20101222Vol VIII Technical Hearing pp 1512-1777.pdf

ORIGINAL
_.BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF PACIFICORP DBA ROCKY MOUNTAIN
POWER FOR APPROVAL OF CHANGES TO
ITS ELECTRIC SERVICE SCHEDULES
CASE NO.
PAC-E-10-07
TECHNICAL HEARING
HEARING BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER JIM D. KEMPTON
-
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:December 2, 2010
.VOLUME VIII - Pages 1512 - 1777
~-~~r"NN
-0:i
N..(J0"
-~
POST OFFICE BOX 578
BOISE. IDAHO 83701
208-336-9208
COURT REPORTING
ttHír tk ~ eo~4'íree19
.
.
.
19
20
21
22
23
24
25
1 APPEARANCES
2 For the Staff:
3
4
5
6
For PacifiCorp
dba Rocky Mountain Power
(RMP) :
SCOTT WOODBURY, Esq.
and NEIL PRICE, Esq.
Deputy Attorneys General
472 West Washington
Boise, Idaho 83702
HICKEY & EVANS, LLP
by PAUL J. HICKEY, Esq.
Post Office Box 467
Cheyenne, Wyoming 82003
-and-
DANIEL E. SOLANDER, Esq.
ROCKY MOUNTAIN POWER
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
RACINE, OLSON, NYE, BUDGE
& BAILEY
by RANDALL C. BUDGE, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
RACINE, OLSON, NYE, BUDGE
by ERIC L. OLSEN, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
BENJAMIN J. OTTO, Esq.
IDAHO CONSERVATION LEAGUE
710 North Sixth Street
Boise, Idaho 83702
WILLIAMS BRADBURY, PC
by RONALD L. WILLIAMS, Esq.
1015 West Hays Street
Boise, Idaho 83702
-and-
DAVI SON VAN CLEVE, PC
by MELINDA J. DAVISON, Esq.
333 Southwest Taylor, Suite 400
Portland, Oregon 97204
BRAD M. PURDY, Esq.
Attorney at Law
2019 North Seventeenth Street
Boise, Idaho 83702
7
8
9
10
For Monsanto:
11
12
13
14
For Idaho Irrigation
Pumpers Association (IIPA):
15
16 For Idaho Conservation
League (ICL):
17
18
For PacifiCorp Idaho
Industrial Customers (PIIC):
For Community Action
Partnership Association
of Idaho (CAPAI):
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
APPEARANCES
.1 I N D E X
2
WITNESS EXAMINATION BY PAGE3
Mark Widmer Mr.Budge (Direct)1512
4 (Monsanto)Prefiled Direct 1518
Prefiled Surrebuttal 15535Mr.Hickey (Cross)1568
Mr.Budge (Redirect)15826
Kathryn Iverson Mr.Budge (Direct)15887(Monsanto)Prefiled Direct 1590
Mr.Woodbury (Cross)1613
8 Mr.Hickey (Cross)1615Commissioner Smith 16219
Brian Collins Mr.Budge (Direct)162310(Monsanto)Prefiled Direct 1625
11 Greg Meyer Ms.Davison (Direct)1636(PIIC)Prefiled Direct 163812Mr.Solander (Cross)1678.13 Donald Schoenbeck Ms.Davison (Direct)1681(PIIC)Prefiled Direct 168414Mr.Woodbury (Cross)1704
Mr.Solander (Cross)170615
Randall Falkenberg Mr.Davison (Direct)171116(PIIC)Prefiled Direct 1714
Prefiled Surrebuttal 175417Mr.Hickey (Cross)1765
18
19
20
21
22
23
24.25
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 INDEX
.
.
16
17
18
19
20
21
22
23
24
. 25
1 EXHIBITS
2
NUMBER
4
For Rocky Mountain Power:
PAGE3
89 WIEC Data Request 3.6, 2 pgs Marked 1570
1570
1573
1618
584
5
90 Widmer list of testimony, 2 pgs Marked6
91 Submission of Stipulation, Wyoming Marked
PSC Docket No. 20000-250-EA-06, 28 pgs7
8 92 Normalized Billing Determinants Marked
9
For Monsanto:
10
253 Duvall Direct Testimony, Wyoming
PSC Docket No. 20000- -ER-10, 3 pgs
Marked11
12
13
14
15
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
EXHIBITS
.
.
.
1 BOISE, IDAHO, THURSDAY, DECEMBER 2, 2010
2
3
4 MR. BUDGE: We'd call Mark Widmer.
5
6 MARK WIDMER,
7 produced as a witness at the instance of Monsanto, being first
8 duly sworn, was examined and testified as follows:
9
10 DIRECT EXAMINATION
11
12 BY MR. BUDGE:
13 Q.Would you state your complete name and business
14 address for the record?
15 A.My name is Mark T. Widmer. My business address
16 is 27388 Southwest Ladd Hill Road, Sherwood, Oregon, ZIP Code
17 97140.
18 Q.Mr. Widmer, did you prefile direct testimony,
19 rebuttal testimony (sic), and surrebuttal testimony on behalf
20 of Monsanto Company?
21
22
A.I did.
Q.Did you also sponsor Exhibits 228, 235, and
23 236?
24
25
A.I did.
Q.And I believe there was an errata sheet with
1512
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
1 respect to your rebuttal testimony that identified certain
2 changes?
3 A.It was actually with respect to my direct
4 testimony.
5 Q.And then a corrected version of that direct
6 testimony was also filed?
7 A.Yes.
8 Q.Do you have any corrections you wish to make to
9 your testimony --
10 Just to clarify, your errata sheet, the
11 correction was to your rebuttal testimony or to your direct
12 testimony?
13 A.To my direct testimony.
14 Q.Do you have any other corrections to either your
15 testimony or your exhibits?
16 A.I do have a few; maybe a few more than a few:
17 Starting with my errata testimony on page 2,
18 line 8, the 47.37 million should be changed to 47.02.
19 And line 9, the 2.57 should be changed to 2.55.
20 Moving to Table 3, for the adjustment Item No.7,
21 Cal iso, i overlooked a second sheet.
22
23
24
25
COMMISSIONER SMITH: What page is that?
THE WITNESS: That's page 3.
COMMISSIONER SMITH: Okay.
THE WITNESS: I overlooked a second sheet of data
1513
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
20
21
1 on my adjustment which needs to be included. That inclusion
2 revises the total Company adjustment to 3,713,698.
3 COMMISSIONER SMITH: Is there a line number?
4 THE WITNESS: That would be Item 7.
5 COMMISSIONER SMITH: All right. Could you say
6 that again, please?
7 THE WITNESS: Yes. The total Company number
8 should be 3,713,698.
9 COMMISSIONER SMITH: Is that a posi ti ve or
10 negative number?
11 THE WITNESS: That's a negative number. Sorry.
12 And as a result of that change, the Idaho
13 allocated number in Column 2 would change to a negative
14 204,569.
15 Because of those changes, that changes the line
16 called Total Adjustments Primary Recommendation. The
17 47,346,771 should be revised to 47,018,478. And the Idaho
18 allocated number should be changed to 2,545,886. And both
19 those are negative numbers.
Q.BY MR. BUDGE: Does that conclude your changes?
A.I have a few more.
22 The following line, Estimated Allowed NPC Primary
23 Recommendation, that number, because of those other changes,
24 would change to 1,022,682,837. And the Idaho number would
25 change to 60,919,493.
1514
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
1 Moving to page 7, line 7, because of those
2 changes we just went through, the .22 million should change to
3 .20 million.
4 Moving to page 20, starting with line 22, the
5 question, through the answer on page 21, line 8, I would strike
6 that because I included a much more complete example in my
7 surrebuttal testimony.
8 Moving to page 23, line 6, the docket reference
9 number should change to 341-EP-09.
10 And then, lastly, for the direct, line 12, the
11 .22 million should change to .20 million.
12 Q.The last correction, could you repeat that?
13 A.Yes. It's page 24, line 12, the .22 million
14 should change to .20 million.
15 Moving to my surrebuttal testimony, line 9 --
16 MR. WOODBURY: What page are we on?
17 COMMISSIONER SMITH: What page?
18 THE WITNESS: Page 5. The second word, "not,"
19 should be stricken.
20 And that completes my changes.
21 MR. BUDGE: Ms. Chairman, with that and those
22 corrections provided, we would move that -- well, excuse me.
23 Q.BY MR. BUDGE: Before we proceed into that,
24 Mr. Widmer, if I were to ask you the same questions contained
25 in your direct, rebuttal (sic), and surrebuttal testimony
1515
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
20
21
22
23
24
25
1 today, would your answers be the same?
2 A.Yes, they would.
3 Q.And I noted a portion of your direct testimony
4 was filed as confidential. Correct?
5 A.That's correct.
6 Q.And is that based upon the fact that some portion
7 of that testimony was derived from confidential information
8 provided to the Company in Response to Data Requests?
9 A.Yes, it was.
10 Q.Were you able to identify on your testimony
11 specifically what portion is confidential?
12 A.Yes, I can.
13 Q.Wi thout referring to the numbers specifically,
14 can you just indicate where they are by page and line?
15 A.Yes, I can.
16 Q.As I look at that, it appears there is only
17 information on page 27, lines 3 through 6, on the confidential
18 draft that appear to be identified by --
19 A.That's correct.
COMMISSIONER SMITH: What about page 31?
Q.BY MR. BUDGE: Excuse me. Also
A.Yes.
Q.What is it on 31?
A.Also the Graph 1 on page 31 is also confidential.
MR. BUDGE: Subject to the Company's desire to
1516
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
19
20
21
22
23
24
. 25
1 handle this in the same manner as the other confidential and
2 have an opportunity to redact that out of the draft should they
3 desire to pull it out after the proceeding, we'd offer the
4 testimony and exhibits of Mr. Widmer and ask that they be
5 spread on the record, and tender him for cross-examination.
6 COMMISSIONER SMITH: If there's no objection, it
7 is so ordered.
8 (The following prefiled direct and
9 surrebuttal testimony of Mr. Widmer is spread upon the record.)
10
11
12
13
14
15
16
17
18
1517
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
. 1 LINODUCTONANQUALCATIONS
2 Q.
3 A.
6 Q.
7
8 A.
9
10
11
12 Q.
13 A..14
is
16
17
18
19
20
21
22
23
.
PLEE STATE YOUR NAM AN BUSINSS ADDRES.
My name is Mark T. Widmer and my business addrss is 27388 S.W. Ladd Hil Road,
PLEE STATE YOUR OCCUATION, EMPLOYM, AN ON WHOSE
BEHA YOU AR TESTIG.
lam a utility regulatory consultat and Principal of Nortwest Energy Consulting, LLC
("NWEC"). I am appearng on behalf of Monsato.
PLEE SUM YOUR QUALMCATIONS AN APPEACE.
With NWC, I provide consultig servces related to elecc utility systm opetions,
energy cost recovery issues, revenue requirements, and avoided cost pricing for
quaifyg facilties. Since formgNWEC, i have provided testmony in dockets
regarding recovery of net power cost thugh genera rate cass and power cost
adjustment mechanisms and avoided cost methodologies in Wyoming and netpower
costs and the prudence of resource acuisitions in Washington. Prior to formg NWEC,
I wa employed by PacifiCorp. Whle employed by PacifiCorp, I parcipat in and filed
testiony on power cost issues innumerous dockets in Wyomig, Orgon, Uta,
Washington, Idao, and Californa jursdictions over a 10 plus year period. At the time
of my depare frm PacifiCorp, I was the Director of Net Power Costs. My . ful
quaifications and appearances ar provided in Exhibit Monsto 228 (M -1).
1518
Widmer, DI - Page 1
.1 D.
2 Q.
3 A.
4
S
6
7 Q.
8 A.
9
10
11.12
13
.
PURSE OF TESTONY AN SUMY OF ADJUSTMNTS
WHT is TH PUROSE OF YOUR TESTIONY?
My testmony addresses PacifiCorp's Generation and Regulation Initiatives Decsion
("GRID") model which was used to calculate normalized Net Power Costs ("NPC") for
the forecast test perod ending December 31, 2010.
PLEE SU YOUR TESTIONY.
My testimony presents. fifteen NPC adjusents totaling $47.02 milion tota Compay
and $2.5S millon Idaho. As discusse in my following testimony, those adjustments ar
made to reflect realistic operation of PacifiCorp's system, match costs with benefits,
make corrections and reflect reasonable results. My adjustments ar sumarze on
Table 1 below and subsequently explained in more detal in the remaider of my
testimony.
1519
Widmer, DI - Page 2
. 1
.
2
3
4
s
6
7
.
ro..
Table 1
Summary of R~mëiAdjustments -~.
"'-I..,
Pnmllry. ... .secâry ......
Reëmerdatioil:Recõiirenations ¡
Idaho Est:' ....,¡- ........ïdho EsC";
..........._~"'_...._.....
63'465,~791
_.._..-.---~...-,_.. , . ..__........,."...... .. ..... _ .L.,......".._ .....GRID (Ne Vanable PowrCot Issue)
,. . "._,_=l~~i~~="~~üë~.~r~... . .ADJUSlMENT i !
T"'1iApS-SupplemenaftCOal +otïl) -1,942.8381 . .............................. ..'~..15;26T. ..._-..__.,.,..:":žTWincfirregl'onCots -3,187,931' ...._,_.~!,aæ~24~L..'... ......1~l~:.;~d~-f!r~;e~i:~~;:rts ,i:~~:~Tri:~"~::~="~:~l
31 Nonirm Transmission .. -2.432,98:=~.44.......7........~!3454....,..:.._......_...,~.I¡...."..'.....,_._......_.....'........,.......................... ....:......_......_...~..~...:.~,........................:.,,:..
'=:J 41~ní~R~!~-.~tifrerñen...:." -'-d"-1~,~j ., :
.I,"jtir~~~~~~c;_=:t.:...". .,_..... "' ...:.-:::.:..-o:--"-'-f~:: .::::_::::'::::-'~i~~i"'"'" .. ......-:----~.-!
I ¡ 6a'T0P of Worldlncreental Windlntegraion?13:?ëf"r ... .....Jdd:,..:=.:'.:.-1S;!j~J. ....; ilcallsO r"- .¡'. .. ... .... -3,713.698 . -20,561 j
rs)côìš¡rippïannecÎ oütâgès ... - ,_. . ~2...58......'....'..'..6...'.7.....8.. ...i...r........._..............,..,....:..1...5...........34......,.,7.......'1'......... _...._'_.._-_.,.... Ii'..J9IEneilY'GatewYTransniission 3.291,261 .195.2711"--" . .... .........;
...L.ljt~~=~~~~~líf~¡.~~s.._,..._.. . .,.:,._-t..- ... ...~:~~~::,. .. ...:.::.~I-:d::::........,....._.,.!I 12¡Bear Rivr Hydro Normalization -2.181,474; ; ~129.427~
!=~t~~t;~¡_.-...=---...-L...~!æ--T-_... .~!~=~_=~_~i
" '. r .. . . ..... ... .. --'.1 . .........-- ........,..... .. .;Tot~ Adjustments Pnmary Recommendion ~...._.~~!!g1~~4i8! . .:~,5o~..~.t~..,--_.-
:~~t~~;i~~:N~2';~=:~¡:~~e~:~;:-. ..,...._i....~..~;~:El7, 6O,919;493j--'......:.:_:~~=,ì
~st~i~::;~risd~~~~~.-....,....:F:.~ .... ....----,...... ... ..".__.....+-_...... .........".'-._..i...._.._.,..:.:.._"._._.....~
SE: Ë3:3575%....j ... .... .:.L.". .. T
$G':'-S:505% ~.,....,.. . ...,,--......... ...._.-......_. ..;.
1.~9.!O(.315:.
î.... . ... ..~+. n.___~"__,,
Adjustment 1.APS SUPPLEAL OPTON
The Company has an option to purchas supplementa energy offered puruat to
th~ Long Term Power Traaction Agrement with Arzona Public Serce ("APS").
. Whle the option is continualy exercised durng actu operations, it is uneconomic as
1520
Widmer, DI -Page 3
modeled in GRlD. Since the .purchase is optional and uneconomic it should be excluded
from NPC. This adjustent reduces NPC by SO.12 millon on an Idao basis.
Adjustment 2.WI INGRATION COSTS
The Company used the wind integrtion rate of S6.S0 per MWh that was adopted by the
Commission for avoided cost rates for qualifyng facilty contrcts to calculate wid
integration costs. This rate ha no basis on the Company's actu wind integration ,costs
and the Company ha therefore, not met its burden of proof regaring recovery of wind
integrtion cost. Consequently, I recommend that the Commssion reject rever of
wind integrtion cost using the S6.S0 per MWh rate and recnuend that wid
integtion costs be recovered though the Company's ECAMas it is the best solution to
recoverng actu wind integrtion cost. Ths adjustent reduces NPC by Sl.88 milion
on an Idao basis. I also reconuend that the Commission adopt the premise of my
seconda adjusent 2a OA IT Wind Integrtions Costs, so that the Company not be
allowed to reover wholesae wheeling customer wid integrtion costs from retal
cutomers thugh the ECAM. If the Commission does not adopt my proposed
reonuendation, my secondar remmendation is to adopt the followig adjustments
2a OAIT Customer Wind Integration Costs and 2b Balancing Wind Integration Costs.
Adjustment 2a.OATT CUTOMER WI INGRATION COST
The Company included wholesale wheeling customer wind integration cost in
NPC beause the Company has failed to reuest an adjustment to their OA IT so. tht
these costs can be recovered from wholesale wheeling cusomers. These cost ar not the
1521
Widmer, DI - Page 4
.1
2
3
4
S
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23
.24
respnsibilty of Idaho customers and should be removed from NPC. This adjustment
reduces NPC by $O.3S millon on an Idaho basis.
Adjustment 2b.BALCIG WI INGRATION COSTS
The Company double counted wind integrtion balancing costs dur the peod
Januar 2010 though April 2010. This adjustent removes the double count and lower
NPC by $0.14 millon on an Idao basis.
Adjustment 3.NON-FI TRSMISSION
In actu operations the Compay utilizes a signficant amount of non-fi
trsmission to us of assets included in rates more effciently in the system balancing
and optimition process. However, non-firm tranmission was excluded from NPC,
therby producing a suboptial dispatch of the system and higher net power costs. I
reommend that non-firm trmission be included in GRID to match costs and benefits.
Ths adjustment reduces NPC by $0.14 milion on an Idao bais.
Adjustment 4.DUN REERVE REQUIME
Ths adjustment incorporates the costs of caring operatng reserves for Dunap,
which were omitted from the original filing and increass NPC by $0.01 millon on an
Idaho basis.
Adjustent 5.RESERVE SIßWN nOR COMPNENT
The Company's inclusion of reserve shutdowns in the GRID forced outage rate
caculation input causes an overstatement of generation lost due to forced outages
1522
Widmer, DI - Page S
.1
2
3
4
S
6
7
8
9
10
11.12
13
14
lS
16
17
18
19
20
21
22
23.
beause the calculation is inconsistent with how GRI calculates generation lost due to
forced outages. I recommend exclusion of reserve shutdowns from the forced outage rate
calculation for all plants except for natu gas peaer units. This adjustent reduces
NPC by $O.OS milion on an Idao basis.
Adjustment 6.TOP OF WORL WI
Durng the discovery process the Company informed Monsanto tht the expecte
online date for the Top of the World wind project ha bee moved forward from
November 1,2010 to October 1, 2010. Ths adjustment includes the new online date and
increaes NPC by $0.09 millon on an Idao basis.
Adjustment 6a.TOP OF WORL INCRMENTAL WI INGRATION
If the Commssion does not adopt my primar recommendatioIl to recover wind
integration cost thugh the ECAM, ths adjustment includes incrementa integrtion
cost. associated with movig the expected in service date frm November 1, 2010 to
October 1,2010.
Adjustment 7.CAL iso EXENSES
The fiing includes a full yea estimate of Cal ISO wheeling and servce fees.
However, the filing does not include any tractions that would incur CAL ISO fees
beyond May 3, 2010. Accordingly, I recommend disalowace of all Cal ISO fees for the
period May 4, 2010 though December 31, 2010. I also remmend tht actu Cal iso
fees be included for the period prior to May 4, 2010 to match cost with the ac
1523
Widmer, DI - Page 6
.1
2
3
4
S
6
7
8
9
10
11.12
13
14
1S
16
17
18
19
20
21
22
23
.24
wholesale trsactons included in the filing. This adjustment reduces NPC by $.20
millon on an Idaho basis.
AdjustmeDt 8.COLSTR PLAD OUTAGES
Ths adjustment moves the planed outage stang dates for Colstrp 3 and Colstrp 4
from September to May to better optize the Company's system.
The revised planed outage dates reduce NPC on an Idaho basis by $0.02 millon.
Adjustment 9.ENGY GATEWAY TRSMISSON
Ths adjustent removes the Energy Gateway triÎssion project from NPC to be
consistent with Mr. Peseau' Energy Gateway transmission adjustent and incras NPC
by $0.20 milion on an Idao basis.
Adjustment 10.CROLL 4 CAPACI
The Company's modeling understates Cholla 4 capacity. My adjustent corrcts the
capacity and reduces NPC by $0.07 milion on an Idaho basis.
AdjustmeDt 11.MORGAN STAN CAL PREMI
The Company's filing includes two cal option purchae power contrts that are
uneconomic. This adjusent removes both contrcts and lowers NPC by $0.17 milion
on an Idao basis.
1524 Widmer, DI - Page 7
.1
2
3
4
S
6
7
8
9
10
11.12
13
14
1S
16
17
18
19
20
21
22
23.24
Adjustment 12.BEA RIR HYRO NOßMTION
The Bea River historica record was adjusted by the Company to remove flood
control year, which ar yea when surlus water was released from Bea Lake. The
Compay believes the adjustment is reasnable beause the region is curently impact
by a long-ter drought and a low water level at Bear Lake. Ths is one-sided because it
is different than the normalize methodology used to normalize all other hydro resources
,and is not appropriate for normalized ratemaking. I recommend that the floo contrl
year excluded. from NPC be included in NPC to be consistent with the modeling of other
. hydro resources. My recommendaon reduces the NPC by $0.13 milion on . an Idao
basis.
