding on of fixed customer costs to commodity
20 rates is merely punitive to some degree.
21 Q.Does the raising of monthly or bimonthly customer charges closer to
22 actual costs "blunt price signals"?
D. Peseau, Re - 21
United Water Idaho Inc.
1 A.No. All the economic benefits attained though pricing are based on
2 the theory that rates bring about optimal levels of consumption of a
3 commodity, water or otherwise, by pricing according to costs. The
4 seasonal rates I propose are based primarily on seasonal commodity
5 cost differences and are adequate for inducing conservation.
6 Q.Do the seasonal commodity rates proposed by you in Exhibit 14
7 already contain a considerable amount of customer costs not collected
8 by the $19.86 proposed bimonthly customer charge?
9 A.Yes. In my direct testimony and my Exhibit No. 14, Schedule 1, Page
10 1 of 2, the implied full cost of service charge would be approximately
11 $22.00, which I do not propose.
12 Q.Would the enactment of monthly rather than bimonthly biling of
13 customers provide an opportunity to raise the current customer charge?
14 A.I believe that it would. Obviously, the commodity portion of a
15 monthly bil wil be approximately one-half of the bimonthly amount.
16 While the anual amount biled should be same, movement to monthly
17 biling should make the customer charge more acceptable. The
18 monthly customer charge under my rate design would be
19 approximately $9.93.
20 Q.Please summarize your position on the appropriate level of customer
21 charge to set in these procedings.
22 A.An increase in the existing customer charge is necessar to maintain
23 some level of revenue stabilty for the capital intensive nature of the
D. Peseau, Re - 22
United Water Idaho Inc.
1 Company's water service. A monthly customer charge of $9.93, while
2 significantly below the monthly fixed costs of serving customer, is a
3 move in the right direction.
4 Furtermore, this level of customer charge would lessen the
5 inequities of cross subsidies in rates for customers wh~ do not pay a
6 fair portion of their specific meter and service line costs.
7 Alternative Inverted Rates
8 Q.What is the purpose of your discussing the issue here of an inverted
9 block rate design?
10 A.As I referred to in the introduction, while Staff Witness Sterling agrees
11 with the level and seasonal design of my proposed rates, he does go on
12 to indicate that, while not recommending an inverted block rate design
13 in this case, he offers discussion on same in the event that the
14 Commission should wish to consider it (Direct, Page 62, Lines 2-11).
15 Q.Do you believe that an inverted rate design for United Water is
16 preferable to your proposed seasonal rate design?
17 A.No. Before I could endorse an inverted block rate design for United
18 Water I would need to have the benefit of considerable consumption,
19 elasticity, biling and other information upon which to base inverted
20 block rates. This information is not available at this time.
21 Secondly, implementing multi-block inverted rates may
22 add considerable confusion for customers. I agree with Mr. Sterling's
23 assessment (Direct, Page 58, Lines 2-10) that:
D. Peseau, Re - 23
United Water Idaho Inc.
1
2
3
4
5
6
7
8
9
10
11
Any time a new rate design is implemented,
however, there is a period - sometimes a very lengty one
- during' which customers must lear and become aware of
the new rate design. Moreover, even more time is required
for customers to adjust their usage patterns before the
objectives of a new rate design can be achieved. I believe
the decision of whether to implement a new rate design
should be based on an evaluation of whether the advantages
of a new rate design outweigh the tradeoffs.
Q.With study, can new rate designs be adequately evaluated at some
12 point?
13 A.Yes, although the process can be involved. Given the lack of specific
14 proposals that could be evaluated in these proceeding, and the cost of
15 administering proceedings on inverted blocks, I recommend that any
16 , such interest be expressed early in the next general rate case.
17 Q.Do you have comments on the testimony of Mr. Wojcik who testifies
18 on behalf of Idaho Rivers United?
19 A.Only briefly. Mr. Wojcik proposes significant rate design changes,
20 including multiple block inverted rates. However, the justification for
21 most of the proposals contains no Company or Idaho-specific data.
22 For the reasons cited by Mr. Sterling and me, these general rate design
23 suggestions referred to by Mr. Wojcik should be studied thoroughly
24 for applicability to the Company and its customers before being given
25 any serious consideration.
D. Peseau, Re - 24
United Water Idaho Inc.
1 Q.Do you agree with Mr. Wojcik's suggestion that the initial summer
2 block be increased by approximately three times the proposed 3CCF
3 bimonthly quantity? (Wolcik, pg. 7, lines 16-17)?
4 A.No. This proposal is intended to discount usage of water equal to the
5 average indoor consumption per customer. In my opinion this is an
6 excessive discount and has no cost or rate design benefit over the
7 smaller proposed 3 CCF discount. A more prudent policy would be to
8 begin with the smaller initial block, study customer responses and
9 assess the acceptabilty at a later date.
10 Q.Does the larger intial block proposed by Mr. Wojcik blunt an
11 appropriate summer price signal?
12 A.Yes. This larger initial summer block in effect shields the customer
13 from facing the consequences of the higher cost summer consumption.
14 After all, all consumption in the summer contrbutes to summer peak
15 and the need for additional supply at higher marginal costs, regardless
16 of whether the consumption is for inside or outside uses.
17 Q.Has Company Witness Mr. Wyatt agreed to a higher than 3 CCF initial
18 minimum block in his rebuttal testimony?
19 A.Yes. It is my understanding that in agreeing to transition to a monthly
20 biling cycle, Mr. Wyatt accepts as a monthly minimum block a 2CCF
21 quantity. This has the effect of increasing the original bimonthly block
22 by 33%, from 3 CCF to 4 CCF.
D. Peseau, Re - 25
United Water Idaho Inc.
1 Mr. Wojcik acknowledged on page 7, lines 5-6 of his
2 testimony that the original3CCF was slightly higher that average
3 toilet and shower usage. The 4 CCF initial block would provide a '
4 significantly higher cushion in this initial block.
5 Q.Do you have any additional comments on the testimony of Mr.
6 Wojcik?
7 A.I have just two comments.One, one Pages 3 and 4 of his testimony,
8 Mr. Wojcik suggests that higher customer charges may weaken
9 customers' incentives to conserve because they are unavoidable. This
10 is tre only in a social engineerig sense, as the optimal level of
11 conservation is never attained by adding inappropriate charges to
12 commodity rates, but rather by properly designing commodity rates.
13 Two, Mr. Wocjik makes a common, but mistaken
14 assumption that high-volume water users place the "highest strain on
15 the water supply system" (Direct, Page 3, Lines 16-18). This is simply
16 not tre; all water users, whether large or small, who consume during
17 system peak equally "strain" the system and drive the need for
18 additional plant and equipment to serve these system peaks. This
19 usage issue is better understood in terms of usage load factors as in the
20 electric and natural gas industries. For example, a large, high load
21 factor user may contribute little to system peak and therefore not be
22 contrbuting disproportionately to higher seasonal costs.
23 Q.Does this conclude your testimony?
D. Peseau, Re - 26
United Water Idaho Inc.
1 A.Yes.
D. Peseau, Re - 27
United Water Idaho Inc.
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