Adjustment 13.Blaek Bi Sales Shaping
The Compay bases its modeling of the Black Hils wholesale sales on the faulty
asumption tht Black Hils will dispatch the contrct durng the highest cost hour.
Historica dispatch of the contract demonstrtes tht ths is not the cae. I reommend
that the contrt be dispatched based on a four-year average of historical resuts. Ths
adjustment reduces NPC by $0.08 milion on an Idaho basis.
Adjustment 14~MONA MAT
The Compay limite the size of the Mona wholesae market, allegedy basd on
trding experience of their Front Offce; Historical inormation shows tht the Mona
market was signficantly undersized. I recornendthat the size of the Mona market be
corrcte based on a four-year average of actu inorration~ Ths adjustment reuces
NPCby $0.03 milion on an Idao basis.
1525
Widmer, DI - Page 8
.1
2
3
4
S
6
7
8
9
10
11
12
13.14
1S
16
17
18
19
20
21 in
22 Q.
23
24 A.
2S.26
Adjustment is.NAUGHTON 3 OUTAGE,
The Company collected liquidated damage payments frm its contrctor Siemens
for failure to complete a contrct on schedule due to poor peormance. The.Company
seeks to recover the cost of ths outae again by including it in GRID planed oute
inputs. Accordingly, I recommend that the planed oute be removed frm GRID. This
adjustment reoves the outae and reuces NPC by $0.03 millon on an Idaho basis.
Finally, in response to Monsato data reuest 2.33 the Company stted:
Pror to its rebutt the Company anticipates additional changes to varous
components of the net power costs, including but not limited to the new Offcial
Forward Price Cure and new short-ter fi electrcity and natu gas
tractions.
Ths very late updte does not provide the Paries adequate time to review the
signficant amount of data tied to the stted updte. Therefore, I recommend that the
Commission reect all Company proposed rebut updtes to NPC except corrons
related to the origial filing so that the Pares other than the Company ar not
disadvantaged by the late updte.
DETAIED ADJUSTMNT
BEFORE YOU DISCUSS YOUR ADSTM IN DETAI, PLEE
'EXLA NPC AN ITS IMORTANCE.
NPC is defined as the sum of purhasd power expense, wheeling expens and fuel
expense less wholesale saes revenues. Review and deterination of the appropriate
NPC is very importt because it repreents one of the Company's single largest revenue
1526 Widmer, DI - Page 9
. 1
2 .
3
4 Adjustment 1. '
reuirement components and establishes the ECAM baseline. NPC is calculated by the
Compay's GRID production dispatch modeL.
ARNA PUBLIC SERVICE ("APS") SUPPLENTAL
S ENGY
PLEASE EXPLA TH AP SUPPLENTAL ADST.
Puuat to the terms of the Long-Term Power Transactions Agrment between APS
and PacifiCorp, APS is required to offer PacifiCorp 219 GWH of Supplementa Coal
Energy and 876GWH of Other Suppiementa Energy though Octobe 31,2020, when
the contrct expires. The Company has the option but not the reuirement to purhas
either the Supplementa coal or Oter Supplementa energy or both at prices offered by
APS for eah product.
6 Q.
7 A.
8
9
10
11.12
13
14 Q.
15 A.
16
17
18 Q.
19 A.
20
21
22
23.
is TH CONTCT ECONOMIC AS MODELED IN GRI?
No. Both the Oter Supplemental and the Supplementa Coal components ar modeled
uneconorncaly in GRID.
HOW DID YOU DETERM TH CONTCT WAS UNCONOMIC?
I ra the GRID. model without the Supplementa Coa and Other Supplementa energy.
The rus reduced NPC by approximately $1.95 millon tota Compay. The contract is
therefore uneconomic for customers as modeled by the Company and should be excluded
from NPC. Ths adjustment reduces the NPC by $0.12 milion on an Idaho bais.
1527 Widmer, DI - Page 10
. 1 Q.HA TH COMPAN AGREED TO TlS METHODOLOGY IN OTHR
2 JUSDIÇTONS?
3 A.Yes. In the stipulation for Oregon Docket UE 216, the Company agreed to model the
4 APS Supplementa Coal and Oter option contrct only when ecnomic for futu filings.
S
6 Adjustment 2.WI INGRATION COSTS
7 Q.
8
9 A.
10
11.12
13
14
15
16
17
18
19
20
21
22
23
24
2S
26
27.28
HA TI COMPAN MET ITS BUREN OF PROOF ON WI
INGRATION COSTS?
No. Whle the Company has done numerous forecas of wind integrtion costs over the
last severa year, whch have vared from a litte over $ 1 per MWH to approximately $9
per MWh for 2011 in a recent dr study, they stil canot tell us what their acal wind
integrtion costs are. In WIEC Data Request S.6 from Wyoming Docket No. 20000-3S2-
EP-09 the Company wa asked to provide the actu reserve intr-hour reserve
requiment for wind generation located withn their contrl area. In response, the
Company stted:
The Company objects to ths question on the basis that it is overly burdensome
and would reuie the Company to perform analysis not previously performed.
Notwthtading ths objection, the Company states as follows.
The Company holds reserves to maita reliabilty of its system in accordce
with stadads set by the Western Electrcity Coordiatig CounciL. Reseres
held are not differentiated such that the Compay can identify the intr-hour
reserve requirement isolated for wind generation.
Without knowig what the Company's actual costs ar it is ver diffcult to determe the
renableness of Company's requested recovery of $34.2 millon for wind integrtion
costs.
1528 Widmer, DI- Page 11
. 1 Q.is TH COMPANS PROPOSED USE OF TH S6.5 PER MW COST OF
2 WI INGRATION RATE APPROVE BY TH IDAHO COMMSION IN
3 CASE NO. PAC NO.-E--o7, A REASONABLE SOLUTON TO TH
4 COMPAN'S LACK OF VERILE INORMTION?
S A.It is a solution, but it is not the best soluton, because the adopted wind integrtion rate is
6 not basd on the Company's system costs. The rate was adopted spcifically to be use
7 in the deterination of avoided cost rates. To date the Company ha not entered any
8 Idaho bas wind qualifying facilty contracts, so the adoption of the rate for avoided
9 costs has not placed customer at risk of paying too much. However, reuesng recover
10 of over $34 milion for wind integrtion costs in this cas basd on the $6.50 per MWh
11 rate is a different matter as it placs customers at risk of payig too much. .
12
. 13 Q.WHT IS YOUR RECOMMATION?
14 A.The Commission should reject the Company's request for reovery of wind integrtion
1S cost using the $6.S0 per MWh rate approved for avoided cost rates beause their buren
16 of proof ha not been met. Due to the signficant size of thes costs, recovery should
17 ocur though the ECAM. Ony ths way can we be assur that actu wid integrtion
18 costs is recovered. Ths adjustment reduces NPC by $1.88 milion on an Idaho. basis. I
19 also recommend that the Commission adopt the premise of my secondar adjustent 2a
20 OA IT Wind Integrations Costs, so tht the Company not be allowed to recover
21 wholesale wheeling customer wid integrtion costs from retal customers though the
22 ECAM.
23
.24 Q.DO YOU BA VE A SECONDARY RECOMMNDATION?
1529 Widmer, DI - Page 12
. 1 A.Yes. If the Commission rejects my recommendation for this adjusent I recoßUend
'. 2 that the Commssion accept my seconda proposed adjustents 2a OA TT Wind
3 Integration Costs and 2b. Balancing Wind Integrtion Cost, which are discussed in my
4 following testimony.
S
6 Adjustment 1..
7
8 Q.
9
10
11 A..12
13
14
1S
16 Q.
17
18 A.
19
20
21
22
.
OPEN ACCESS TRSMISSION TAR fOAm - WI
INGRATION
DOES TH COMPAN'S OATT TAR INCLUDE A CHGE FOR WI
INGRATION EXENSES FOR WHOLESAL TRSMISSION
CUSTOMERS?
No. Despite being aware of wind integrtion expenses for over six year, bas on the
inclusion of such expenses in its 2004 IRP, the Company has not made a fiing with the
Federa Energy Reguatory Commssion reuestng inclusion of such expenses in its
QATT. So, the Company is attempting to recover these costs frm retal customer.
SHOUL RETAI CUSTOMERS BE REQUID TO PAY FOR THSE
COSTS?
Of coure not. Recovery of these costs frm OATT cusomers is the Company's
responsibilty and they have had over six year to make a fiing with FERC that would
allow them to recover such costs. Retal customers should not be burened with these
costs due to the Compay's failur to make such a fiing.
1530 Widmer, DI - Page 13
.1 Q.
2
3
4 A.
S
6
7
8
9 Q.
10
11 A..12
13
14
1S Q.
16 A.
17
is
19
20
21
22
23
24
.2S
26
27.28
BA TH COMPAN INICATED IF AN WHN THY PLA TO MA A
FIG TO MODIF ITS OATf TO INCLUDE CHGES FOR WI
INGRATION SERVICES TO NON-ÐWN WI FACIS?
Yes. In the stipulation for Oregon Docket UE 216 the Company agreed to make a fiing
before the Feder Energy Regulatory Commission in June 2011. Whle the Company
has finally decided to make ths filing there is nothng that prevented them from making
the filing at a much earlier date.
AR WI INGRATION COSTS INCLUDED IN OTH TRSMISSION
PROVIER OATl?
Yes. As a matter of fact, the Company pays Bonneville Power Admsttion (BPA) for
wind integration costs assoated with the Goonoe and Leanng Junper wid projects
and has included those costs in the wheeling expense.
HA FERC PREVIOUSLY ADDRESED MODMCATION OF TH OATl?
Yes. In Docket No. ER09- 1314-0000, th FERC rued tht applicant, Nortweste
Energy's proposa related to ths issue was not superior to its proforma OATf taff The
FERC stated that:
Rather than proposing a generator reguation charge to recover capacity costs of
holdig additional reserves necessa to meet generator imbaances,
NortWestern's proposal seeks to eliminate any obligation under its Tar to
offer such service in the first instace (at least with respect to intermttent
renewable generators exportng energy out of Nortweste's balancing authority
ar). Accordingly, we find tht Nortwestern's proposa is neither consistent
with nor superior to the prforma Tarff. Our determnation is without prejudce
to Nortwestern proposing to reedy the cost allocation issues discusse in ths
proceeding, consistent with the gudance set fort above.
1531 Widmer, DI - Page 14
.1
2
3
4
S
6
7
8
9
10
11
12
13
14
is
16
17
18.19
20
21
22
23
24
Order Rejecting Proposed Tarff Revisions, FERC Docket No. ER09-1314-0000, Order
No. 20091110 at paagraph 27 (November 10, 2009). The FERC also stated:
In its fiing, NortWestern descrbes a "gap" between its obligations as a
balancing authority and its opportity to recover the cost associated with these
obligations under its Tarff. NortWeste assers that its Tarff does not contan
a mechansm that allows it to recover generator reguation servce costs associated
with trsmission use to export energ from NortWestern's system, which
NortWestern must incur to meet reliabilty standards. Moreover, Nortwestern
contends that its native load customers should not be requid to subsidize the
costs of providing generator reguation service to those generators that export
energy from NortWestern's system. To the extent that NortWestern is not
curently recovering the costs of providing generator reguation serce to
exporting genertors, we agree that a mechansm allowing it to recover those
costs is appropriate.
FERC clearly does not believe that retal customers should pay for the costs of wholesale
customers either and suggested a mechansm should.be allowed to solve the problem. In
the interm; retal customers should not be required to pay for these cost. Accordingly, I
reommend that such wind integrtion costs be excluded from NPC becaus the
Company has had ample opportity to reuest modification of its OA IT to recover
these costs from the pares that caused the Company to incur these expenss and retal
customers should not be bUrdened for the Company's failur to act. This adjustment
reduces NPC by $O.3S milion on an Idao basis.
2S Adjustmt 2b.WI INGRATION COSTS -BALCIG
26 Q.PLEAE EXLA TI COMPNENTS OF TH WI INGRATION
27 COSTS.
28 A.The wid integrtion cost is comprised of Inter-hour and Intr-hour costs. Inter-hour cost
29 is the balancing component and consists of pre-scheduling and hour-ahea balancing..
1532 Widmer, DI - Page is
. 1 Intra-hour cost are the costs carng load following and reguation resees for the
2. varabilty of wind generation. Ths adjustment focuse on the balancing component.
3
4 Q PLEAE EXLA HOW TH COMPAN BALCE ITS SYSTEM FOR
S WI INTEGRATION.
6 A.The .. Company has a varety of options. for balancing. In order of most frequent us
7 balancing is. accomplished though hourly firm wholesae trsations, re-dispatch of
8 wholesae contracts with hourly flexibilty, re-dispatch of generation resours, houry
9non-firm wholesale sales trsactions and wind curilment.
10
11 Q.DOES TH COMPAN'S FIG INCLUDE A DOUBLE COUN OF WI
. 12
13 A.
INGRATION BALCIG COSTS?
Yes. The balancing cost component of wind integtion is double' COÙDted because the
14 Company's filing included actu short-term firm tractions for the period Janua 1,
15 2010 though May 4, 2010, which includes actul hourly firm wholesale trsaons
16 us for wid integrtion balancing and the Compay's separtely calculated wind
17 integrtion costs using the $6.S0 per MWH wid integrtion rate. Ths leaves the
18 question of how to allocate par of the $6.50 per MWh rate to balancing to determe the
19 amount of the double count.
20
21 Q.HOW SHOUL A PORTION OF TH 56.50 MWRATE BE ALCATED TO
22 BALCIG?
23 A.The metod should be. strght forward and based on Company data. With tht
.24 clarfication I believe we should look to the Company's last completed IR to detere
1533 Widmer, DI - Page 16
.i
2
3
4
S
6
7 Q.
8
9
10
11 A..12
13
14
15
16
17
an allocation. In that IRP the Company calculated a tota wind integration cost of $6.92
per MWH consisting of $2.09 per MWh for balancing and $4.83 for intr-hour
integation. Using this information the balancing component for the $6.S0 per MWh rate
ca be calculated by dividing $2.09 per MWh by $6.92 pe MWh and multiplying that
resut (30.2%) times $6.S0per MWh. This produces a double countofS1.96 per MWh.
SHOUL TH 51.9 BE REDUCED FUTH TO COMPNSATE FOR TH
PORTION OF BALCING THT is ACCOMPLISHED BY MES OTH
TH HOURY FI WHOLESAL SALS TRSACTONS INCLUDED IN
GRI?
A fuer adjustent could be reasonable if the inormation were available. However,
the Company stated that there is no offcial Company estimate of how much balancing is
accomplished though the varous means identified above other than to place them in an
order of most to least. Since the Company ha previously stated tht most of its
balancing occur though actu hourly wholesae saes tranactions, which are included
in GRID, $1.96 per MWh should be used to remove the double count. Ths adjusent
reduces NPC by $0.14 milion on an Idao basis.
18
19 Adjustment 3.
20 Q.
NON-FI TRSMISSION
DO YOU AGREE WI PACMCORP'S EXCLUSION OF NON.FI
21 TRSMISSION FROM NPC?
22 A.
23
.24
No. Exclusion of non-firm trsmission is not consistent with actu operations and does
not provide a match between costs and benefits. If the Compay. used an imateal
amount of non-firm trsmission it may be reasonable to exclude it from normalized
1534 Widmer, DI - Page 17
. 1 results. However, that is not the cas. As shown below in Table 2 - PacifiCorp
2 Trasmission Utilization, a substatial amount of non-firm trsmission is utiliz.
3 Durng 2009, non-firm trmission of energy exceeded STF trsmission by over 2.69
4 millon MWh or by more than 6 times. It is rather obvious that non-firm trsmission is
S normally relied.upon to balance and optiize the Company's system.
.
6
7
8 Q.
9 A.
10
11
12
13
14
15
16 Q..17
.n "'T -,.~-~~-~.m~'-"-'''--"'1
L
¡
__, ,_v_~. w-~-~~~.~. __..,,;___ "'_........__..._.+--,..._.....1_.._' ,.......:......
p~_f.~rp.T~~~l~~~~~ti~l~~n
Millons MWh /1
........_... .. . .'l- -.-. . ....!._~._-_...._...;.. . . ..l ~.. ~--'-. .... - _...._........1i ¡ Non-Firm '¡-._..... _................. +... '..- .... ,...._......_..........:
L. ,.~_,__,.~200:: ,._~-_..'"',..,_,!~?~l,_.u_"'200T 0.88:. =,N.y~'....,.. ,.."..,"200L 9.74!
¡ ............. .. ..1200¡ 3.13
r..... ......_...._...... ..,..................._-_.......... .
.,"-v~.__~J...-_....
r4~~~.~yR.3.88'_.._-_......t-..._......
i
1/1 Excludes Cal ISO, intra bubble and transmission already modeled',~~, ~ .,,'... '. ',~Y' .~.._',"'W'~'_W~'~" ' ..'"..__~. ......~..'"__.V_"_fl~_.__. "., ,.., _..., .,..,. ."_., _ " ... ,_'."_' _~ _'.'~~""'~ .',=~" W'W_W'~' -.v....... _ ~,.".""_.... __.
WH DOES TH COMPAN UT NON-FISMISSON?
Non-fi transmission is utilized to balance and optimize the Company's syst. Ths
keeps NPC lower than it would be absent us of non-firm trsmission. Lower NPC is
accomplished though more effcient us of generation and trmission assets in conce
with wholesae trsactions and create more benefits (earngs) for the Compay and its
sharholder. Since these benefits ar derved frm assets and expees aly included
. in rates, non-firm trsmission should be included in NPC to match costs with benefits.
HA TH INCLUSION OF NON-FI TRSMISSION BEEN ADOPTD BY
OTH COMMSSIONS OR BEEN AGRE TO BY TH COMPAN?
1535 Widmer, DI - Page 18
.1 A.
2
3
4
5
6
7 Q.
8 A.
9
10
11
Yes. Inclusion of non-firm trsmission has been adopted in the Company's two largest
jursdictions, Uta and Oregon, The Uta Commission adopted non-firm trission in
Docket No. 07-03S-93. More reently, in the stipulation for Oregon Docket UE-216, the
Company agreed to include non-firm. trsmission links and costs in all futue fiings
using a four-year average.
WHT is YOUR RECOMMNDATION FOR NON-FI TRSMISSION?
Non-firm trsmission link and costs should be modeled in GRID using the sae four-
year average used to normalize thermal generation. Ths will match costs and beefits
and thereby allow cusomers to receive the ful benefits of the system they ar paying for
in rates. The adjusent reduces NPC by $0. i 4 millon on an Idao basis.
. 12
13 Adjustment 4.
14 Q.
1S A.
DUN RESERVE REQUINT
PLEE EXLA TH DUN RESERVE REQUiME ADJUSTNT.
The Company did not model the Duap wind. project as having an operatig resee
16 requireent. This adjusent includes the operatig resere requirement for Duap and
17 incrases NPC by $0.01 millon on an Idaho bais.
18
19 Adjustment 5.
20 Q.
21 A.
RESERVE SHUOWNS
PLEAE DEF RESERVE SHUOWNS.
Resere. shutdown is a state in which a thermal unit was available for serce but not
22 electrcally connected to the grd for economic reasons.
23.
1536 Widmer, DI - Page 19
. 1 Q.HOW AR REERVE SHUOWNS USED IN TH COMPAN'S
2 CALCUTION OF FORCED OUTAGE RATE INUT FOR GRI?
3 A.The Company's forced outage rate calculation excludes reserve shutdown hours frm the
4 denominator. The formula is as follows:
S Forced outge rate = tota lost hours / tota possible hours less planed outages
6 and reserve shutdowns
7 Tota lost hour is the su of forced deratings, forced outaes, maintenance deratings,
8 maintenance outages and planed dertings. Tota possible hours is the su of hour in
9 the perod multiplied by the each thermal plants maximum depndable capacity.
10
11 Q.DOES TH COMPAN'S REERVE SHUWN ADSTM
. 12
13
COMPNENT OF TH FORCED OUTAGE RATE CALCUTION PRODUCE
REONABLE RESULTS?
14 A.No. The Company'sforced outage rates are inconsistent with GRID's calculaton of
15 generation lost due to forced outaes because of inconsistencies between the two
16 calculatons. In GRID forced outage rates are applied to the unts' total possible
17 generation before reserve shutdown and af planed outages, while the Company's
18 forc outage rates usd as an input to GRID ar calculated afer resere . shutdowns and.
19 planed outaes. Due to this difference, the Company's proposed forced outae rates
20 produce too much lost generaion when usd as an input in GRID.
21
22
23
.24
1537
Widmer, DI - Page 20
WHT is YOUR RECOMMNDATION FOR RESERVE SHUWNS?
The Company's forced outage rate calculation is inconsistent with th GRI calcuaton
of generation lost due to forced outages and consequently produces too much lost
generation. To corrct ths problem the Compay's forced outage rate calculation should
be revise by removing the adjustment for reserve shutdowns. Ths adjustment reuces
NPC by approximately $O.OS millon on an Idao basis.
1538
Widmer, DI - Page 21
.1
2
3
4
S
6
7
9 Q.
10 A.
11.12
13
14
15
Adjustment 6.. TOP QF WORI WI IN SERVICE DATE
"
Q. PLEE EXLA TI TOP OF WORL WI ADJUsTM.
A. Durng discovery the Company informed Monsanto that the in-serce date for. ths
project was now expecd to be October 1, 2010 instead of Novembe i, 2010. Ths
adjustment moves the in-servce date to October 1, 2010 and increases .NCby $0.09
millon on an Idaho basis.
8 Adjustent 6&.TOP OF WORLD INCREMEAL WI INGRATION
PLEE EXLA THI ADSTMNT.
As I previously discussed in ths testiony, my primar reommendation is to remove
wind integrtion costs from the Compay's filing so that they are recovered though the
ECAM. If my primar recommendation is not adopted this adjustent will include the
incrementa wind integrtion costs associated with the one additional month that the Top
of World wind project is expeted to be in-service durng 2010.
16 Adjustment 7.CAL isO FEES
DOES TH COMPANS FIG INCLUDE A FU NORM YE OF
CAL iSO WHELG AN SERVICE FEES?
Yes. NPC includes $4.7 millon of these fees on a tota Company basis. However, as
explained later. in my testimony, a significat porton of these fees are not ecnomic
because there ar no wholese trsactions that rely on the Cal iso beyond May 3~ 2010.
WH AN WHN DOES PACMCORP INCUR THSE FEES?
1539
Widmer, DI - Page 22
. 1 A.
2
3
4
s
6
7
8
9
10
11
. 12
13
Historica rerds reveal that most of the tranactions with the Cal ISO. as a counter par
ar incured shortly before or on the actu day of delivery. Due to the Compa's use of
a foreast test period and the fact that the filing was made many month prior to the end
of the forecast test year, trsactions that would incur Cal ISO wheeling and servce fees
had not occured in most month at the time of filing. As Ii result, NPC includes a ful
year of Cal ISO cost, but only wholesale transactions that would generte the Cal ISO
expense prior to May 4, 2010. For ths reason, I reommend that all Cal iso fees
included in the filing for the peod May 4,2010 thugh Decmber 31,2010 be exclud
frm NPC. In addition, I reommend tht act Cal iso fees be usd for the peod
Janua 1, 2010 though May 3, 2010 to match with the actu wholesae trsactions
aleay included in the filing that caused the actu Cal iso cost to be incurd. Ths
adjustment reduces NPC by $0.20 milion on an Idao basis.
14 Adjustment 8.COLSTR PLA OUTAGES
PLEE EXLU HOW TH COMPAN DEVELOPS TH PLA
OUTAGE SCHDUL INUT FOR GRI.
The methodology employed by the Company to normalize planed outages uss 48-
month averge of historical data for the period 2006-2009 to determine the amount of
time the plants ar on outage. Historicaly, these outages ar scheduled durng the sprig
and fall shoulder months when market prices tend to be lower so that replacement power
costs ar kept low and ample energy is available from the marketplace to replac the
generation on outage. After the Company develops the amount of tie the unts were on
outage it develops a normalized outage schedule based on a varety of factors includig
1541 Widmer, DI - Page 24
!.1
i
2
3
4 Q.
S
6 A.
7
8
9
10 Q
11.12
13 A.
14
is
16
17 Q.
18 A.
19
20
21
market prices, historical outages and the amount of units or MW on. outage at a given
point in time.
DO YOU AGREE WI TH COMPAN'S NORM OUTAGE
SCHUL INCLUDED IN GRI?
Not completely. The stag point of Colstrp 3 and Colstp 4 planed outages should
be moved from Septembe to May to bett optimize the timing of the outaes so that
NPC would be lower than it would be using the Compay's outage schedule.
DOES YOUR PROPOSED CHGE TO TH PLAD OUTAGE SCHUL
RESULT IN AN EXCESSIV AMOUN OF CAPACI ON OUTAGE DURG
MAY?
No. The amount of capacity on outge is withn a reonable rage based on a
comparson of actu planed outges compar to planed included in the Company's
filing.
WHT IS YOU RECOMMNDATION?
I recommend that the Colstrp 3 planed outage be moved frm September 18th to May
1st and the Colstrp 4 planed outage be moved from September 30th to May 13th. Ths
adjustment reuces proposed NPC by $0.02 milion on an Idao basis.
22 Adjusent 9.
23 Q..
ENRGY GATEWAY TRSMISSION
PLEE EXLA TH GATEWAY TRSMISSION ADSTMNT.
1542 Widmer, DI - Page 2S
. 1 A.Ths adjustent removes the trmission capacity upgrdes associated with the Energy
2 Gateway trsmission project included in GRID as par of the adjustment to remove the
3 Energy Gateway project from the Compan's filing as recommended by Monsto
4 witness Denis Peseau. Ths adjustment increases NPC by $0.20 milion on an Idaho
S basis.
6
7 Adjustment 10.
8 Q.
9 A.
10
11.12
13
14 Q.
is A.
16
17
18
19
20
21
CROLLA 4 CAPACI
PLEE EXPLA HOW CROLL 4 CAPACI WAS MODELED.
The Company modeled Chona 4 capacity at 387MW even though the capacity wa
upgraded to 395MW not long ago. It appears the reasoning behid modeling the capacity
at 387MW is beause the Company has 387 MW of firm trsmssion rights to move
Cholla 4 Generation.
DO YOU AGREE WI MODELIG CROLL 4 AT 387?
No. Chona is already derated below 387 MW for weekday and week-end forcd outae
rates of S.24% and 7.04%. which respectively produce a derated caacity of 374.3 MW
and 367.2 MW for Chona 4. Since the derated capacity is alreay below the 387 MW of
firm trsmission rights it is not necessa to derate the plant for fi trsmission rights.
Cholla 4 capacity should be modeled at the ful 39SMW. This adjustment reuces NPC
by $0.07 millon on an Idaho basis.
22 Adjusent 11.
23 Q.
.24
MORGAN STANY CAL PRE
PLEE DESCRIE TI TWO MORGAN STANY CAL OPTON
CONTCT INCLUDED IN TH COMPAN'S FIING.
1543 Widmer, DI - Page 26
. 1 A.The Company entered two call option contrcts with Morgan Staney durng Novembe
2 200S for the period June 1.2010 though August 31, 2010. Each contrct provides the
3 . right to cal _ of firm supe-peak product pe hour, exercisable only on the
4 "WECC Pr-Scheduling Day" at an additiona cost of _ per MW for one contrct
S and _ pe MWh for the secnd contrct. For ths right the Company paid a
6 premium of_ for one contrct and _ for the seond contrt.
7
8 Q.WE EITR OF' THSE CAL CONTCTS EXECISED IN. TH
9 COMPAN'S FIG?
10 A.No. Neither contrct was dispatched beause they were not economic for the test yea.
11
. 12
13
Q.HA TH COMPAN PREVIOUSLY STATE A POSmON ON TH
INCLUSION OF CAL OPTON CONTCTS THT AR NOT ECONOMIC?
14 A.Yes. In Oregon Docket UE-191 the Company stated that cal option contrcts should be
1S removed frm NPC ifremoval lowers NPC. In ths cae removal of both Morgan Staey
16 call option contracts lower NPC. For ths reasn, I reommend reoval of Morgan
17 Staey call option contracts p2721S3-6 and p2721S4-7. Ths adjustment lower NPC by
18 $0.17 millon on an Idaho basis.
19
20 Adjustment 12.BEA RI HYRO NORMTION
21 Q.PLEASE EXLA HOW TH COMPAN mSTORICALYNORMD
22 HYRO GENRATION FOR SMA HYRO PROJECT LIK BEA RIR.
23 A.
.24
Small hydr projects generaly have no appreiable storage and are operated as ru of
river projecs where stam flow in is equal to the strea flow out. For these smal
1544 Widmer. DI - Page 27
.1
2
3
4
S Q.
6 A.
7
8
9
10
11.12 Q.
13
14 A.
15
16
17
18
19
20
21
22
23
24
2S
26.
projects, normalized generation is based on an evaluation of 30 year of historical
genertion capabilty. Bear River is somewhat different in that it does have some storage
capabilty.
HOW DOES TH 3Ø-YEAR NORMTION PROCS WORK?
Thirt year of historica generation are usd to develop a medan hydro foreast. When
a new year of data beomes available it becomes the first year data and the prior first year
data becomes the second year data and so fort until the prior 29th yea data becomes the
30th year data and the prior 30th year data is excluded. This provides cusmer and the
Compay with a balanced recovery of generation benefits over the 30-year peod.
HA TH COMPAN'S BEA RIR NORMIZTION DEVITE FROM
TH 3OYE NORMTION METHOD IN RECEN YE?
Yes. The Company's caculation of normalized hydro generation for Bear River began to
exclude flood contrl year from the 30 year historical record stang in 2008. In
response to WIEC Data Request 8.24 in Docket No. 20000';333-ER-08, the Compay
explained how they adjusted Bear River generation and explained their reons for the
adjusents:
The infow forec for Bear River was recently reuced. Year in which surlus
water was releas from Bear Lake ("flood control year") were removed. frm
the historical data set from which the Bear River generation forecast is derved.
Flood control years provide additional water for Bea River genertion. However,
the region is curently impacte by long-term drught conditions and ba on the
low water level in Bea Lake the probabilty of a flood control yearis minial for
the next th yea.
1545 Widmer, DI ~ Page 28
. 1 Q.DO TH DROUGHT CONDmONS PROVIE A LEGITTE BASIS FOR
2 EXCLUDING FLOOD CONTOL YEAR FROM TH CALCUTION .OF
3 NORMIZD GENRATION?
4 A.No. Arbitrarly removing flood control water year data from the historical record beaus
S drought conditions are expeted to persist is not consistent with the 30.Year
6 normalization methodology employed by the Company for other smal projects or the
7 methodology employed for other larger projects. The Bear River methodology is clearly
8 a case of cher picking, which prouces higher NPC because it excludes the nine highest
9 generation year from the thirt-year normalization period. Those nine year have. a
10 median anua generation of S63,114 MWh. In contrt, the years included in the
11 Company's filing have a median generation foreast of20S,S76 MW. Put another way,
12
. 13
the Company's Bear River generaton normalization trfers customer's beefits of
higher hydr generation to shaholders.
14
1S Q.is TH BEA RIR ADSTM SYTRCAL FROM TH
16 PERSPEcn OF PREVIOUS HYRO ADSTM OR FIGS?
17 A.No. To the. best of my knowledge, the Company ha never volunteerd adjustents to
18 increase. hydro generation and decrase NPC bas on an exptation of a good wa
19 year. For the reasons explained above, I recommend that the Company's Bear River
20 normaliztion should be revise to use the same 30-year normalization methodology us
21 for other small hydro facilities. My recommendation reuces NPC by approximately
22 $0.13 milion on an Idaho basis.
1546 Widmer, 01 - Page 29
. . 1 Adjustent 13.
2 Q.
3
4 A.
S
6
7
8
9
10 Q.
11 A..12
13
14
1S
16
17
18
19
20
21
22
23
24
25
26
27
28.29
30
BLACK lULS SIlING
PLEE EXLA TH COMPAN'S MODELG FOR TH BLACKLS
WHOLEAL SALS CONTCT.
The contrct is clasified as a call option contrt in GRID and the contrt tes for
energy such as hourly, daily weekly, monthy and anua take and deliver points ar
inputs to GRID. Based on this infonnation and the Compay's forward prce cure
GRI dispches the contrct durg the highes cost hour based on the assumption that
is what the purhasing entity would do.
DO YOU AGREE WI THS ASUMON?
No. While the assumption may be reasnable for some contrts it rely depnds on the
reuireents and assumptions of the purhasing entity. In the ca of Black Hils, the
act delivery shape of the sae is much flatter th it is modeled in GRID. As shown
below in Grph 1, Black Hills Dispatch, the difference betwee actual on and offpe
deliveries is smaler (flatter) than the difference beteen the Company's modeled on and
off-peak deliveries.
1547 Widmer, DI - Page 30
. 1 Grph 1 - Black Hils Dispatch
60
.- so
40
30
20
10
o
1 2 3 4 51 6 7 8 9 10 11 12
..PAC- GRID BHP HLH
__PAC- GRID BHP LLH
..4-Yr. Avg Actual BHP
HlH
..4-Yr. Avg Actual BHP
llH
AR YOU SURRISED BY TH SHAING DIFRENCE?
No. The difference is not surrising becuse the Company simply does not know what
Black Hils system reuirements and assumptions are. In this case, the assuption tht
Black Hils would do exactly what the Company ths they would do is incorrect and
results in a higher contract cost in GRID than occur on an actu basis. To corrct ths
problem the energy shape should be modeled using the actu delivery shap.
DOES TH .COMPAN USE AN ACTAL INORMTION TO MODEL
OTH ASPECTS OF TH BLACKLS CONTCT?
Yes. The delivery points for the contrt ar modeled based on actu information. The
purse of using actu delivery points is to. captu the expeted cost of the sae beaus
1548 Widmer, DI - Page 31
.1 the energy Can be delivered on both the eat and west side of the Company's system.
2 This fact also suggests that the energy shape should use actual information.
3 Q.DOES TI COMPAN USE ACTAL INORMTION TO MODEL OTH
4 CONTCTS?
S A.Yes. Actu information is also used to model other contracts.For example, energy for
6 the Gem State contrct is modeled for the month of May, June, July and Augu bas
7 on historical information despite the fact that the contrct sttes that deliveres ar
8 expeted to ocur durng June, July and August. The Compay also uses act data for
9 varous inputs of other contr and GRID inputs such GP Cam, APS, Biomass and
10 forced and planed outges etc.
11 Q.WHT is YOUR RECOMMNDATION?.12 A.The Black Hils wholesle saes contrct should be modeled bas on a four a four-year
13 averge of historical dispatch informion.Ths adjusent reduces NPC by $0.08
14 millon on an Idaho basis.
is
16 Adjustment 14.MONA MAT
PLEE EXLA HOW PACMCORP SIZ TI MONA WHOLEAL
MAT HU?
The Company modeled the market capacity as no grveyar market (the five hour ended
1:00 AM though 6:00AM Pacific tie) and 7S MW in all other hours.
DOES TH MONA WHOLESAL SALS MAT CONSIST SOLEY OF
SALES WI A MONA POIN OF DELIVY (PD) DESIGNATION?
1549
Widmer, DI - Page 32
.1 A.
2
3
4
S Q.
6
7 A.
8
9
.
.
10
11
12 Q.
No. According to Confidential Attchment Monsato 2.1 S, the Mona maret consists of
Mona, Gonder, Red Butte, Sierr Pacific system (SPPC) and Nevad Uta Border (N)
PODs.
GIV TIS INORMnON, HA PACICORP ADEQUATELY SIZD TH
MONA MAT?
No. As shown below in Table 3, the Compay's Mona market capacity is considerably
understated based on a comparson wholesale sales volume for the 48-Iíonth peod
ended December 31 ~ 2009.
.....1' täble 3 . ... .. '--r"--'~-"""'-i
....~==--=..==~Or~.:M~rk.ëï .'SizeCo~¡~~~==Ld~d::'" .... .w.
l.dl=.dd-.....__...t~...A~~~~~aYtts . . ..i.....,..dddddd:""
Ë ~::=i~~~i~. January ¡ /1 : 0
,.........__. ...._.r....... ....__..... ....1'.- ..... .. ...¡ February . 11 . , 0
~~ã§~~...~. ......_J1.=~:d.dr.:.::_Q......
,April ¡ /1 I 0't..__ .. . ...--.."'----..---..-§.. .. "........ ..~ ... _____ . ...... , ... . .u.. )¡May .. :... 75 .. ...... 0
?Júìïë--."""('-'--75 .._.....", .....Ö....
¡July ; 75i' 0
!Äugušt-_.... ---.-f5........ ...... 'Ö".
l~o;r~r:~d~=l~~~.::.::.:=Ed.= .~..:...:...J:.....iNowmbei 75 i 0 ¡t-.. ..._..+....._...._.__.,......__.-..... ..:... ..... .
~ ~.~rr.~!l_......_?~.."'....L. .. 0
1'-.dN~td~~i~~!l~.~.~Û!t:~l.n~. us~ .~~t~¡¡.1?01 0 data ...d:_._...__...
.......1..,
Actuâr4a:citìAv..- .
All otiii'HOïiSr-jiiäf" ¡'. .... ..M'.mo . ...,....zm .. . :i . .. ./1 27:i'¡ ..24.....j" .... - ._._...--~, - . ."" - ."..,.~/1 20
.... .if...d...:::d.r.....ddJ~..-._. i75 : 17
.. ."183.......,. . '.2"1'
.2?~..._....L_..?~.......296 44
.'~¡ó" ..d:I...::.d_~.::~.--1151 ¡ 25 i'" .~..........._.._._~_.._..._j132 í 24 !.. .... ...._.._......_............._-_......,167 . 17 ¡".),_,_~.__~.~u,u_._""._,..__~,
WH DID YOU USE A 48MONT AVERAGE FOR TH COMPARN
13 SHOWN IN TABLE 3?
1550 Widrer~ DI - Page 33
.1 A.
2
3
4
S Q.
6
7 A.
8
9
10
11
12.
.
13 Q.
14
15 A.
16
17
18
19
20
21 Q.
22
I used a 48-month average to be consistent with the.Company's normalization of theral
genertion, STF trsmission capacity and grveyard market caps, which. all use a 48-
month normalization period.
WHT IS YOUR RECOMMNDATION FOR CUGTH CONSIDERLE
UNERTATEME OF TH MONA MAT?
The Mona market capacity needs to be sized appropriately to provide a proper match of
cost and benefits. I reommend tht the Mona maket capacity be corrcted by using the
48-month average capacities shown above in Table 3. Ths adjustment reduces NPC by
approxitely $0.03 millon on an Idaho basis.
Adjustment 15.NAUGHTON 3 OUTAGE
PLEAE EXLA TH CAUSE OF TH NAUGHTON 3 OUTAGE WHCH
STARTED MAY 8, 200 AN ENED MAY 26, 200.
The Company's contrtor Siemens failed to complete the Naughton 3 overhaul on
schedule per contr ter due to por performance. The major reons for the faiure to
DID TH COMPAN RECIVE COMPENSATION FROM SIES FOR
FAIUR TO MEET CONTCT TES?
1551 Widmer, DI - Page 34
I: ..
. 1 A.
.
Ii.
i
.
Yes. Pusuat to the terms of the contr the Company reeived a $SOO~OOO liquidated
2 damages payment in June 2009 tht was booked to FERC account SSS purha power
3 expese.
4
S Q.DID IDAHO RETAa CUSTOME RECEIV AN ALOCATED SHA OF
6 TI 550,00 PAYMNT?
7 A.
8
9 Q.
No. The ECAM did not become effective until July 1,2009.
DO YOU AGREE WI TI COMPAN'S INCLUSION OF TH OUTAGE
10 EVENT IN NPC?
11 A.
12
13
No. The outage was caused by poor performance of the Company's contrctor (Siemen)
and is therefore an imprudent outage tht should not be included in the calculation of
NPC. Furerore, the Company has aleady been compensated. for the outage purt
14 to the terms of their contrct though the $SOO,OOO liquidate daage payment it
1S
16
reeived. Inclusion, of the outage in NPC would result in the Company collecg outage
costs twce, once frm customers and once from Siemens. For these reasns, I
17 remmend that the outage be removed frm the caculation of NPC. Ths adjusent
18 reduces NPC by approximately $0.03 millon on an Idao basis~
19
20 Q.
21 A.
DOES THS CONCLUDE YOUR TESTIONY?
Yes
1552 Widmer, DI - Page 3S
.
..
.1
2
3
4
5
Q.AR YOU THE SAM MA T. WIDMER THAT PREVIOUSLY TESTIFIED
IN TIDS PROCEEDING?
A.Yes.
Q.WHT IS THE PUROSE OF YOUR SUR-REBUTTAL TESTIMONY?
A.My testimony responds to Dr. Shu's rebutt testiony. The adjustment numbers in my
6 following testimony refer to adjustents shown on Table 1 of my dirct testiony.
7 Adjustment 1.ARIZONA PUBLIC SERVICE ("APS") SUPPLEMENTAL
8 ENERGY
9 Q.
10
11 A.
12
.13
14
DO YOU AGREE WITH DR. SHU'S MODIFICATIONS TO THE APS
SUPPLEMENTAL CONTRACT?
Yes. Dr. Shu's proposed modification to my adjustment accepts the premise of my
proposed adjustment that PacifiCorp would not exercise its contract option uness it is
economic. This increases my proposed adjustment from a tota PacifiCorp NPC
reduction of $1.9 milion to a reduction of $2.6 milion.
15 Adjustment 2.
16 Q.
17
18 A.
19
20
21 Q.
22
23.
WIND INTEGRATION COSTS
DR. SHU STATED THAT YOU DIDN'T EXPLAIN WH THE $6.50 PER MWh
WID INTEGRATION RATE IS NOT APPROPRIATE. IS THAT TRUE?
Not at alL. In direct testimony I stated tht PacifiCorp had not met its burden of proof for
cost recovery because the $6.50 rate is not cost based and the only way we could be
assured that customers are not paying too much is to allow recovery though the ECAM.
ARE YOU AWARE OF AN DECISIONS THAT REJECTED RECOVERY OF
WIND INTEGRATION COSTS BECAUSE THE PROPOSED RATE WAS NOT
COST BASED?
1553
..'
Yes. FERC rejected Puget Sound Energy's request for a modification to its OATT to
allow it to recover wind integration costs from trsmission customers becaus the
proposed rate was not cost based. In that order FERC made the followig statements and
other which are supportive of my position:
We reject the taff sheets containing Pugets proposed Wind Following Servce
because Puget has not shown that the rate it proposes to charge for the servce is
just and reasonable. .... the Commssion must ensure that ratepayers ar protected
from rate proposas-such as the one proposed by Puget here-that are not shown
to be related to actu demonstrable costs incured in providing servce. (PLO
pargraph 31 Docket No. ERlO-1436-000 Order Rejecting Proposed Tarff
Revisions)
DOES YOUR RECOMMENDATION TO REJECT RECOVERY OF WI
INTEGRATION COSTS BASED ON $6.50 PER MW FORESTALL
RECOVERY OF THE COMPAN'S ACTUALLY INCURRD WI
INTEGRATION COSTS?
No. It simply allows recovery thugh the ECAM so customers do not pay too much.
DOES DR. SHU PRESENT A VALID ARGUMNT THT IF WID
INTEGRATION COSTS AR RECOVERED THROUGH THE ECAM THE
SAME SHOULD BE DONE FOR WHOLESALE SALES REVENUES?
No. The method of calculating normalizd wholesale sales revenues has been accepted
for a long time. On the other hand, there is not consensus on how to calculate wid
integration costs. The Company's August 31, 2009 wid integration study stted that
there is no industr standard design of costing methodologies and the understading of
wind impacts is evolving. The pertinent pages of the study ar provided as Exhbit MTW
235 (MW-2).
1554
Widmer, SUR - Page 2
.1 Q.
2
3
4 A.
S
6
7
8
9
10
11
12
.13 Q.
14
15
16
17
18 A.
19
20
21
22
23.24
25
DO YOU AGREE WITH DR. SHU'S STATEMENT THAT YOU ONLY NEED TO
LOOK AT BPA WIND INTEGRATION COSTS TO DETERMNE THAT THE
COMPAN'S COSTS AR REASONABLE?
No and apparently neither does PacifiCorp. In the same August 3 i, 2009 wind
integration stdy referenced above, PacifiCorp cautioned againt comparing PacifiCorp
costs with other utilty studies because there is 1) no industr stadard design different
cost components are incorprated into the studies and different modeling approaches and
tools are applied, 2) costing methodologies and understading of wind impacts is
evolving rapidly as utilties gai operating experience, 3) utility system differences, 4)
study assumptions (e.g., transmission sufciency, wid location diversity, regional
coordition, wind forecast improvement expectations), and 5) conservative vs.
optimistic bias.
SHOULD TIl $6.63 PER MWH RATE FOR WID INTEGRATION
APPROVED BY THE PUBLIC SERVICE COMMSSION OF UTAH IN
DOCKET NO. 09-035-23, PROVIDE A REASONABLE BASIS FOR APPROVIG
THE COMPAN'S REQUEST FOR RECOVERY OF WIND INTEGRATION
COSTS USING $6.50 PER MW?
No. First, PacifiCorp has admtted on numerous occasions that it canot calculate the
actul cost of wind integration and has also stated that they have not estiated actul
costs, which could be used for verification of the reasnableness of wid integration cost
forecasts. In response to Monsato Rebuttl 1.6, when asked if they had calculated an
estimate of the actu wid integrtion cost for 2008 and 2009 PacifiCorp stated:
No estimate has been made. Wind integrtion costs are largely drven by the
increased demand on operating reserves required to manage the volatilty of wid
generation on PacifiCorp's system. Whle these operating reserves were held in
1555
Widmer, SUR - Page 3
.1
2
3
4
5
6
7
8
9
10
11
12
13
14
.15
16 A.
17
18
19
20
21
22
23
24
25
26
27
28
29
30.31
32
2008 and 2009 consistent with the level of wind generation on PacifiCorp's
system at that time, it is not possible to differentiate the amount of operating
reserves held to integrte wid from the operating reserves held for other system
varables.
The point here is that if PacifiCorp canot provide an estimate of actul wind integrion
costs how can we believe their forecasts of wind integration costs are reasonable. As
discussed previously in my testimony~ it certnly wasn't good enough for FERC to
provide Puget recovery, so it should not be good enough to provide recovery in ths
docket.
Adjustment 2a.OPEN ACCESS TRASMISSION TARFF (OATT) - WIND
INTEGRATION
Q. DO THE FERC ORDERS REJECTING NORTHWSTERN'S AN PUGET
SOUND ENERGY'S WIND INEGRATION REQUESTS IMPLY THAT FERC
WILL NOT ALLOW RECOVERY FROM TRASMISSION CUSTOMERS?
No. The Puget Sound Energy order explicitly stated FERC would provide cost recovery
if certn requirements were met. In the Puget Sound Energy order FERC made the
following statements in paragraphs 34 and 35:
. .. we find that Puget has not shown that its proposed proxy rate is just and
reasonable. In the context of generator imbalance charges, to which Puget cites as
support for its proposed rate schedule, the Commssion ha explaied tht while it
will allow recovery of legitimate and verifiable opportty costs, it would do so
only where trsmission providers clearly explain how opportty costs would
not lead to over recovery of costs. (page 11, paragrph 34 Docket No. ER10-
1436-000 Order Rejecting proposed Tarff Revisions)
Based on the information submitted, we canot find that Puget s proposed rate is
a reasonably accurate representation of the opportty costs Puget incurs in
providing a following service to wind resoures. Moreover, Puget has not
explained its proposal for self-scheduling ths service, including the tyes and
locations of resources that may be used. We therefore reject Puget s proposed
Wind Following Servce rate, without prejudice to Puget filing a new rate
1556
Widmer, SUR - Page 4
.1
2
3
4 Q.
5
6
7
8 A.
9
10
11
12
13
.14 Q.
15
16
17 A.
18
19 Q.
20
21 A.
22
23
proposal consistent with the discussion in ths order. (page 12, pargraph 35
Docket No. ER 10-1436-000 Order Rejecting proposed Tarff Revisions)
SHOULD THE FACT THAT PACIFICORP PLANS TO FILE A FERC RATE
CASE, WITH A WIN INTEGRATION CHAGE IN ITS TRASMISSION
TARFF, NO LATER THA JU 1,2011 IMPACT THE COMMSSION'S
DECISION IN TilS CASE?
No. Customers have already paid too much for transmission customer costs than they
should not have paid for in the first place. By the time the Company seeks recovery of
wind integrtion costs from trsmission customers it will have taen approximately
seven years to make such a request. It is time that the responsibilty for recovery of these
costs from transmission customers is placed with the Company. This should create more
impetus to resolve the issue before FERC.
IS THERE A POTENTIAL OVER RECOVERY ISSUE IF THE IDAHO
COMMISSION PROVIDES RECOVERY OF TRASMISSION CUSTOMER
WID INTEGRATION COSTS FROM RETAIL CUSTOMERS?
Yes. If FERC approves PacifiCorp's June 2011 filing wid integration costs could be
over collected, once from retal customers and once from tranmission customers.
DO YOU AGREE THAT STATELINE SHOULD BE REMOVED FROM YOUR
OATT WID INTEGRATIONADJUSTMENT?
Yes. The value of ths seconda adjustment would change from a tota PacifiCorp
reduction in NPC of $6.4 milion to a reduction of $4.3 millon.
24 Adjustment 2b..WID INTEGRATION COSTS - BALANCING
1557
Widmer, SUR - Page 5
.1 Q.
2
3
4
5
6
7 A.
8
9
10
11
12
13
14
15.16
17
18
19
20
21
22 Q.
23
24
25
26
27 A.
.28
DR SHU IMPLIES THAT YOUR PROPOSED SECONDARY ADJUSTMENT TO
REMOVE A DOBULE COUNT OF WIND INTEGRATION COSTS SHOULD BE
REJECTED BECAUSE SHORT-TERM FIRM WHOLESALE TRASACTIONS
AR ONLY A SMALL PORTION IF ANY OF THE RESOURCES THAT
PACIFICORP UTILIZES TO INTEGRATE GENERATION FROM WIND
FACILITIES INTO ITS SYSTEM. DO YOU HAVE AN COMMENTS?
Yes. Her arguent is inconsistent with their response to Monsanto 3.3 7. In that response
the PacifiCorp stated:
Actions taken to balance the system for inter-hour wid integration include the
following in the order of expected volumetrc use:
Hourly firm wholesae transactions
Redispatch of wholesale contracts with hourly flexibilty
Re-dispatch of generation resources
Hourly non-firm wholesale transactions
Wind curilment
Based on ths inormation it is clear that short-term firm wholesale tranactions are
heavily used to integrate wind resources. So, it is rather obvious that if the Commssion
provides recovery of wind integration costs using the $6.50 per MWh that the additional
wid integration cost captued though short-term firm wholesale saes is a double count.
REALIZING THAT A PORTION OF THE INTER-HOUR WI
INTEGRATION BALANCING MAY HAVE BEEN ACCOMPLISHED BY.A
MEANS OTHER THA SHORT-TERM FIRM TRASACTIONS, DID YOU
EXPLORE WHETHER THERE WAS A WAY TO REDUCE THE SIZE OF THE
ADJUSTMENT?
Yes. Unfortately, the Company was unable or unwilling to provide the requested
informtion. Monsanto sent data request Monsanto 6.16 to the Company to determine
1558
Widmer, SUR - Page 6
.1
2
3
4
5
6
7
8
9
10
11
12
13
14
is
16
.17
is
whether there was a reasonable basis to reduce the size of the adjustment below an
assumption that 100% of wid integrtion balancing is covered though short-term firm
wholesale trsactions. The followig is the request provided to the Company and the
Company's response.
Monsanto Data Request 6.16
Please provide the Company's estimate of percentages for each category
listed in Monsanto 3.37.
Response to Monsto data Request 6.16
There is no offcial Company estimate of these percentages. System
conditions var extrmely from season to season and even day to day and
volumetrc results will be likewise volatile.
Given ths response I found no basis for reducing the size of the adjustment because a
portion of the balancing was accomplished by a means other tha short-term firm
wholesae transactions. If the Company could provide inonnation that demonstrtes the
percentage of system balancing costs accomplished through short-term firm trsactions I
would be willng to reduce the size of my adjustment.
19 Adjustment 3.NON-FIRM TRANSMISSION
20 Q.DO YOU AGREE WITH DR. SHU'S PROPOSED MODIFICATION TO YOUR
21 NON-FIRM WHELING ADJUSTMENT?
22 A.I have some reservations about the proposed modification to my proposed adjustment,
23 which I do not have time to address in this case. However, I am willng to accept the
24 proposed modification for this case. Ths reduces the size of the adjustment from a tota
25 PacifiCorp NPC reduction of $2.4 millon to a reduction of approximately $1.2 millon.
26
.
1559
Widmer, SUR - Page 7
.:
3
4
S A.
6
7
8
9
10
11 Q.
12
.13
14
1S A.
16
17
18
19
20
21
22
23
.24
Adjustment 5.RESERVE SHUTDOWNS
Q. DO YOU AGREE WITH DR. SHU'S STATEMENT THAT PACIFICORP'S
CALCULATION OF FORCED OUTAGE RATES IS CONSISTANT WITH HOW
GRID APPLIES THEM?
No. If GRID simulated forced outages with a Monte Carlo simulation there would not be .
an issue. With a Monte Carlo simulation the forced outage rate would apply both when a
unt is rung and when a unit would be on reserve shutdown but for the forced outage.
GRI simulates forced outages by derating the unt capacity. As such, the forced outage
rate applies when the unit is rug. Thus, GRID overstates the forced outage and
understates generation.
HAVE YOUR PREPARED AN EXAPLE THAT ILLUSTRATES THE
PROBLEM WITH THE PACIFICORP'S FORCED OUTAGE RATE
CALCULATION AS IT is USED IN GRID AND DEMONSTRATES THAT
YOUR ADJUSTMENT SOLVES THE PROBLEM?
Yes. The first line with numbers on Exhibit 236 (MW-2) shows how PacifiCorp records a
forced outage using standard industr practice for a 100 MW unit that ru 16 hours per
day, has one 2S day forced outage and is on resere shutdown 8 hour per day. For the
year the unt rus 5,440 hours and generates 544,000 MWh (16*340*100). Using
PacifiCorp's method the unt has a 9.9% forced outage rate. The second line with
numbers shows GRID modeling with PacifiCorp's forced outage rate. As shown, GRID
simulates the forced outage by derating the unt capacity by 9.9%. That is, GRI does
not put the unit on forced outae for 25 days. For the year using GRID's simulation and
PacifiCorp's calculation, the unit rus 5,840 hour and generates 525,987 MWh
(16*365*90.1) or 18,013 MWh too few. The thd line with numbers shows how I
1560
Widmer, SUR - Page 8
.1
2
3
4
5
6
7
propose to calculate the forced outage rate to solve the problem of too many forced
outae hours and not enough generation. Using my proposed calculation the forced
outae rate would be 6.85%. The four line with numbers shows GRID modeling with
my proposed calculation. For the year using GRID's simulation and my proposed
calculation the unt rus 5,840 hours and generates S44,000 MWh as would have
happened on an actu basis. Clearly, my propose adjustment is supported by logical
and analytícal reasoning contrar to Dr. Shu's statement.
CAL iSO FEES8 Adjustment 7.
9 Q.
10
11 A.
12
.13
14
15
16
17
18
19 Q.
20
21
22 A.
23
.24
DO YOU AGREE THAT CAL ISO ACTIVITES AR REFLECTED IN GRID AS
PART OF SYSTEM BALANCING WHOLESALE SALES AN PURCHASES?
No. Cal ISO activities can not be reflected in GRI uness the wheeling capacity
acuied from Cal ISO is included in GRI. In ths case the only transmission that could
be considered to be Cal ISO transmission is a lin from 4C to SP15. However, the SP15
market was modeled with a zero market capacity so the wheeling does not allow Cal ISO
wholesales transactions. PacifiCorp's modeling is equivalent to charging an individual
for muncipal water when they don't have a muncipal water pipe connected to their
dwellng and the ,water used by the individua comes from a well located on their
propert that they own.
DO YOU HAVE AN COMMENTS REGARING THE STATEMENT THAT
REMOVING CAL ISO AS A COUNTER PARTY WOULD LIMT THE
COMPANY'S OPTIONS TO BALANCE ITS SYSTEM AND DRIVE UP NPC?
Yes. I am not recommending that Cal ISO be removed as a counter par. In fact my
adjustment allows recovery of matched Cal iSO costs and benefits for the period Janua
1, 2010 through May 3, 2010. It also removes Cal iSO wheeling expenses and fees for
1561
Widmer, SUR - Page 9
.1
2
3
4 Q.
5
6
7 A.
8
9
10
11
12
.13
the period May 4,2010 though December 31,2010 where there is not a match between
costs and benefits because NPC does not include any wholesale transactions that could be
considered a surogate for Cal ISO transactions as explained above.
SHOULD ADOPTION OF THE CAL ISO ADJUSTMENT CAUSE PACIFICORP .
TO REMOVE CAL ISO AS A COUNTER PARTY' FOR ACTUAL
OPERATIONS?
No. Adoption of my adjustment would not merit such an action on the PacifiCorp's par.
In actual operations PacifiCorp should stil tre with Cal ISO as long as the trasactions
are the most economic at the time. If they were to remove Cal ISO as a counter par it
would be an imprudent decision on PacifiCorp's par as long as Cal ISO transactions are
the most economic.
CROLLA 4 CAPACITYAdjustment 10.
Q. DR. SHU STATED THAT THE CHOLLA 4 ADJUSTMENT IGNORES THE
PHYSICAL CONTRANTS OF THE DELIVRY OF POWER FROM CHOLLA.14
15
16 A.
IS THAT AN ACCURATE REPRESENTATION?
No. As shown below in Table 1, my Cholla 4 adjustment does not ignore the physical
17 constrnts of delivering energy above the 387MW firm trsmission constraint because
18 the derated capacity is well below the constrnt.
.
1562
Widmer, SUR - Page 10
.
.
1
2
3 Q.
4 A.
S
6
7
Table 1
Cholla 4 Modeling Comparison
PacifiCorp Modeling Monsanto Modeling
HLHMW LLHWM HLHMW LLHMW
Name Plate Capacity 395 395 395 395
Transmission derate /1 8 8 0 O.
Capacity prior to EFOR Dearate 387 387 395 395
Forced Outage Derate /2 5.24%7.04%5.24%7.04%
Derated Capacity 366.72 359.76 374.30 367.19
Incremental Generation Available 7.58 7.44
Pacificorp is not modeling
/1 Pacificorp has 387 MW of firm transmission rights
/2 PacifiCorp proposed EFOR
DO ACTUAL RESULTS SUPPORT YOUR ADJUSTMENT?
Yes. Confdential Attchment Monsanto 2.41 shows that Cholla 4 only operated at or
above 387 MW for one hour durng 2009. In fact, durng most hours in 2009 Cholla
operated at a level well below 387MW, thereby demonstrating that the firm trsmission
constrait was not an issue.
8 Adjustment 11.
9 Q.
10
.11
MORGAN STANLEY CALL PREMIUMS
DO YOU AGREE WITH THE ANALOGY THAT THE ADJUSTMENT TO
REMOVE THE CALL PREMIUMS FOR TWO MORGAN STANLEY
CONTRACTS IS SIMILAR TO REQUESTING A REFUND OF AN AUTO
1563
Widmer, SUR - Page 11
e 1
2
3 A.
4
5
6
7
8 Q.
9
10
11 A.
12
e13
14
15
16
17
18
19 Q.
20
21
22 A.
23e
INSURCE PAYMENT EVERY YEAR YOU HAVE NOT BEEN IN A
TRAFIC ACCIDENT?
No. As I will explain below the Company's request for recovery of premiums associated
with these contracts is akin to trg to get someone to pay for flood insurce when they
live on a hil hundreds of miles from a body of water because the likelihood of customers
ever receiving a benefit from these call option contrts was very small at best at the time
of execution.
WHN PACIFICORP EXECUTED THESE CONTRACTS IN 2005 WAS THERE
A REASONABLE PROBABILITY THAT CUSTOMERS WOULD BENEFIT
FROM THE CONTRACTS mROUGH RETAIL RATES?
No. Both contrts were way out of the money when they were executed during 2005
and therefore, were unikely to provide a benefit to customers. To put this into
perspective the actual market price of PacifiCorp's STF wholesale purchases durg the
representative months of 2005 averaged approximately $57 per MWh. In contrast, due to
stre prices in excess of $1001MWh and premiums paid for the right to tae power, the
market price of energy would have had to exceed $130.0 per MWh for customers to
breakeven. Therefore, it was very unikely that customers would benefit though retal
rates.
IF IT WAS UNLIKELY CUSTOMERS WOULD BENEFIT THROUGH RETAIL
RATES, WAS IT LIKELY THAT CUSTOMERS WOULD BENEFIT FROM A
PASS-THROUGH MECHASM?
No. PacifiCorp did not have an ECAM or PCAM mechansm at the time the contracts
were executed.
1564
Widmer, SUR - Page 12
.1
2
Q.
3 A.
IF CUSTOMERS WERE UNIKELY TO BENEFIT WHO WOULD HAVE
BENEFITED FROM THESE CALL OPTION CONTRACTS?
The most likely beneficiar was stockholders, especially if customers to paid for the call
4 option premums. Ifwas for these reasons PacifiCorp agreed in Oregon Docket UE-191
5 tht call option contrts should be removed from NPC if their removal lowered NPC.
6 Adjustment 12.
7 Q.
8
9 A.
10
11
12
.13 Q.
14
15
16
17 A.
18 Q.
19
20
21 A.
22
23.
BEAR RIR HYRO NORMIZATION
DO YOU AGREE THAT THE IMPACT OF THE 2003 FERC LICENSE FOR
PROJECT #20 SHOULIl BE MODELED FOR BEAR RIVER?
To the extent that the constrnts are not included in the PacifiCorp data that I used for
my adjustment, the impacts should be modeled. This adjustment to my adjustment would
need to be calculated by PacifiCorp because I do not have the necessar inormation and
tools to model the impact.
DO THE BEAR RIER OPERATING AGREEMENTS PROIDBIT
WITHRAWING WATER FROM BEAR LAK FOR FLOOD CONTROL
PURPOSES IF THE LAK ELEVATION DROPS BELOW A CERTAIN LEVEL
DURIG ACTUAL OPERATIONS?
Yes.
DO THE OPERATING AGREEMENTS OR THE UNQUE NORMIZATION
OF HYDRO GENERATION PREVENT THE INCLUSION OF FLOOD
CONTROL YEAR FROM NORMIZED GENERATION?
No. First, hydro generation is normalized with the curent generation capabilties of each
project and historical stream flows. Second, there is nothig in the operating agreements
that place a requirement on how generation is normalized. For all other hydro facilties
1565
Widmer, SUR - Page 13
.1
2
3 Q.
4
S
6 A.
7 Q.
S
9 A.
10
11
12
.13
14
1S
PacifiCorp uses a period of 30 years or more to normalize generation. In the case of Mid
Columbia projects, the Company uses 70 years.
DOES PACIFICORP'S NORMIZATION OF OTHER HYDRO RESOURCES
EXCLUDE mSTORICAL YEARS FROM THE NORMIZATION
CALCULATION DUE TO CURNT EXPECTATIONS?
No.
CAN YOU PROVIDE AN EXAPLE OF WHRE PACIFICORP'S HYRO
GENERATION NORMLIZATION IS INCONSISTANT?
Yes. An example would be normalization of the Mid Columbia projects, which includes
the exceedingly poor dust bowl years and other very poor hydro year. Following on
PacifiCorp's Bear River logic, the Dust Bowl years and other very poor hydro year
should have been removed from the generation normalization calculation because
expectations at the time of the filing did not include an expectation of Dust Bowl like
yeas in the test year or even the following year. The conclusion here is that there is no
valid reason to model Bear River differently than other hydro projects are modeled.
16 Adjustment 13.
17 Q.
is
19
20 A.
21
22 Q.
23.
BLACK mLLS SHAING
IS CHARACTERIZATION OF THE BLACK HILLS SHAING ADJUSTMENT
AS THE COMPAN ACTS RATIONALLY AND BLACK mLLS ACTS
IRTIONALLY ACCURATE?
No. The correct characterization would be that Black Hils acts rationaly and PacifiCorp
has no knowledge of what is optimal for Black Hils as PacifiCorp has already admitted.
DO YOU AGREE THAT THE BLACK mLLS ADJUSTMENT IS CONTRAY
TO YOUR APS ARGUEMENT?
1566
Widmer, SUR - Page 14
.1 A.
2
3
4 Q.
5
6
7
8 A.
9
10
11
12 Q.
.13 A.
.
No. PacifiCorp has the option to tae energy pursuat to the term of the APS contract
and would do so only when it is economic. The same holds tre for Black Hils, who
would only dispatch their contract when it is economic to them.
WOULD ADOPTION OF THE BLACK IDLLS SHAING ADJUSTMENT
REQUIRE FOR CONSISTENCY AN FAIRNSS THAT ALL OTHER
FLEXIBLE CONTRACTS AN RESOURCES BE DISPATCHED IN A SIMILAR
MANNER?
No. GRID was designed to dispatch the resources which PacifiCorp has control in the
same way they operate their system. That should not change with the adoption of an
adjustment that dispatches the Black Hils contract the way Black Hils dispatches their
system.
DOES TIDS CONCLUDE YOUR SUR-REBUTTAL TESTIMONY?
Yes.
1567
Widmer, SUR - Page 15
.
.
.
20
21
22
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Mr. Woodbury, do you have
4 questions?
5 MR. WOODBURY: Madam Chair, Staff has no
6 questions, thank you.
7 COMMISSIONER SMITH: Thank you.
8 Mr. Purdy.
9 MR. PURDY: No questions.
10 COMMISSIONER SMITH: Questions? Anybody have --
11 MR. OLSEN: No questions, Madam Chair.
12 MR. OTTO: No questions.
13 COMMISSIONER SMITH: Mr. Hickey.
14 MR. HICKEY: I do. Thank you, Commissioner
15 Smith.
16
17 CROSS-EXAMINATION
18
19 BY MR. HICKEY:
Q.Good afternoon, Mr. Widmer.
A.Good afternoon, Mr. Hickey.
Q.Is it fair to say that you are being paid today
23 by Monsanto to criticize the net power costs identified by
24 Rocky Mountain Power's generation and regulation initiatives
25 model, or the GRID model?
1568
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
20
21
22
1 A.i would say -- i would put ita little
2 differently than "criticized." I'm being paid to make sure
3 that the results produced by the model are reasonable on a
4 normalized basis.
5 Q.Okay, we'll go with that for a while, Mr. Widmer.
6 You propose adjustments totaling $47.02 million
7 through 15 different adjustments. Isn't that a fact?
8 A.It's actually -- the revised number is 47.0
9 million.
10 Q.I've been trying to stay with it, but it's now
11 47.09?
12 A.47.0. That's the number I updated just a few
13 minutes ago in my direct.
14 Q.So the last one went from 47.02 to now 47. OO?
15 A..01.
16 Q..01 ?
17 A.Yeah.
18 Q.Okay. And to be fair, a couple of these
19 adjustments would actually increase net power costs?
A.That's correct.
Q.In a minor way?
A.Actually, not. The Top of the World adjustment
23 was about 1.6 million on a total Company basis. It was a
24 decent size adjustment.
25 Q.Prior to 2008, it's true, isn't it, Mr. Widmer,
1569
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 that you appeared as a witness on behalf of Rocky Mountain
2 Power and PacifiCorp supporting the GRID model?
3 A.I did.
4 Q.Correct?
5 And, in fact, the GRID model was implemented
6 during your tenure with Rocky Mountain Power. Isn't that a
7 fact?
8 A.That's correct.
9 Q.I'm going to hand you a couple of exhibits, the
10 first of which is Exhibit 89, and the second will be 90.
11 (Rocky Mountain Power Exhibit Nos. 89 and
12 90 were marked for identification.)
13 Q.BY MR. HICKEY: Handing you first what's marked
14 as exhibit I'll represent to you will be marked as Exhibit 89.
15 Do you recall seeing that Data Response -- Data Request and
16 Response before?
17 A.I don't, but doesn't mean I didn't see it. I've
18 seen probably thousands of Data Requests.
19 Q.Okay, not surprised to hear that, but just to
20 quickly--
21 MS. DAVISON: Excuse me, Madam Chair, I did not
22 get a copy.
23 MR. HICKEY: Oh, I thought Mr. Budge would pass
24 those out.
25 MS. DAVISON: All right, I have it. I'm sorry
1570
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 for the interruption.
2 Q.BY MR. HICKEY: So, is it true that you were
3 retained by the Wyoming Industrial Energy Customers in the
4 state of Wyoming in a proceeding in 2Q09?
5 A.Yes.
6 Q.And that was what's been called the Wyoming 2009
7 rate case that was actually tried in April of this year.
8 Correct?
9 A.That's correct.
10 Q.And your client, Wyoming Industrial Energy
11 Customers, asked for copies of all the testimony that you have
12 filed in support of net power costs while you were employed by
13 the Company. Correct?
14 I -- subj ect to check, I'll agree with that.A.
15 Okay. And this is a summary of the differentQ.
16 states and the different times that you appeared in support of
17 the GRID model. Correct?
18 A.Subj ect to check.
19 Well, and then let's go to Exhibit 90 if youQ.
20 would. Is this the more detailed breakdown by docket number
21 and by references and by identification of direct and/or
22 rebuttal testimony or supplemental testimony that you filed in
23 all of these dockets over all of these years supporting GRIDs,
24 Mr. Widmer?
25 I'll agree with that, subj ect to check.A.
1571
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 Q.If I represent to you that the total of these
2 dockets identified within the Data Request is 36, do you have
3 any reason to disagree with that?
4 A.No.
5 Q.And isn't it true that in those 36 cases, you
6 were appearing in support of the setting a base net power cost
7 supported by the Company?
8 A.That's correct.
9 Q.And you had previously been asked in the capacity
10 of supporting the net power costs of the Company to address the
11 issue of wind integration charges, hadn't you?
12 A.I was.
13 Q.And, in fact, again in the state of Wyoming and
14 in an avoided cost docket in 2006, you spoke in favor of the
15 necessi ty of a wind integration charge as being a component of
16 net power costs. Isn't that true?
17 A.I did speak of it in that nature because wind
18 integration drives up the cost of carrying reserves and the
19 cost of carrying reserves on the system has a direct bearing on
20 the avoided costs that the Company would pay utili ties. So,
21 even though there's been a huge amount of uncertainty relative
22 to what the real number is for wind integration, it is clear
23 that in order for a QF to receive a fair payment, something
24 needed to be included, so, yes, I did recommend that wind
25 integration costs be built into the avoided cost calculation.
1572
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 Q.I'm going to hand you what we'll mark as
2 Exhibit 91.
3 (Rocky Mountain Power Exhibit No. 91 was
4 marked for identification.)
5 MR. HICKEY: Did everyone get one?
6 Q.BY MR. HICKEY: I'm going to hand you what's been
7 marked as Exhibit 91, and ask if that --
8 MR. WOODBURY: Excuse me.
9 Q.BY MR. HICKEY: Oh.
10 ask if this refreshes your recollection of the
11 Wyoming avoided cost docket in 2009 in which you testified in
12 support of the wind integration charge?
13 MS. DAVISON: I'm sorry, Mr. Hickey, did you --
14 Exhibi t 91, did you say it was 2009?
15 MR. HICKEY: I did. Thanks for the correction.
16 It was 2006.
17 MS. DAVISON: Thank you.
18 Q.BY MR. HICKEY: Does it refresh your recollection
19 that in 2006, you testified in support of a wind integration
20 charge while employed by the Company in an avoided cost docket
21 in Wyoming?
22
23
A.Yes, it does.
Q.Okay. Referring you to page 5 of the testimony,
24 which I'LL represent to everyone is several pages in, there is
25 a submission of Stipulation of three pages; then there is a
1573
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 Stipulation and Settlement Agreement of some additional pages;
2 and Exhibit i to that is where your testimony begins. Isn't
3 that true, Mr. Widmer?
4 A.That's correct.
5 Q.And if you would, sir, please join me on page 5
6 of your testimony at line 10, and did you ask yourself this
7 question in 2006: Do intermittent renewable resources require
8 an additional adjustment to the GRID production dispatch model
9 of avoided costs?
10 And could you read your answer, please?
11 A.Yes. The intermittent nature of a renewable
12 resource causes the Company to incur additional costs
13 associated with the integration of the renewable resource that
14 other resources do not cause the Company to incur. These
15 integration costs represent the intrahour fuel and operating
16 reserve requirement cost of having intermittent resources on
17 our system. These costs are not captured by the Company's GRID
18 model, and, therefore, must be deducted from the GRID
19 calculated avoided cost results.
20 Q.Okay, thank you. And then you had an opportunity
21 in 2009 in a general rate case in Wyoming to address again the
22 issue of wind integration charges, didn't you?
23 A.I did.
24 Q.And you proposed an adjustment in that case,
25 didn't you, to wind integration charges?
1574
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
. 25
1 A.I did.
2 Q.And if I represent to you that the adjustment
3 that you proposed was five million, nine hundred fifty-five
4 thousand, six hundred excuse me, two hundred sixty-two
5 dollars, do you have any reason to disagree with that?
6 A.I do not. However, I should mention that the
7 reason I proposed an adj ustment to wind integration costs in
8 the Wyoming case which is different than what I propose in this
9 case is because at the time in Wyoming there was not an ECAM
10 mechanism that could be utilized by the Company to recover
11 their wind integration costs. So if you're getting at why my
12 testimony is different between that case and this case, that's
13 the reason.
14 Q.Well, let's talk about that for a minute. You
15 recall since it was fairly recently, I assume, that in the 2009
16 Wyoming case, which was again tried earlier this year, some
17 several months ago now but at least in the same calendar year,
18 the Company filed for $32 million of wind integration charges,
19 didn't they? Subj ect to check, can you take that?
20 A. Subj ect to check.
21 Q. And your adj ustment that you sponsored on behalf
22 of the Wyoming Industrial Energy Customers was this approximate
23 $6 million adjustment that I just read.Correct?
A.I agree with that.
Q.And in this current case in Idaho,you're aware
1575
HEDRICK COURT REPORTING WIDMER (X)
P.O.BOX 578,BOISE,ID 83701 Monsanto
24
.
.
.
1 of the fact that the Company has filed for $34 million in wind
2 integration charges. Correct?
3 A.That i S correct.
4 Q.But it's your position that no wind integration
5 costs should be allowed in setting base net power costs in this
6 proceeding for the reasons presumably that you alluded to a
7 moment ago. Correct?
8 A.Yes. I recommended that the wind integration
9 costs should not be included in base net power costs because,
10 number one, the rate the Company proposed -- the $ 6.50 per
11 megawatt hour rate -- is not cost based, it's not based on
12 operation of PacifiCorp' s system or anything of that nature;
13 therefore, there's a distinct possibility by approving that in
14 net power costs we could end up with customers paying too much,
15 and I'm concerned about having customers pay too much. The
16 only way to be ensured that customers aren't paying too much
17 would be to allow the Company to recover wind integration costs
18 through the ECAM mechanism.
19 On top of that, I would think that the Company
20 would prefer to recover wind integration costs --
21 Q.I'm sorry, Mr. Widmer, I'm staying with you to
22 give you some latitude here, but to the point that you're going
23 to offer perspectives of what the Company's position is, I
24 think that's beyond any fair response to the question,
25 Madam Chair.
1576
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
20
1 COMMISSIONER SMITH: Mr. Budge.
2 MR. BUDGE: Could the witness just be allowed to
3 complete his answer?
4 COMMISSIONER SMITH: Mr. Widmer, have you
5 adequately responded to the question posed?
6 THE WITNESS: I didn't get to finish my answer.
7 COMMISSIONER SMITH: Well, will you please
8 finish?
9 THE WITNESS: Yes, ma' am.
10 As I was saying, I would think the Company would
11 rather recover wind integration costs through the ECAM also,
12 because as I i ve stated on numerous occasions, they don't know
13 what their wind integration costs are. They haven't estimated
14 actual wind integration costs, they can't calculate them. At
15 least by recovering the wind integration costs through the
16 ECAM, the Company knows that they are recovering what their
17 actual costs are.
18 COMMISSIONER SMITH: Mr. Hickey.
19 MR. HICKEY: Thank you, Chairman Smith.
Q.BY MR. HICKEY: So at the end of this,
21 Mr. Widmer, we are in agreement that wind integration costs are
22 real costs and that there should be some accounting for them in
23 setting net power costs?
24
25
A.I agree that wind integration costs are real
costs; I agree the Company doesn't know how much they actually
1577
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 are; and I agree that they should be recovered through an ECAM.
2 I do not agree they should be included in base rates.
3 Q.I think I've heard you say that before,
4 Mr. Widmer.
5 A.I was just correcting how you stated your
6 statement.
7 Q.And the reason that you have suggested that they
8 be recovered in the ECAM in Idaho is because that means the
9 Company would take a 10 percent haircut right off the bat
10 because of the sharing band. Isn't that correct?
11 A.Well, that would be true; however, I would point
12 out that that haircut would be less than the amount the Company
13 has been charging customers for wind integration costs that are
14 caused by wholesale transmission customers located on the
15 Company's system, because the Company has been delinquent in
16 seeking recovery from FERC of those costs, so I
17 Q.You were here when -- I'm sorry.
18 A.So I think it's not that much of a stretch to say
19 it would be reasonable for the Company to take a li ttle bit of
20 a haircut until they figure out what their real costs are.
21 Q.Since you alluded to it, you're aware of the fact
22 that there is a new Notice of Proposed Rulemaking at the
23 F-E-R-C that addresses the issue of wholesale wind integration
24 charges, aren't you?
25 A.Actually, I have not seen that.
1578
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 Q.Okay. Did you hear Dr. Shu's testimony yesterday
2 regarding that NOPR?
3 A.I believe I was outside the room at that time.
4 Q.Would it surprise you to know that that new Rule
5 requires, as I understand it, a year's worth of data to be
6 collected before the Application for a tariff filing at the
7 F-E-R-C can be made in pursuit of wind integration charges at
8 the wholesale level?
9 A.Well, I would point out that the Company has
10 had--
11 MR. HICKEY: If I could, Madam Chair, I think
12 that was a specific question of whether he had any knowledge
13 about the requirement of the proposed rulemaking.
14 COMMISSIONER SMITH: I think the question was was
15 he surprised.
16 Were you surprised?
17 THE WITNESS: No, I wasn't surprised at that, no.
18 Q.BY MR. HICKEY: Okay. Fair enough. One last
19 area I'd like to talk to you about, and that is the Black Hills
20 adjustment that you propose in this case that relates to a
21 contract that has been a part of the total portfolio of
22 resources of Pacific Power for quite a few years, hasn't it,
23 Mr. Widmer?
24 A.Yes, it has.
25 Q.In fact, in all of these years that Exhibits 89
1579
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
20
1 and 90 document your involvement with net costs for the Company
2 and testifying in support of GRID in the six-state terri tory,
3 that contract would have been a part of the net power cost
4 recovery in each of those cases, wouldn't it?
5 A.Yes, it would have.
6 Q.And you never suggested in any of those
7 circumstances that that contract needed to be adjusted, did
8 you?
9 A.I did not, but you need to realize that in
10 working for PacifiCorp, I was tasked with recovering the most
11 power costs I could possibly recover; and if an issue had not
12 been brought forward by an opposing party, we did not address
13 it, and --
14 MR. HICKEY: I have nothing further of the
15 wi tness. Thank you.
16 COMMISSIONER SMITH: Thank you.
17 Do we have questions from the Commissioners?
18 COMMISSIONER REDFORD: No.
19 COMMISSIONER KEMPTON: No.
COMMISSIONER SMITH: All right. Mr. Budge, do
21 you have redirect?
22 MR. BUDGE: Just very briefly.
23 I guess just a point of inquiry to the Company:
24 Mr. Duvall was asked a question yesterday about whether the
25 start date of the Top of the Line (sic) project had been moved
1580
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 back to December 1 in his recently-filed testimony in Wyoming,
2 and it was this witness -- Mr. Widmer who had actually
3 checked that information and had it. We since have pulled a
4 copy of his testimony. It does, in fact, reflect that.
5 So I guess what I would ask the Company is is
6 Mr. Duvall going to be put back up? Should I inquire of that
7 of him, or is the Company now willing to stipulate that that
8 date is December 1 based on his filing in Wyoming, or should I
9 take it up with this witness?
10 MR. HICKEY: Well, I would agree with you, this
11 isn't redirect.
12 MR. BUDGE: I'll take it up on redirect then,
13 that's fine.
14 MR. HICKEY: Well, I think you're at redirect,
15 and it's nothing that I inquired into. If you'll give me a
16 minute.
17 MR. BUDGE: You did ask about adjustment on Top
18 of the World, so I plan on going into it unless you just want
19 to cut it short.
20 MR. HICKEY: I didn't ask him about it. He made
21 a comment about the Top of the World; I didn't ask him about
22 it.
23 But let me have two seconds, Madam Chair.
24 COMMISSIONER SMITH: Okay. We'll be at ease for
25 a few moments.
1581
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (X)
Monsanto
.
.
.
1 (Discussion off the record.)
2 COMMISSIONER SMITH: I think we're ready to go
3 back on the record.
4 Mr. Budge.
5 MR. BUDGE: Thank you.
6
7 CROSS-EXAMINATION
8
9 BY MR. BUDGE:
10 Q.Mr. Widmer, Counsel had asked you a question
11 concerning an adjustment concerning the Top of the World
12 in-service date.
13 MR. HICKEY: I just want to --
14 COMMISSIONER SMITH: Mr. Hickey.
15 MR. HICKEY:make it clear that I didn't ask
16 that question. I believe the adjustment that I gave Mr. Widmer
17 a chance to acknowledge, that some of his 15 adjustments
18 actually would increase net power costs. He alluded to this
19 wi thout identifying it by name.
20 Is that right, Mr. Widmer?
21 COMMISSIONER SMITH: No, he said, "Top of the
22 World."
23
24
25
THE WITNESS: I said, "Top of the World."
MR. HICKEY: But it wasn't my question to him.
COMMISSIONER SMITH: So j ust alter your questions
1582
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
20
21
22
1 to say, "In your response to one of the questions."
2 MR. BUDGE: Okay.
3 Q.BY MR. BUDGE: Mr. Widmer, in your response to a
4 question from Mr. Hickey, you had made a comment concerning the
5 Top of the World wind proj ect. Correct?
6 A.Yes.
7 Q.At the time you had filed your testimony that's
8 now in evidence, were you making adjustments based upon the
9 information received from the Company in Data Requests
10 concerning when the start date was for that proj ect?
11 A.That's correct, it was based on Monsanto Response
12 2.33.
13 Q.And what was the start date the Company provided,
14 if you can recall, in that Data Response that you then
15 incorporated in your adjustments?
16 A.October 1, 2010.
17 Q.Since that testimony was filed, were you able to
18 determine that the Company had asserted a different start date
19 in the Wyoming case recently filed?
A.Yes, in Mr. Duvall's --
Q.What was -- how did you make that determination?
A.I reviewed some testimony that Mr. Duvall
23 recently filed in a Wyoming docket, and in that testimony it
24 stated that the contract effective date for the Top of the.25 World wind project was December 1, 2010.
1583
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
1 Q.BY MR. BUDGE: May I approach the witness?
2 COMMISSIONER SMITH: You may.
3 MR. BUDGE: I haven't yet made extra copies of
4 this, but I will maybe if we can during the break and circulate
5 it. We have
6 Q.BY MR. BUDGE: Can you simply identify that
7 document which we'll mark as Monsanto Exhibit 251?
8 COMMISSIONER SMITH: Three. Two five three.
9 (Monsanto Exhibit No. 253 was marked for
10 identification. )
11 Q.BY MR. BUDGE: Is that the transcript -- excuse
12 me. Is that the testimony of Mr. Duvall that you are referring
13 to?
14 MR. HICKEY: And to that point, we certainly
15 stipulate that that testimony had the incorrect date, yes.
16 MR. BUDGE: You stipulate that is the correct
17 date, correct in-service date?
18 MR. HICKEY: I know that the correct date is
19 October 1. If that document reflects December, it is
20 incorrect.
21
22
23
MR. BUDGE: Okay.
MR. HICKEY: What does that document reflect?
MR. BUDGE: The document reflects an in-service
24 date of December 1st.
25 MR. HICKEY: It should be October 1st.
1584
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
18
19
1 COMMISSIONER SMITH: The document reflects what
2 was filed in Wyoming?
3 MR. BUDGE: Yes.
4 COMMISSIONER SMITH: Okay.
5 Q.BY MR. BUDGE: Well, let's proceed with it this
6 way: If -- I think the Company has indicated they're going to
7 provide more information to the Company -- or, to the
8 Commission on these service dates.
9 COMMISSIONER SMITH: Yes.
10 Q.BY MR. BUDGE: And I would assume that they could
11 confirm which date is accurate. We have three different ones
12 wi th respect to Top of the World.
13 So, anticipating that additional filing from the
14 Company, Mr. Widmer, if, in fact, the in-service date is
15 December 1 as Mr. Duvall indicated in his Wyoming case, not
16 October 1, would that make any difference in the adjustments
17 made in your testimony?
A.Yes.
Q.And could you explain what difference it would
20 make?
21 A.If the December 1 date was correct, looking at
22 page 3 of my direct filed testimony, it would change the Top of
23 the World adjustment which is shown as Adjustment 6 from a
24 positive -- meaning increase in revenue requirement -- of
25 $1,550,033 to a credit of $2,712,003.
1585
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
1 And the Idaho estimate would change from an
2 increase of 91,963 to a decrease of $160,000 -- $160,902.
3 Q.And have you made a calculation on how that would
4 affect your overall recommendation in your testimony?
5 A.I did not make that calculation.
6 Q.Counsel asked you something about your prior
7 testimony that was reflected in Exhibits 88 and 89?
8 A.Yes.
9 Q.And some of that testimony preceded the year
10 2003. Is that correct?
11 A.Yes.
12 Q.And some was after 2003?
13 A.Yes.
14 Q.When did GRID come into existence?
15 A.2001.
16 Q.So the testimony prior to 2001 would not have --
17 would have preceded any GRID model being in existence?
18 A.Yeah. Actually, GRID itself came in existence
19 about 2001, but given the length of time it takes to proceed
20 wi th various dockets and so forth, we didn't actually have
21 testimony until after 2001, I believe, on the GRID model,
22 subject to check.
23 Q.Counsel for the Company inferred that that prior
24 testimony might be inconsistent with the testimony you provided
25 in this case. Do you believe that to be correct or
1586
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
18
19
20
21
22
23
24
. 25
1 incorrect?
2 A.Would you repeat the question?
3 Q.Counsel inferred that by reason of your testimony
4 in these prior cases in support of the GRID model, that that
5 somehow might be inconsistent with the testimony you provided
6 here on behalf of Monsanto.
7 A.Well, it was consistent with the general thinking
8 at the time from the Company. It was consistent with that
9 thinking.
10 Q.Would any of that prior testimony change the
11 testimony you provided here today?
12 A.No.
13 MR. BUDGE: No further questions.
14 COMMISSIONER SMITH: Thank you, Mr. Budge.
15 Thank you, Mr. Widmer.
16 THE WITNESS: Thank you.
17 (The witness left the stand.)
MR. BUDGE: We call Kathryn Iverson.
1587
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
WIDMER (Di)
Monsanto
.
.
.
19
20
1 KATHRYN IVERSON,
2 produced as a witness at the instance of Monsanto, being first
3 duly sworn, was examined and testified as follows:
4
5 DIRECT EXAMINATION
6
7 BY MR. BUDGE:
8 Q.Will you state your full name and business
9 address for the record?
10 A.Yes. My name is Kathryn E. Iverson:
11 K-A-T-H-R-Y-N, E, I-V-E-R-S-O-N. And my business address is
12 17244 West Cordova Court, Surprise, Arizona, 85387.
13 Q.Ms. Iverson, did you prefile direct testimony on
14 behalf of Monsanto Company under date of November 1, 2000
15 (sic), together with Exhibit 229, 230, and 231?
16 A.Yes, that was filed November 1, 2010.
17 Q.Do you have any changes you wish to make to
18 ei ther your testimony or exhibits?
A.No.
Q.If I were to ask you the same questions today as
21 are contained in your prefiled testimony, would your answers be
22 the same?
23
24
25
A.Yes.
MR. BUDGE: Madam Chairman, we'd move to spread
the testimony and exhibits of witness Iverson.
1588
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (Di )
Monsanto
.
.
20
21
22
23
24
. 25
1 COMMISSIONER SMITH: I don't see that she has an
2 exhibi t, but she did attach Appendix A which is apparently her
3 qualifications. So, if there's no obj ection, we will spread
4 the pre- --
5 MR. WOODBURY: Three exhibits.
6 MR. BUDGE: I have three exhibits.
7 COMMISSIONER SMITH: Oh, you're right.
8 MR. BUDGE: 229 through 231.
9 COMMISSIONER SMITH: I'm also going blind as well
10 as deaf.
11 Without objection, we will spread the prefiled
12 testimony of Ms. Iverson upon the record as if read, and
13 identify Exhibits 229 through 231. I apologize.
14 (The following prefiled direct testimony
15 of Ms. Iverson is spread upon the record.)
16
17
18
19
1589
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (Di )
Monsanto
.
1
2 Q
3 A
4 Q
5 A.6
7
.
8 Q
PACIFICORP dba ROCKY MOUNTAIN POWER
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. PAC-E-10-07
Direct Testimony of Kathryn E. Iverson
I. INTRODUCTION AND QUALIFICATIONS
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Kathryn E. Iverson; 17244 W. Cordova Court, Surprise, Arizona 85387.
WHAT IS YOUR OCCUPATION AND BY WHOM ARE YOU EMPLOYED?
I am a consultant in the field of public utility regulation and employed by the firm of
Brubaker & Associates, Inc. (BAI), regulatory and economic consultants with
corporate headquarters in St. Louis, Missouri.
WOULD YOU PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND
9 EXPERIENCE?
10 A I have a Bachelor of Science Degree in Agricultural Sciences and a Master of
11 Science Degree in Economics from Colorado State University. i have been a
12 consultant in this field since 1984, with experience in utility resource matters, cost
13 allocation and rate design. More details are provided in Appendix A to this testimony.
1590
Iverson, Di - 1
Monsanto Company
.1 Q
2 A
3
4
5
6 Q
7 A
8
9
10
11.12
13
14 Q
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
I am appearing on behalf of Monsanto Company ("Monsanto"), a. special contract
customer of Rocky Mountain Power ("RMP" or "Company"). RMP is a division of
PacifiCorp.
II. PURPOSE OF TESTIMONY AND SUMMARY OF CONCLUSIONS
WHAT IS THE PURPOSE OF YOUR TESTIMONY?
The purpose of my testimony is to: (1) show the impacts on Monsanto resulting from
the Company's requests in this case, along with the historical impacts of previous rate
changes, (2) discuss the proper regulatory treatment of a non-firm customer such as
Monsanto in the allocation of jurisdictional costs, (3) provide the impacts of the
adjustments made by various Monsanto witnesses on the Idaho proposed rate
change both individually and in total, and (4) offer recommendations on rate design
for the Schedule 400 tariff.
ARE YOU SPONSORING ANY EXHIBITS IN CONNECTION WITH YOUR
15 TESTIMONY?
16 A Yes. I am sponsoring Exhibit 229 (KEI-1) through Exhibit 231 (KEI-3). These
17 exhibits were prepared either by me or under my supervision and direction.
18 Q
19 A
20
21
22.
WOULD YOU PLEASE SUMMARIZE YOUR FINDINGS AND CONCLUSIONS?
My findings and conclusions are as follows:
Rate Impact of Company's Proposal
· The impact to Monsanto of this case could range anywhere from $8.3 milion to
$22.3 millon.
1591
Iverson, Di - 2
Monsanto Company
.
.
.
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
. Since 2003, Monsanto's average cost has increased by over 65%. In the last four
years alone, Monsanto's costs have increased by $10.5 milion, or 33%. In
addition to cost increases, Monsanto has also seen its curtailable hours increase
from 800 to .1, 050 hours over the same time.
. If RMP's request to increase Monsanto's rates by over $22 milion in this case is
granted, it would result in increases totaling $32.8 milion since the expiration of
the 2003 Contract. This case could result in the doubling of Monsanto's rate
since the last time the Commission has had to decide a contested case.
Regulatory Treatment of Monsanto as a Non-Firm Customer
. Monsanto desires first and foremost to be a non-firm customer of a regulated
utility. The concept of forcing a non-firm customer to first "buy all-firm" and then
"sell a product" back to the utility is neither reasonable nor fair and in fact is a
fiction that does not reflect reality.
. Since the Company has not planned for, or acquired resources, on the basis of
Monsanto's non-firm loads, a proper jurisdictional allocation study would reflect
only Monsanto's firm demands for purposes of allocating system costs.
. A "non firm" approach to jurisdictional allocation reduces the increase to Idaho by
$12 milloh. Applying a share of these benefits to mitigate RMP's proposed rate
increase reduces Monsanto's increase down to roughly 2%.
. RMP's "All Firm" allocation method fundamentally ignores both the planning
reality that Monsanto's loads are non-firm, and the long-standing history of non-
firm service to Monsanto. Furthermore, in order to form a complete picture of the
evaluation of Monsanto's rates, the "All Firm" method must include a separate
valuation of interruptibilty.
. A proper valuation of Monsanto's curtailment should reflect the avoidance of
capacity and energy. Without a valuation of Monsanto's interruptibility, the cost of
service results provided by the Company. in its May 28, 2010 Application are
incomplete. Monsanto will provide an updated valuation on this issue on
December 22, 2010.
30 . The Revised Protocol treatment that Monsanto is a "firm" customer that sells back
31 curtailment is a fiction and has resulted in increases year after year. The
32 opportunity to address issues regarding the allocation of system costs to non-firm
33 loads should be explored both in this rate case, as well as in the case filed last
34 month by RMP, Docket No. PAC-E-10-09.
35 Modifications to Revenue Requirements
36 . The adjustments for return on equity, capital structure, adjustment to Gateway
37 transmission, and net power cost study result in an overall increase to Idaho of
38 $11.8 million, a reduction of $15.9 million based on the Company's "All Firm"
39 approach. Monsanto's increase under the "All Firm" approach is an increase of40 $6.4 millon.
41
42
43
44
. When the adjustments are included in a jurisdictional allocation study that does
not include Monsanto peak demands of its non-firm load, the increase to Idaho is
$4.0 millon. The benefits of this reduction shared between Monsanto and other
ratepayers results in entirely mitigating Monsanto's $6.4 milion increase.
1592
Iverson,. Di - 3
Monsanto Company
.1
2
3
4
5
6
7
8
9
10
11
12
13
14.15
16 Q
Schedule 400 Revisions
· Monsanto's firm load of 9 MW qualifies for service under the Schedule No., 9 --
General Service -- High Voltage. At current rates, the revenues to serve 9 MW
under Schedule 9 would be roughly $3.3 milion.
· The remaining non-firm load would remain as a Special Contract customer and be
served under Schedule 400 at a flat energy rate.
· Historical and current precedence for a flat non-firm energy rate exists, as this
was the type of rate Monsanto had prior to 2004. Furthermore, RMP recently
agreed to a similar rate structure for an interruptible contract in Utah.
II. RATE IMPACT OF COMPANY'S PROPOSAL
Q WHAT TYPE OF ELECTRICAL SERVICE DOES MONSANTO TAKE FROM
ROCKY MOUNTAIN POWER?
A Monsanto has a total load of approximately 182 MW served at transmission voltage
level and under charges set forth in Schedule 400. Of this amount, 9 MW Gust 5%) is
served at firm rates. The remaining 95% of Monsanto's load is non-firm and biled
under interruptible demand charges.
HOW MUCH DOES THE MONSANTO SODA SPRINGS FACILITY CURRENTLY
17 PAY FOR ITS ELECTRICAL SERVICE?
18 A The Soda Springs facility currently pays $42,437,868, for an overall average price of
19 $30.64 per MWH. This is based on the Company's forecasted loads for 2010.
20 Q WHAT ADJUSTMENTS DID ROCKY MOUNTAIN POWER MAKE TO
21 MONSANTO'S ACTUAL METERED LOADS FOR TREATMENT IN ITS COST
22 STUDIES?
23 A As explained by Monsanto witness Mr. James Smith, loads at the Soda Springs
24 facility in 2009 were abnormally low. To reflect more typical operations, the Company
. 25 forecasted energy use for the 2010 test period including an adjustment for energy
1593
Iverson, Di - 4
Monsanto Company
.1
2
3 Q
4 A
5 Q
6 A
7
8
9
10.11
12
13
14
15
16 Q
17
18 A
19
.
that may be curtailed or interrupted at times. Monsanto's total energy use for the test
period is 1,385,173 MWH.
WHAT AMOUNT OF INCREASE IS THE COMPANY SEEKING IN THIS CASE?
The Company proposes to increase rates in Idaho by $27.7 milion, or 13.7%.
WHAT IS THE PROPOSED INCREASE TO MONSANTO?
The impact to Monsanto could range anywhere from $8.3 millon to $22.3 milion as
the full impact is unclear from the Company's Application. If the "Interruptible
Credit, ,,1 currently in effect for Monsanto is retained as the Company indicated in its
initial filing, Monsanto's increase is $11.7 million, or an increase of 27.6% to its
current cost. If the "Interruptible Credit" is reduced as proposed in the Company's
supplemental testimony filed on September 30, 2010, Monsanto's increase would be
$22.7 milion, or 53.5%. Alternatively, if all billing elements on Schedule 400 are
increased by a uniform percentage of 19.6% as explained by Mr. Griffith in his direct
testimony, the impact to Monsanto would be 19.6%, or $8.3 milion.2 Any of these
scenarios represent a huge impact to Monsanto.
HOW HAVE MONSANTO'S RATES CHANGED OVER THE LAST SEVERAL
YEARS?
Exhibit 229 (KEI-1) provides a chart of the increases Monsanto has experienced
since the 2003 contract went into effect January 1, 2004. Monsanto's electrical costs
1 "Interruptible Credit" is a term used in Schedule 400 in order to maintain the confidentiality of the
Interruptible Demand Charge. As stated in Schedule 400: "Interruptible Demand Charge: Firm
Demand charge minus Interruptible Credit."
2 Direct Testimony of Wiliam Griffith, page 8, lines 15 - 18. When asked to describe the proposed rate
design changes for Schedule 400, the witness answered: "For customers served on these schedules,
the Company proposes a uniform percentage increase to all billng elemênts."
1594
Iverson, Di - 5
Monsanto Company
.1
2
3
4
5
6
7
8
9
10
11 Q.12 A
13
14
15
16
17
18 Q
19 A
20
21
22.
under Schedule 400 have increased by over 65% since 2003. As shown on the
chart, Monsanto's costs have increased the past four consecutive years:
January 1, 2007 $3.5 million 10.9%
January 1, 2008 $3.8 million 10.7%
January 1, 2009 $1.2 million 3.0%
January 1, 2010 $2.0 million 5.0%
These increases total $10.5 milion, or a 33% increase over four years. In addition
to the rate increases, Monsanto has also seen its curtailable hours increase from 800
to 1,050 hours over the same time. In short, over the last four years Monsanto has
seen its cost go up, and quality of service go down.
HAVE OTHER RATE SCHEDULES EXPERIENCED THESE SAME INCREASES?
No. Base rates collected from rate schedule classes (excluding special contracts)
have increased only four times since 1986, with an overall increase of less than four
percent, The Company claims that it has demonstrated a "pattern of limiting rate
increases due to rising costs" in the last 25 years. Based on Monsanto's ever-
increasing costs these last seven years, the Company's limitation of rate increases
has certainly not been applicable to its largest customer.
WOULD YOU CARE TO COMMENT ON ANY OTHER ASPECT OF YOUR CHART?
Yes. This exhibit also provides a perspective of the proposed changes Monsanto wil
see if the Company's request is granted. If the Company's request to increase
Monsanto's rates by over $22 million in this case is granted, it would result in
increases totaling $32.8 millon since the expiration of the 2003 Contract. In effect,
3 Direct Testimony of William Griffth, page 3, lines 17 - 20.
1595
Iverson, Di - 6
Monsanto Company
.
9
10.11
12
13
14
.
15 Q
20
1 this case could result in the doubling of Monsanto's rate since the last time the
2 Commission has had to decide a contested case. Consequently, the importance of
3 this one case cannot be overstated.
4 iv. REGULATORY TREATMENT OF MONSANTO AS A NON-FIRM CUSTOMER
5 Q HAS MONSANTO ALWAYS TAKEN SERVICE AS A NON-FIRM CUSTOMER?
6 A Yes. As explained in the testimony of Mr. Smith, Monsanto has been served under
7 non-firm rates for over fifty years, and has fully complied with all requests for
8 curtailments made by the Company during that time.
Existing Electric Service Agreement
Q DOES MONSANTO CURRENTLY HAVE AN AGREEMENT WITH THE COMPANY
WITH RESPECT TO THE TIMING, DURATION AND NOTICE PROVISIONS OF ITS
INTERRUPTIBILlTY?
A Yes. Mr. Smith discusses these provisions in more detail in his testimony, but in
general, Monsanto provides up to 1,050 hours of curtailment or interruption4 annually.
IF MONSANTO'S CURTAILMENTS ARE LIMITED TO 1,050 HOURS A YEAR,
16 DOES THIS MEAN THAT DURING THE OTHER HOURS OF THE YEAR
17 MONSANTO IS BEING SERVED AS A FIRM CUSTOMER?
18 A No, not at alL. The fundamental principle is that non-firm customers receive a lower
19 quality service than the firm customers do. All but 9 MW of Monsanto's load may be
interrupted at any time during the year according to the provisions of the agreement.
4 For purposes of this testimony, I wil use the terms "curtailment" and "interruptibility" interchangeably.
1596
Iverson, Di - 7
Monsanto Company
.
. 11
.
1 Just because the Company serves Monsanto during an hour does not suddenly
2 change service in that hour to "firm."
3 Q DOES MONSANTO HAVE TWO SEPARATE AGREEMENTS WITH THE
4 COMPANY?
5 A No, it does not. It has a single agreement where 9 MW are billed at firm demand and
6 energy charges, and the remainder of the load is biled at interruptible demand and
7 energy charges.
8 Q
9
10 A
WHY IS IT IMPORTANT TO MONSANTO TO HAVE A SINGLE AGREEMENT FOR
NON-FIRM ELECTRIC SERVICE FROM THE COMPANY?
Being able to purchase non-firm power is a critical component to the economics of
Monsanto's operations. Monsanto has been a non-firm customer of RMP, or its
12 predecessors, for over fifty years now. It has never desired to take firm service
13 except for the 9 MW necessary for safety reasons.
14 Q HAS ROCKY MOUNTAIN POWER EVER ATTEMPTED TO FORCE MONSANTO'S
15 NON-FIRM LOADS ONTO FIRM SERVICE?
16 A Yes, it has. In Docket No. PAC-E-01-16, the Company sought approval to increase
17 Monsanto's contractual non-firm rate by 70% in an effort to make Monsanto buy all its
18 loads at firm rates. The Commission disallowed the Company's two-contract
19 proposal then and should reject any similar proposal now.
20 Q
21
22
WHY DOES IT MATTER IF MONSANTO HAS ONE CONTRACT OR TWO?
A It matters because Monsanto desires first and foremost to be a non-firm customer of
a regulated utility. The concept of forcing1CS§~n-firm customer to first "buy all-firm"
Iverson, Di - 8
Monsanto Company
.1 and then "sell a product" back to the utilty is neither reasonable nor fair and in fact is
2 a fiction that does not reflect reality.
3 As i said before, Monsanto has been an exemplary curtailable customer for
4 over 50 years. Asa long-standing customer, it should be able to continue its
5 relationship with RMP as a non-firm customer.
6
7
8
9
10
11.12
13
14
15 Q
16 A
17
18
19
20
21
22.23
24
Correct Allocation Method For Treating Non.Firm Loads
Q HOW SHOULD THE FACT THAT MONSANTO IS SERVED AT A LOWER
QUALITY OF SERVICE BE REFLECTED IN THE ALLOCATION OF
PACIFICORP'S SYSTEM COSTS?
A A proper allocation method would allocate costs only to those loads designated as
firm. As explained by Mr. Collns, the Company has not planned for, or acquired
resources, on the basis of Monsanto's loads. Consequently, the inclusion of peak
demands placed on the system as the result of serving Monsanto's non-firm load
should be removed from any inter-jurisdictional allocation.
HAVE YOU PERFORMED THIS CORRECT ALLOCATION?
Yes. To accomplish this allocation, i revised the Company's Jurisdictional Allocation
Model ("JAM") study in three areas. First, Idaho's industrial revenue (Account 442)
was reduced by the amount of firm revenue that the Company had imputed for
Monsanto's non-firm load. Second, the cost associated with the existing "Interruptible
Credit" which the Company put into the net power costs was removed from Account
555. And third, the monthly coincident peaks of Idaho were reduced by Monsanto's
curtailable load. As a result of these changes to the JAM study, the Idaho increase of
$27.7 millon in the Company's filng is reduced to $15.7 milion, or a reduction of
$12.0 millon.1598
Iverson, Di - 9
Monsanto Company
.1 Q
2 A
3
4
5
6
7
8
9
10
11.12
13
14
15 Q
WHAT DOES THIS $12.0 MILLION REDUCTION REPRESENT?
The $12.0 million represents the benefit to Idaho associated with a lower allocation of
costs by virtue of the fact that the bulk of Monsanto's loads are served at a lower
quality of service, and should not be allocated a share of the system costs on the
basis of their peak demand. The Company's allocation model, in contrast, makes no
reference or recognition of either Monsanto's non-firm attributes or any associated
benefits.
Q HAS THE COMPANY TREATED ANY OTHER CURTAILABLE LOAD THROUGH A
REDUCTION TO COINCIDENT PEAK?
A Yes, i find two instances of this precedent. In this case, the Idaho peaks for June,
July and August were reduced by approximately 185 MW in recognition of the
irrigator's load curtailment program. And in Utah, expected reductions in Magcorp's
interruptible load for economic curtailments were made to the peaks in that
jurisdiction.5
DOES THE JAM STUDY PROVIDE FOR A PORTION OF FIXED COSTS TO BE
16 ALLOCATED ON THE BASIS OF MONSANTO'S NON-FIRM ENERGY?
17 A Yes. Fixed costs in the JAM study are allocated on the basis of the "SG" allocator
18 which is based on a 75/25 split: 75% on 12 CP, and 25% on energy. Since the
19 revised JAM study still includes the 1,306,333 MWH of non-firm energy of Monsanto,
20 a portion of fixed costs are allocated on the basis of Monsanto's non-firm load by the
21 nature of the SG allocator's 75/25 split.
.5 Response to Monsanto Data Request 1.31
1599
Iverson, Di - 10
Monsanto Company
.1
2
3
4
5
6
7
8
9 Q
10 A
11.12
13
14
15 Q
16 A
Q HOW SHOULD THIS IDAHO BENEFIT OF $12 MilliON BE USED TO MITIGATE
THE COMPANY'S PROPOSED RATE INCREASE OF $27.7 MilLION?
A Monsanto assumes all the risks associated with taking interruptible service, as well as
the additional costs associated with either lost production or higher prices in order to
buy-through energy. Consequently, the vast majority of the benefit should rightfully
accrue to Monsanto, and the other ratepayers of Idaho receive a smaller share of the
benefit. I recommend that this benefit be shared 90/10 between Monsanto and the
rest of the ratepayers. Thus, all parties are benefitted.
WHAT DOES THIS MEAN FOR MONSANTO'S RATE IMPACT?
The Company's proposed increase of $11.7 million to Monsanto should be reduced
by 90% of the $12 million benefit, or $10.8 millon. This results in an increase to
Monsanto of $0.9 milion, or roughly 2%.
The remaining $1.2 million of benefit could be applied to the other customers
of Idaho to mitigate their rate increases as proposed by the Company.
DO YOU RECOMMEND THAT MONSANTO'S RATES BE INCREASED BY 2%?
No. This analysis assumes no change is made to the Company's requested revenue
17 requirement. As I explain in a later section, Monsanto recommends several
18 adjustments be made to the Company's revenue requirement. When these
19 adjustments are included in the analysis, the results show that Monsanto requires no
20 increase.
.
1600
Iverson, Di - 11
Monsanto Company
. 1 "All Firm" Approach Used By Company
2 Q THE COMPANY CLAIMS THAT THE PRICE INCREASES REQUESTED IN THIS
3 CASE REPRESENT ITS ACTUAL COSTS OF SERVING MONSANTO. DO YOU
4 AGREE WITH THEIR ASSESSMENT?
5 A No. The allocation process and costs presented by the Company all assume
6 Monsanto is served under firm rates. No where does the Company reflect the actual
7 costs of serving Monsanto as a non-firm customer.
8 Q HOW DOES YOUR CORRECT ALLOCATION TREATMENT COMPARE TO THE
9 ALLOCATION PROCESS USED BY THE COMPANY?
10 A The Company uses an "All Firm" approach whereby Monsanto is treated as a firm
11 customer and allocated system costs on its entire load. Revenues are adjusted
. 12 upwards to reflect the elimination of the "Interruptible Credit," and the net power cost
13 study includes the cost of the "Interruptible Credit" which is allocated to the system.
14 Q HOW DOES THE COMPANY RECOGNIZE THE LOWER QUALITY OF SERVICE
15 THAT MONSANTO TAKES IN THE COST ALLOCATION PROCESS?
16 A It doesn't. Both the JAM study and the Idaho class cost of service study make no
17 adjustment for Monsanto's non-firm service.
18 Q IF THERE IS NO RECOGNITION IN TI1E COST ALLOCATION PROCESS, HOW
19 DOES THE COMPANY REFLECT MONSANTO'S NON-FIRM SERVICE?
20 A After the Company determines the full cost to serve Monsanto as a firm customer, it
21 then deducts from this full cost a credit to recognize the value of Monsanto's
. 22 interruptibility.
1601
Iverson, Di - 12
Monsanto Company
.1
2
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
.
Q ARE THERE PROBLEMS WITH THE "ALL FIRM" APPROACH FOR SETTING
RATES FOR MONSANTO'S NON-FIRM SERVICE?
A Yes, severaL. First, the "All Firm" approach fundamentally ignores both the planning
reality that Monsanto's loads are non-firm, and the long-standing history of non-firm
service to Monsanto.
Second, the "All Firm" method has continually brought additional system costs
to Idaho's jurisdiction that have raised costs to Idaho year after year, and in particular,
to Monsanto. With the Company's plan to make substantial capital investments, even
more system costs will be allocated to Idaho under the "All Firm" method with a blind
eye towards Monsanto's non-firm service.
Third, in order to form a complete picture of the evaluation of Monsanto's
rates, the cost of service in the "All Firm" method cannot stand alone -- it requires a
separate valuation of interruptibilty. Without this critical valuation, the results of the
"All Firm" cost studies are incomplete. Despite its critical importance, the Company
provided no direct testimony whatsoever in its May 28, 2010 filing with regard to the
valuation of Monsanto's curtailment.6
Fourth, while the firm rates developed for Monsanto's non-firm loads in the "All
Firm" approach are based on regulatory principles of all-in costs for utility resources
(i.e., expenses plus return on rate base), the Company historically values Monsanto's
curtailment using short-term market prices and "lost profits." Hence, the "All Firm"
approach is no different conceptually than requiring Monsanto to pay firm rates for its
non-firm service with only a short-run credit.
6 On September 30, 2010, the Company filed supplemental testimony with the Commission regarding
the economic valuation of interruptible products. Order No. 32098 established a separate schedule on
this issue with Staffllntervenor direct testimony to be filed December 22, 2010.1602
Iverson, Oi - 13
Monsanto Company
.1
2
3
4
5
6
7
8
9
10
11
12.
13
14
15
16
17
18
.
Fifth, the "All Firm" approach fails miserably as a fair treatment for non..firm
customers. As the Company brings on-line more and more resources, it raises the
firm rates in the "All Firm" cost study that non-firm loads must first pay before they
can receive any discount for their interruptibility. However, the Company then points
to its new resource stack and claims with a straight face that Monsanto's "curtailment
products" are now less valuable. There is no way to have a fair outcome when the
deck is stacked in this manner.
Sixth, the "All Firm" approach forces Monsanto into a position of "sellng" its
"curtailment product" back to the Company. Thus, Monsanto is placed in the unique
position that it must first buy non-firm power at firm rates from a monopoly, and then it
can "sell" its "product" back to a monopsony? that has substantial, and potentially
abusive, market power.
Q YOU MENTIONED EARLIER THAT IN THE "ALL FIRM" APPROACH, THE
VALUATION IS CRITICAL. HAS MONSANTO UPDATED THE VALUATION?
A Yes. A proper valuation of Monsanto's curtailment should reflect the avoidance of
capacity and energy. In response to Order No. 32098, the quantification regarding
the economic valuation of Monsanto's interruptible products wil be provided
separately in direct testimony to be filed December 22, 2010.
7 In a monopoly, there is only one seller of goods or services. In a monopsony, there exists a single
buyer of a service or good.1603
Iverson, Di - 14
Monsanto Company
.
.
.
1
2 Q
Revised Protocol Docket PAC-E-02-3
WHAT iS THE COMPANY'S BASIS FOR DETERMINING THAT MONSANTO'S
3 ENTIRE LOAD INCLUDING THE NON-FIRM PORTION BE TREATED AS FIRM IN
4 THE ALLOCATION OF JURISDICTIONAL COSTS?
5 A As explained in response to Monsanto Data Request No. 1.26, the Company utilized
6 the Revised Protocol methodology which was approved by the Idaho Public Utilities
7 Commission in Docket No. PAC-E-02-3, Order No. 29708 on February 28,2005.
8 Q WAS MONSANTO A PARTY TO THAT STIPULATION AND AGREEMENT FILED
9 ON NOVEMBER 4, 2004?
10 A
11 Q
12 A
13
14
15
16
17
18
19
20
21
22
23
24
Yes, it was.
WHAT HAS CHANGED SINCE THAT TIME?
In signing the Stipulation in Docket No. PAC-E-02-3, all parties recognized that
circumstances might change such that it might not be sensible for them to continue to
support the Revised Protocol. Monsanto finds itself at that point today, given the
persistent rate increases it has endured these last several years, and the enormous
rate increases ahead.
At the time Monsanto agreed to use of the Revised Protocol method,
Monsanto was in its first year of the three-year agreement (2004 - 2006) resulting
from Docket No. PAC-01-16. Monsanto had just received a h,efty rate increase of
25% based on the Commission's Order to bring Monsanto to cost of service together
with an offset to reflect curtailment. It was Monsanto's understanding that the
Company would continue its pattern of limiting rate increases due to rising costs, and
that Monsanto would see increases consistent with the system. This has clearly not
been the actual case however. The CCil1rmY began an unprecedented capital
Iverson, Di - 15
Monsanto Company
.1
2
3
4
5
6
7
8
9
10
11
12.
13
14
15
16
17
18
19
20
21
22
23.24
investment cycle and Monsanto has witnessed increases year after year to the firm
component of its Schedule 400 rates. Only through negotiation and offering
additional hours of curtailment has Monsanto been able to,lessen the impact of these
increases.
Monsanto was also wiling to go along with the Stipulation with the expectation
that any valuation of its "product" would be fair and reasonably reflect Monsanto's
lower quality of service, as the results from Docket No. PAC-01-16 had shown. The
Company, though, has consistently denied in the past that Monsanto's curtailment
avoids capacity and has instead based its valuation on their "lost profits" and short-
term reduction in expenses only. Thus, the expectation that the valuation component
of the Revised Protocol's "All Firm" approach would help to keep rates affordable for
Monsanto, and reduce the need to argue cost of service has simply not transpired.
Q SHOULD THE REVISED PROTOCOL "ALL FIRM" APPROACH TO TREATING
MONSANTO'S NON-FIRM LOADS BE AMENDED?
A Yes. Circumstances have changed since 2004 and Monsanto believes the Revised
Protocol "All Firm" approach produces results that are not just, reasonable and in the
public interest. Monsanto has serious concerns about how much, if any, benefit the
Idaho jurisdiction receives from the current Revised Protocol for the fact that 40% of
its load is served at a lower quality of service. In addition, as explained in Mr.
Peseau's testimony, Monsanto also is concerned with how this new era of massive
renewable resource development and speculative transmission investment in the
western United States will affect Idaho. The continued use of the Revised Protocol
will have long-term consequences for Idaho, and the time to begin its re-evaluation is
today.
1605
Iverson, Di - 16
Monsanto Company
.1 Q
2
3 A
4
5
6
7
8
9..
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
IS THERE A CURRENT DOCKET REQUESTING APPROVAL OF AMENDMENTS
TO THE REVISED PROTOCOL?
Yes. The Company recently filed a docket requesting amendments to the current
Revised Protocol allocation method (Docket No. PAC-E-10-09, filed September 15,
2010). As the largest single customer on the PacifiCorp system, the dynamics of
regulatory treatment of Monsanto will impact costs to both the state, as well as
Monsanto. Consequently, the opportunity to address issues regarding the allocation
of system costs to non-firm loads should be explored in this new docket. However,
those issues deserve review here in this general rate case as well, since this is truly
"where the rubber meets the road."
Q PLEASE SUMMARIZE YOUR FINDINGS ON THE PROPER TREATMENT OF
MONSANTO'S NON-FIRM SERVICE?
A Under a correct allocation process, the loads to Idaho would reflect only firm loads.
The JAM study as revised to reflect this correct approach reduces the increase to
Idaho by $12 millon. Applying 90% of the $12 millon benefit to Monsanto lowers
their proposed increase from $11.7 milion to $0.9 million. This is in stark contrast to
the Company's request for an increase of up to $22.3 million.
The "All Firm" approach has many problems and, in particular, without a
proper valuation of Monsanto's interruptibilty, the "All Firm" cost of service results
provided by the Company in its May 28, 2010 Application are incomplete. In
response to Order No. 32098, the quantification regarding the economic valuation of
Monsanto's interruptible products will be provided separately in direct testimony to be
filed December 22,2010.
1606
Iverson, Di - 17
Monsanto Company
.
.
.
1 In the next section, I will address the modifications to the Company's revenue
2 requirements which will further reduce the impact to all customers, including
3 Monsanto.
4 V. MODIFICATIONS TO REVENUE REQUIREMENTS
5 Q WHAT ARE THE RESULTS OF THE IDAHO CLASS COST STUDY AS FILED BY
6 ROCKY MOUNTAIN POWER?
7 A Table 1 presents the results of RMP's cost study:
Residential
General Service
Irrigation
Other
Agrium
Monsanto
Total
TABLE 1
RMP Results of Class Cost of Service
As Filed in Case No. PAC-E-10-07
Present
Revenue
$ 59,629447
37,447,761
39,845,737
1,134,740
4,466,432
59,524.497
$202,048,614
Source: Exhibit No. 47, page 2 of 2
Increase
(Decrease) to
Equal ROR
$ 6,403,185
5,086,319
3,852,416
(100,532)
715,346
11,741,139
$27,697,872
Percentage
Change
10.7
13.6
9.7
(8.9)
16.0
19.7
13.7
1607
Iverson, Di - 18
Monsanto Company
.1 Q DOES MONSANTO AGREE THAT IDAHO RATES SHOULD BE INCREASED BY
2 $27.7 MILLION?
3 A No. The testimonies of Messrs. Gorman, Peseau and Widmer provide adjustments to
4 the Company's revenue requirements analysis. As a result of their adjustments, the
5 total increase to Idaho is approximately $11.8 milion.
6 Q
7
8 A
9
10
11.12
13
14
15
16
17
18
19
20
21
22
PLEASE DESCRIBE AND QUANTIFY THE IMPACTS ASSOCIATED WITH EACH
OF THESE WITNESSES.
Mr. Gorman's testimony addresses the return on equity and proposes that it not
exceed 9.5%, and also makes adjustments to the capital structure. As a result of his
recommendation alone, the Idaho revenue price change is reduced from $27. 7 millon
down to $20.0 millon, a reduction of $7.7 millon. The results are summarized on
Exhibit 230 (KEI-2), page 1.
Mr. Peseau's testimony addresses the regulatory treatment of the Gateway
transmission asset the Company has included in its filing. As a result of Mr. Peseau's
recommendation alone, the Idaho revenue price change is reduced from $27.7 milion
down to $21.8 millon, a reduction of $5.9 million. The results are summarized on
Exhibit 230 (KEI-2), page 2.
Mr. Widmer's testimony addresses the Net Power Costs assumed by the
Company in their GRID modeling. Under the "All Firm" approach and Mr. Widmer's
power cost adjustments, the Idaho revenlJe price change is reduced from $27.7
milion down to $25.0 million, a reduction of $2.7 millon. The results of these
adjustments are summarized on Exhibit 230 (KEI-2), page 3.
.
1608
Iverson, Di - 19
Monsanto Company
.
. 12
.
1 Q WHAT IS THE FULL IMPACT OF THESE REVENUE REQUIREMENT
2 ADJUSTMENTS ON THE REQUESTED INCREASE TO IDAHO?
3 A When all of these adjustments are reflected in the JAM study simultaneously, the "All
4 Firm" Idaho revenue price change is reduced from $27.7 million down to $11.8
5 millon, a reduction of $15.9 milion. This results in an increase of 5.9% to the state
6 compared to the Company's requested 13.7% increase. Exhibit 230 (KEI-2), page 4
7 provides a summary of the impact on Idaho.
8 Q HAVE YOU UPDATED THE IDAHO CLASS COST OF SERVICE TO REFLECT A
9 TARGET INCREASE OF $11.8 MILLION?
10 A Exhibit 231 (KEI-3) provides the summary sheet of the class cost of service study
11 based on this target increase. Table 2 below summarizes the impact on the class
cost of service results with these adjustments.
TABLE 2
RMP Results of Class Cost of Service
With Monsanto Adjustments
Residential
General Service
Irrigation
Other
Agrium
Monsanto
Total
Present
Revenue
$ 59,629,447
37,447,761
39,845,737
1,134,740
4,466,432
59,524,497
$202,048,614
Source: Exhibit NO.231 (KEI-3)
Increase
(Decrease) to
Equal ROR
$ 2,267,238
1,953,181
1,052,826
(153,512)
338,630
6,378,098
$11,836,461
Percentage
Change
3.8
5.2
2.6
-13.5
7.6
10.7
5.9
1609
Iverson, Di - 20
Monsanto Company
.1
2
3
4
5
6
7
8
9
.
.
10 Q
Q YOU DESCRIBED A PREFERRED JURISDICTIONAL ALLOCATION THAT
INCLUDES PEAK DEMANDS ONLY OF FIRM LOADS. WHAT IS THE IMPACT TO
THE STATE OF IDAHO WHEN ONLY FIRM PEAK LOADS ARE INCLUDED IN
THE JAM STUDY, ALONG WITH THE ADJUSTMENTS DESCRIBED ABOVE?
A When the JAM study is updated to remove Monsanto's non-firm peak loads, the
increase to Idaho is $4 milion, or a reduction of $7.9 million compared to the "All
Firm" method. When 90% of this benefit is applied to Monsanto's increase of $6.4
milion as shown above in Table 2, its increase is completely mitigated and no
increase is warranted to the current level of Monsanto's rates.
WHAT IS THE IMPACT TO MONSANTO WITH MONSANTO'S UPDATED
11 VALUATION?
12 A The quantification regarding the economic valuation of Monsanto's interruptible
13 products wil be provided separately in direct testimony to be filed December 22,
14 2010.
15 Vi. SCHEDULE 400 REVISIONS
16 Q
17 A
18
19
20
21
PLEASE DESCRIBE SCHEDULE 400 USED FOR SERVICE TO MONSANTO.
Schedule 400 is the rate tariff schedule available for providing Monsanto firm and
interruptible retail service of electric power and energy. The tariff provides both firm
and non-firm rates for service to Monsanto. This is because 9 MW of Monsanto's
load are firm and must be priced at the firm demand and firm energy charges.8 The
remaining load is served under the interruptible energy charge, as well as the
8 A monthly customer charge is also included under the Firm Power and Energy heading as welL.
1610
Iverson, Di - 21
Monsanto Company
.1 interruptible demand charge which, for confidential reasons, is not specified in the
2 public version of the schedule.
3 Q
4 A
WHAT RECOMMENDATIONS DO YOU MAKE FOR SCHEDULE 400?
Since Monsanto has gone to tariff standard, its 9 MW firm load can actually be served
5 under Electric Service Schedule No. 9 -- General Service -- High Voltage. It is my
6 understanding that this firm load was served under Schedule 9 in the past, but was
7 moved into the special contract at some point. As Schedule 9 offers service to
8 industrial customers in Idaho limited to a maximum power requirement of 15,000 kW,
9 Monsanto's 9 MW of firm power would qualify. I calculate that at current rates, the
10 revenues to serve 9 MW under Schedule 9 would be approximately $3.3 milion.
'.11 Q
12 A
13
14
15
16 Q
WHAT RATE STRUCTURE DO YOU PROPOSE THEN FOR SCHEDULE 400?
The remaining non-firm load would remain as a special contract load and be served
under Schedule 400 at non-firm rates, with no need for separate firm and interruptible
rates. Consequently, I recommend a flat energy rate for the non-firm load served
under Schedule 400.
WHY IS A FLAT ENERGY RATE PREFERABLE TO THE CURRENT SCHEDULE
17 400 RATE COMPONENTS?
18 A There is both historical and current precedence for a flat energy rate for non-firm
19 service. Monsanto took non-firm service for many years under a flat energy rate, and
20 the latest interruptible contract signed by the Company (August 17, 2009) is based on
.
1611
Iverson, Di - 22
Monsanto Company
.
.
.
1 a simple flat energy rate.9 Furthermore, the need for a firm demand charge is
2 eliminated once the 9 MW are biled under Schedule 9.
3 The interruptible demand charge found in Schedule 400 is based on both a
4 firm rate and an interruptible credit. The interruptible credit has proven to be a highly
5 contentious component of the rate design. Determining a cost to provide non-firm
6 service to Monsanto would eliminate the need for an interruptible credit to be applied
7 to the firm demand charge.
8 Q DOES THIS CONCLUDE YOUR TESTIMONY IN THIS CASE?
9 A Yes.
9 Response to Monsanto Data Request NO.1-30, Confidential Attachment.
1612
Iverson, Di - 23
Monsanto Company
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. BUDGE: Thank you.
4 COMMISSIONER SMITH: Is she ready for cross?
5 MR. BUDGE: Ready for cross.
6 COMMISSIONER SMITH: Mr. Woodbury.
7 MR. WOODBURY: Thank you, Madam Chair.
8
9 CROSS-EXAMINATION
10
11 BY MR. WOODBURY:
12 Q.Good afternoon, Ms. Iverson.
13 A.Good afternoon.
14 Just one matter to clear up: Looking at yourQ.
15 testimony on page 1, your educational background is bachelor of
16 science in agricultural sciences and a master's in economics?
17 A.Yes.
18 Okay. Now, setting aside that nine megawatts ofQ.
19 power that Monsanto has in Soda Springs, apart from the
20 interruptible nature of service that Monsanto receives pursuant
21 to the curtailment products that it has agreed to deliver and
22 the fact that Monsanto receives at the transmission level
23 rather than the distribution levels, can you explain how the
24 electric service Monsanto receives is of a lower quality than
25 the service received by the Company's other tariff customers?
1613
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
1 A.Yes. I think I first mentioned the term "lower
2 quality" on page 6 of my direct testimony at the top of that
3 page. It's at line 10. And in putting together my testimony,
4 I looked at the historical increases that Monsanto has seen
5 over these last several years, last eight years or so, and it
6 became clear that we couldn't simply look at the increases in
7 costs to Monsanto, but that we had to also recognize that they
8 have offered additional hours of interruptibili ty. And so when
9 I made the comment that, in short, over the last four years
10 Monsanto has seen its costs go up and quality of service go
11 down, I'm speaking to the fact that the quality of service is
12 that they have to provide additional hours of interruption.
13 Q.Okay, thank you.
14 A.So it has nothing to do with voltage drop,
15 al though that is sometimes considered in the quality -- service
16 quali ty. It has to do with the number of outages that they
17 experience.
18 Q.Thank you.
19 MR. WOODBURY: With that clarification, I have no
20 further questions. Thank you.
21 COMMISSIONER SMITH: Thank you, Mr. Woodbury.
22 Mr. Purdy, do you have questions?
23 MR. PURDY: No, I don't.
24 COMMISSIONER SMITH: Mr. Olsen.
25 MR. OTTO: None from me.
1614
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
19
1 COMMISSIONER SMITH: Mr. Hickey, do you have
2 questions?
3 MR. HICKEY: Thank you, Madam Chair.
4
5 CROSS-EXAMINATION
6
7 BY MR. HICKEY:
8 Q.Good afternoon, Ms. Iverson.
9 A.Good afternoon.
10 Q.On page 9 of your testimony, you propose revising
11 the allocation treatment for Monsanto. Isn't that correct?
12 And I think 20 and 21 would be the line references?
13 A.Yes.
14 Q.And on page 21, you state that you performed this
15 new allocation, and you describe the three steps that you took
16 in that regard. Is that getting some background out of the way
17 here?
18 A.Yes, uh-huh.
Q.You state that, first, industrial revenues were
20 reduced by what amount?
21 A.The amount of firm revenue that the Company had
22 imputed to Monsanto.
23
24
25
Q.And was that XXXXXXXXXXX?
A.Yes. And I'm afraid that that number was
provided under confidential.
1615
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
1 MR. HICKEY: I would ask the reporter to seal
2 this page of the transcript, and with the endorsement of the
3 Chairman ask that this --
4 COMMISSIONER SMITH: Everyone forget they heard
5 it? We'll try.
6 Q.BY MR. HICKEY: Then you say the second step that
7 was the cost associated with the existing interruptible credit,
8 which the Company put into net power costs and that that was
9 removed from an Account 555. Isn't that true?
10 A.Yes.
11 Q.And then, finally, the third step you explain was
12 that monthly coincident peaks of Idaho were reduced by
13 Monsanto's curtailment load. Is that the third of the three
14 steps that you --
15 A.Yes.
16 Q.And your conclusion is that as a result of the
17 three steps, the Company's filing should be reduced by -- and
18 I'm hesitant to state the figure until Mr. Budge can address
19 whether that figure that you calculated you or Monsanto
20 consider confidential.
21
22
23
A.That is not confidential.
Q.And that figure would be $ 12 million. Correct?
A.That's right. That's the decrease in the
24 increase.
25 Q.And what amount of demand or firm revenues did
1616
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
20
1 you remove? Is that the XXXXXXXXXX?
2 A.That was that number, yes.
3 Q.And by what amount did you reduce Idaho's monthly
4 coincident peaks?
5 A.By the 162 megawatts that is the interruptible
6 demand of Monsanto, adj usted upwards for losses.
7 Q.Now, you were here this morning when Mr. Smith
8 testified, weren't you?
9 A.Yes.
10 Q.And you understand that there are different
11 categories of interruptible product and different hours
12 associated with the current contractual arrangement regarding
13 what qualifies for interruptible credit. Correct?
14 A.What qualifies for an interruptible credit is all
15 of Monsanto's load except for the nine megawatts of firm
16 demand.
17 Q.Okay. Well, let me -- appreciate your response.
18 Had you finished it? I don't want you to feel like --
19 A.Yes.
Q.But you were here and understand that there are
21 limi ted circumstances that ever cause some of these
22 interruptions to occur, don't you?
23 A.I understand that according to the Agreement,
24 that -- between the Company and Monsanto, that there are
25 provisions for different types of interruptions as far as
1617
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
1 economic curtailments and operating reserves and system
2 integri ty, yes.
3 Q.So just as Mr. Smith acknowledged that the 170
4 megawatts is not a guarantee that it's going to be interrupted
5 every year, you can't guarantee that 170 megawatts would be
6 interrupted every year, can you?
7 A.I can't guarantee that, because the Company is
8 the entity that decides when those interruptions will occur and
9 at what time.
10 Q.Fair enough. Go ahead if you weren't --
11 A.No, that's fine.
12 Q.I'm going to hand you what I've marked as
13 Exhibi t 92, and we'll ask if you've had a chance to see this in
14 your preparation for the testimony you filed in the case. I
15 believe Ted's getting copies to Counsel.
16 (Rocky Mountain Power Exhibit No. 92 was
17 marked for identification.)
18 Q.BY MR. HICKEY: So the outstanding question,
19 Ms. Iverson, is whether or not you've had a chance to see what
20 I'LL, for the record, again note is Exhibit 92, but it is a
21 part of exhibits attached to Mr. Griffith's testimony?
22 A.Yes, I've seen that, and I believe that that is
23 an update to Mr. Griffith's Exhibit 55 that he originally filed
24 in your May Application.
25 Q.Okay. And if we go down to nonfirm on the
1618
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
20
1 left-hand side of Exhibit 92 -- are you with me?
2 A.Just one moment.
3 Q.Sure.
4 A.This is slightly different from what Mr. Griffith
5 filed in Exhibit No. 55, because now we have two columns for
6 units: A 2009 unit and a 2010 unit. Whereas, in the
7 Application you only had 2010 units.
8 Q.This is Exhibit 84.
9 A.Uh-huh.
10 Q.To Griffith.
11 A.Uh-huh.
12 Q.Okay. Well, when you mentioned 55, I wanted
13 to --
14 A.Fifty-fi ve was similar to this in that it was
15 what the Company filed in its original Application when it was
16 seeking a $27.7 million rate increase for the state. I believe
17 this exhibit of Mr. Griffith's -- and I've only got one page of
18 it; there's 21 pages, I believe -- shows what the Company's
19 rebuttal position is.
Q.You are absolutely correct. And take the time
21 you want to look at this, and if you want the other pages of
22 it, we can certainly get the entire exhibit in front of you. I
23 don't think my follow-up questions are going to require it, but
24 I want you to have the entire exhibit if you want it.
25 A.No, that's fine.
1619
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
1 Q.Okay. So I'm stiii -- I'm locked in at nonfirm
2 on the left-hand side, about the middle of the document.
3 A.Yes.
4 Q.And if we go to the third line down, nonfirm
5 kW--
6 A.Yes.
7 Q.can you come across with me to 2010 present
8 revenue dollars?
9 A.2010 present revenue dollars under the 2010?
10 Q.Yes.
11 A.Yes.
12 Q.And that Figure is $25,168,416. Correct?
13 A.That's correct. And that column is simply
14 multiplying units times price, so it's the 2010 units times the
15 present price of 12.27, which is actually the firm demand
16 charge.
17 Q.But shouldn't it be that 25 million would, in
18 fact, be the correct figure to use in your allocation, rather
19 than the XXXXXXXXXX that we discussed earlier?
20
21
22
23
24
25
A.No.
Q.You don't agree?
A.No.
Q.Okay.
A.The reason is that the $25 million shown there is
taking the nonfirm billing units and multiplying it times the
1620
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (X)
Monsanto
.
.
.
1 firm rate.
2 I removed only the interruptible credit portion
3 because Monsanto does pay a demand charge on its interruptible
4 for its interruptible load, and that interruptible demand
5 charge is the difference between the firm demand and the
6 interruptible credit.
7 Q.Okay.
8 MR. HICKEY: I have no further questions of
9 Ms. Iverson.
10 COMMISSIONER SMITH: Thank you.
11 Do we have questions from the Commissioners?
12 COMMISSIONER REDFORD: No.
13
14 EXAMINATION
15
16 BY COMMISSIONER SMITH:
17 Q.I guess, Ms. Iverson, it's not even a question,
18 but it i s just an observation that I have never -- I have never
19 heard of your concept of a reduction in quality of service
20 applying to curtailment or interruptible hours. So I guess the
21 use of that just kind of grates on me a little because, to me,
22 service quality is something very different than a customer
23 that chooses to be interrupted and has a certain number of
24 hours of curtailment and they increase or decrease.
25 A.Perhaps my background came from in Colorado, one
1621
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (Com)
Monsanto
.
.
20
21
22
23
24
. 25
1 of the utili ties there has a quality of service plan in place,
2 and part of that plan is that every year, they look at how many
3 outages have customers had to face.
4 Q.Right. I'm with you. Those were probably
5 unplanned outages.
6 A.That's exactly right. And these are totally
7 planned; I agree they are totally planned.
8 Q.Yeah.
9 A.But the issue was, as I was alluding to earlier,
10 when I put together my testimony, just putting out the dollars
11 of the cost increase to Monsanto didn't paint the full picture,
12 and that's why I said that they were incurring additional hours
13 of curtailment.
14 Q.They certainly were, and I know they reluctantly
15 agreed to it but they did agree to it, so that was kind of
16 their choice.
17 A.Yes.
18 COMMISSIONER SMITH: Mr. Budge, redirect?
19 MR. BUDGE: No further questions.
COMMISSIONER SMITH: Thank you.
Thank you for your help.
(The witness left the stand.)
MR. BUDGE: Call Brian Collins to the stand.
1622
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
IVERSON (Com)
Monsanto
.
.
21
.
1 BRIAN COLLINS,
2 produced as a witness at the instance of Monsanto, being first
3 duly sworn, was examined and testified as follows:
4
5 DIRECT EXAMINATION
6
7 BY MR. BUDGE:
8 Would you state your name and business addressQ.
9 for the record, please?
10 Brian C. Collins. My business address: 16690A.
11 Swingley Ridge Road, Suite 140, Chesterfield, Missouri, 63017.
12 Mr. Collins, did you prefile direct testimony onQ.
13 behalf of Monsanto Company under date of November 1, 2010?
14 A.Yes,I did.
Q.And did you also file rebuttal testimony?
A.No,I did not.
Q.And I didn't see that you filed any exhibits.
A.I did not file any exhibits.
Q.Do you have any corrections you wish to make to
your prefiled direct testimony?
15
16
17
18
19
20
A.No, I do not.
22 If I were to ask you today the same questionsQ.
23 contained in your direct testimony, would your answers be the
24 same?
25 A.Yes, they would.
1623
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLINS (Di)
Monsanto
.
.
20
21
22
23
24
. 25
1 MR. BUDGE: Madam Chair, with that, we'd move to
2 have the prefiled testimony of Mr. Collins spread on the
3 record, and tender him for cross-examination.
4 COMMISSIONER SMITH: Okay. I believe what we
5 decided to do is spread this testimony on the record as if it
6 had been read, with the recognition that some of the issues
7 might be more applicable to our subsequent hearing. Okay, so
8 we will spread the record -- testimony on the record as if
9 read.
10 (The following prefiled direct testimony
11 of Mr. Collins is spread upon the record.)
12
13
14
15
16
17
18
19
1624
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLINS (Di)
Monsanto
.
.
. 17
1 Q
2 A
PACIFICORP dba ROCKY MOUNTAIN POWER
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. PAC-E-10-07
Direct Testimony of Brian C. Collns
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
Brian C. Collins. My business address is 16690 Swingley Ridge Road, Suite 140,
3 Chesterfield, MO 63017.
4 Q
5 A
WHAT IS YOUR OCCUPATION?
i am a consultant in the field of public utilty regulation with the firm of Brubaker &
6 Associates, Inc. ("BAI"), energy, economic and regulatory consultants.
7 Q
8 A
9 Q
10 A
PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND EXPERIENCE.
This information is included in Appendix A to my testimony.
ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?
I am appearing on behalf of Monsanto Company ("Monsanto"), a special contract
11 customer of Rocky Mountain Power ("RMP" or "Company"). RMP is a division of
12 PacifiCorp.
13 Q
14 A
WHAT IS THE SUBJECT OF YOUR TESTIMONY?
I provide testimony as to the interruptible nature of Monsanto's loads, the treatment of
15 Monsanto by RMP in its Integrated Resource Plan, and the economic benefits to
16 RMP, its customers and the power system as a whole from a long-term interruptible
program such as Monsanto.
1625
Collns, Oi - 1
Monsanto Company
.1 Q
2
3 A
DID RMP PROVIDE ANY DIRECT TESTIMONY IN ITS MAY 28,2010 FILING WITH
REGARD TO THE VALUATION OF MONSANTO'S CURTAILMENT?
No. In its May 28, 2010 filing, the Company provided no direct testimony whatsoever
4 with regard to the valuation of Monsanto's curtailment. On September 30, 2010, the
5 Company filed supplemental testimony with the Commission regarding the economic
6 valuation of Monsanto's curtailment. In consideration of Order No. 32098 in this
7 proceeding, the issue regarding quantification of this valuation wil be addressed in
8 my direct testimony to be filed December 22, 2010.
9 Q
10 A
11.12
13
14
15
16
.
17 Q
DOES MONSANTO RECEIVE FIRM SERVICE FROM RMP?
Only a very small portion (9 MW) of Monsanto's total 182 MW load is served under
firm rates. The vast majority of Monsanto's load is interruptible and is charged a
lesser demand charge. For cost allocation purposes, Monsanto is treated by RMP as
though it were 100% firm, although in reality Monsanto is primarily a non-firm
interruptible customer. RMP first determines the cost to serve Monsanto as a firm
customer, then deducts from Monsanto's cost of service a credit equal to the value of
Monsanto's curtailment.
IS IT TRUE THAT WHEN DETERMINING MONSANTO'S COST AS A FIRM
18 CUSTOMER, RMP ALLOCATES TO MONSANTO A PORTION OF NOT ONLY THE
19 COSTS OF SHORT-TERM AND LONG-TERM MARKET PURCHASES USED TO
20 MEET FIRM DEMAND BUT ALSO THE COSTS OF GENERATING UNITS THAT
21 THE COMPANY HAS PLANNED AND CONSTRUCTED TO MEET FIRM DEMAND
22 ON ITS SYSTEM?
23 A
24
Yes, that is true. Since Monsanto is not a firm customer, the valuation of Monsanto's
curtailment is extremely important. Monsanto's value of curtailment must be
1626
Collns, Oi - 2
Monsanto Company
.
.
.
1 deducted from its allocated all-firm costs in order to determine its cost of service as
2 an interruptible customer. The valuation of Monsanto's curtailment should be fair
3 and reasonable such that the overall net costs allocated to Monsanto reflect the non-
4 firm nature of Monsanto's demand on the RMP system.
5 Q HOW HAS THE COMPANY TREATED THE MONSANTO INTERRUPTIBLE LOAD
6 IN ITS 2008 INTEGRATED RESOURCE PLAN ("IRP")?
7 A RMP has removed Monsanto's interruptible load from its firm demand for planning
8 purposes. Monsanto's load is treated as non-firm. Therefore, RMP does not
9 consider Monsanto's interruptible demand when planning to construct or purchase
10 resources to meet its firm system demand. Since Monsanto is an interruptible
11 customer, RMP avoids the cost of long-term resources (including a reserve margin) to
12 serve the Monsanto interruptible load. RMP's 2008 IRP plainly states:
13
14
15
16
17
18
19
Interruptible. There are three east-side load curtailment contracts in
this category. These agreements with Monsanto, MagCorp and Nucor
provide 237 MW of load interruption capability at time of system peak.
Both the capacity balance and energy balance count these resources
at the level of full load interruption on the executed hours.
Interruptible resources directly curtail load and thus planning
reserves are not held for them.1 (emphasis added)
20 Q WITH RESPECT TO THE 237 MW REFERENCED ABOVE AND INCLUDED IN THE
21 2008 IRP AS INTERRUPTIBLE RESOURCES, HOW MUCH IS ATTRIBUTED TO
22 MONSANTO?
23 A Monsanto's 67 MW of economic curtailment is included in the 237 MW identified as
24 interruptible load in the 2008 IRP.
1PacifiCorp 2008 IRP, page 87.
1627
Collns, Oi - 3
Monsanto Company
.1
2
3
4
5
6
7
8
9
10
11
.
. 24
Q HAS RMP SUBSEQUENTLY INCLUDED MONSANTO'S PROVISION OF
OPERATING RESERVE AS AN INTERRUPTIBLE RESOURCE IN ITS IRP?
A Yes. In the 2008 IRP Update issued on March 31, 2010, RMP now includes 90 MW
of Monsanto operating reserve as an interruptible resource. At page 35 of the 2008
IRP Update, the Company states:
Interruptible contracts - The positive change reflects the inclusion of
the operating reserve component of the Monsanto interruptible load
contract (90 MW) in addition to the economic curtailment portion
previously modeled.
All of Monsanto's interruptible load is now deducted by RMP for the purposes of
determining its planning reserve obligation.
12 Q
13 A
WHAT COSTS WOULD RMP INCUR IF MONSANTO WERE A FIRM CUSTOMER?
RMP would have to acquire long-term firm resources equal to Monsanto's load plus a
14 planning reserve margin if Monsanto were a firm customer and RMP would incur the
15 costs of such resources.
16 Q HOW LONG DOES THE COMPANY ANTICIPATE MONSANTO TO BE AN
17 INTERRUPTIBLE CUSTOMER?
18 A The 2008 IRP states at page 83, "For planning purposes, PacifiCorp assumes that
19 current qualifying facilty and interruptible load contracts are extended to the end of
20 the IRP study period." The end of the IRP study period is 2018.
21 Q ARE THERE ECONOMIC BENEFITS DUE TO A LONG-TERM INTERRUPTIBLE
22 PROGRAM?
23 A Yes. Economic benefits accrue to RMP, its customers, and the power system as a
whole from a long-term interruptible program. There are also economic benefits that
1628
Collns, Oi - 4
Monsanto Company
.
.
21
22
23
24
25
26
27
28
29
30
31.
1 can accrue directly to Monsanto. For example, as explained in the 2007 IRP, these
2 customer benefits are:
3 Economic benefits may also accrue directly to participants in the form
4 of incentives, rate discounts, and greater ability to adjust their loads to
5 prices, thereby gaining greater control over their energy use and
6 managing their energy costs. (Demand response) has also been
7 credited with several harder to quantify economic benefits, such as
8 creating a hedge against market exposure (price objectives),
9 helping create a more elastic demand curve by sending appropriate
10 price signals (elasticity objectives), and reducing the overall market
11 price by alleviating pressure on reserves (market efficiency objectives).
12 (20071RP, Appendix B, page 7, emphasis added)
13 As the.Company's 2007 IRP notes, a customer such as Monsanto should rightfully
14 expect certain benefits as a result of its commitment to curtail loads. Monsanto
15 actively manages its energy costs through careful planning, and direct communication
16 with the Company on curtailment requests, buy-through of energy, and even
17 scheduling of furnace maintenance. More importantly though, as the 2007 IRP notes,
18 Monsanto's interruptible contract should offer a "hedge against market exposure."
19 While firm costs for RMP capacity go up, the valuation for Monsanto's curtailment
20 should also increase.
Q HAS THE IDAHO PUBLIC UTILITIES COMMISSION ("COMMISSION") STAFF
PREVIOUSLY RECOGNIZED THE BENEFITS OF USING INTERRUPTIBLE
RESOURCES AS A HEDGE?
A Yes. In Case No. PAC-E-06-9, the Staff anticipated, specifically, this benefit in its
comments:
Revenue paid under the contract to Monsanto for these interruptible
services help to offset the increased costs incurred by Monsanto to
receive electrical service. ... As explained in Section 2.2 of the
Agreement, adjustments may be made to, but not limited to, the
customer charges, demand charges, energy charges, as well as the
credit value.
1629
Collns, Oi - 5
Monsanto Company
.1
2
3
4
5
6
7
8
9
10
11
12 Q
13 A
14
15
16.17
18
19 Q
Not only will the Company be able to collect revenues from Monsanto
based on its cost of service, but the price paid to Monsanto will reflect
the value of the products it provides the Company. Both the Company
and Monsanto have assured Staff that there are opportunities for either
side to reevaluate the credits in the context of a general rate case.
Staff believes it is important for Monsanto to have an opportunity to
reevaluate the value of the credits at the same time rates are changed
to reflect changes in cost of service. This abilty wil help keep rates
affordable for Monsanto and reduce the need to argue cost of
service in a general rate case. (Case No. PAC-E-06-9, Comments of
the Commission Staff, November 3,2006, page 3, emphasis added)
WHAT AMOUNT OF CURTAILMENT DOES MONSANTO PROVIDE RMP?
The 2008 Electric Service Agreement ("ESA") provides for three types of curtailment:
(1) Operating Reserves of 95 MW which can be called upon a maximum of 188 hours
per calendar year; (2) Economic Curtailment of 67 MW available for a maximum of
850 hours per calendar year; and (3) System Integrity of 162 MW available a
maximum of 12 hours per calendar year. The amounts and hours of curtailment
reflect the terms of the 2008 ESA currently in effect for calendar year 2010.
WHAT ARE SOME OF THE IMPORTANT FACTORS IN VALUING MONSANTO'S
20 CURTAILMENT?
21 A The valuation should recognize the nature of Monsanto's curtailment and how it is
22 used by RMP, and that Monsanto's curtailment is a long-term resource. This will
23 provide a fair and reasonable result for all customers and encourage retention of
24 Monsanto's interruptible contract.
25 Q
26 A.27
28
HOW LONG HAS MONSANTO BEEN AN INTERRUPTIBLE CUSTOMER?
Monsanto has been a reliable interruptible customer since 1951 and has adequate
ore to be mined for another 40 years. The fact that Monsanto has been an unfailing
customer these 50-plus years along with its commitment to remain operating in Idaho
1630
Collns, Oi - 6
Monsanto Company
.1
2
3 Q
4
5
6 A
7
8
9
10
11
12 Q.13 A
14
15
16
17
18
19
20
21
22
23 Q
in the foreseeable future both point to treating Monsanto's curtailment as a long-term
resource.
WHAT ARE SOME OF THE ECONOMIC BENEFITS TO THE UTILITY, THE
CONSUMERS AND THE POWER SYSTEM AS A WHOLE FROM A LONG-TERM
INTERRUPTIBLE PROGRAM SUCH AS MONSANTO'S CONTRACT?
There are a host of economic benefits, but cost avoidance and cost reduction are the
main economic drivers. Perhaps the Company's 2007 IRP stated it best:
Demand response allows utilities to avoid or defer incurring costs for
generation, transmission, and distribution, including capacity costs,
line losses, and congestion charges. (PacifiCorp 2007 IRP,
Appendix B, page 7, emphasis added)
ARE THERE OTHER SYSTEM BENEFITS AS WELL?
The support of reliabilty in power supply and delivery during system emergencies is
also a benefit when customers such as Monsanto can shed load during emergency
conditions. This is further explained in the 2007 IRP:
Customer demand management can enhance reliability of the electric
supply and delivery systems by providing the utility with the means to
better balance. loads with supply during system emergencies and/or
high-use periods. In this context, (demand response) can help
improve the adequacy and security of the power supply and delivery
(T&D) systems by augmenting the utilty's ancillary services, such as
supplemental reserve. (PacifiCorp 2007 IRP, Appendix B, pages 7-8)
DOES MONSANTO PROVIDE THESE BENEFITS TO RMP AND ITS
24 CUSTOMERS?
25 A Yes, it does. Monsanto's contract allows RMP to avoid or defer incurring capacity
26 costs for generation. It also allows the Company to reduce its fuel or purchased.27
28
power expense by callng upon Monsanto for economic curtailment. Furthermore,
since Monsanto is able to interrupt within a 10-minute time period, it qualifies as a
1631
Collns, Oi - 7
Monsanto Company
.1
2
3
4
5
6
resource that can provide operating reserves. Interruptions for operating reserves
can occur at any time and in any month, and Monsanto stands available 24 hours per
day to provide operating reserves.
Monsanto also provides RMP the means to balance system loads during
system emergencies. The loads of Monsanto's three furnaces - 162 MW total - are
available for curtailments for system integrity purposes.
7 Q HAS RMP PREVIOUSLY RECOGNIZED THE BENEFIT OF AVOIDED CAPACITY
8 INVESTMENTS FOR LOAD MANAGEMENT PROGRAMS?
9 A Yes. In RMP's 2009 Demand Side Management Annual Report - Idaho at page 35,
10 the Company states:
11 The cosUbenefit analysis of the load management programs are based
12 on the avoided value of peak or capacity investments..
13 Q HAVE YOU QUANTIFIED THIS CAPACITY VALUE?
14 A Yes.However, in response to the Commission's Order No. 32098, I will file direct
15 testimony supporting the quantification separately on December 22, 2010.
16 Q DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
17 A Yes, it does.
.
1632
Collns, Oi - 8
Monsanto Company
.
.
.
20
21
22
23
24
25
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Mr. Woodbury, do you have
4 questions?
5 Or, were you done, Mr. Budge?
6 MR. BUDGE: Yes.
7 MR. WOODBURY: Madam Chair, Staff has no
8 questions.
9 COMMISSIONER SMITH: Mr. Purdy.
10 MR. PURDY: No.
11 COMMISSIONER SMITH: Ms. Davison.
12 MS. DAVISON: No, ma'am.
13 COMMISSIONER SMITH: Mr. Olsen.
14 MR. OLSEN: No.
15 MR. OTTO: I have no questions.
16 COMMISSIONER SMITH: Mr. Hickey.
17 MR. HICKEY: I have no questions for the reasons
18 that you alluded to, Madam Chairman: We expect this testimony
19 to be part of the second phase.
COMMISSIONER SMITH: Okay. From the Commission?
COMMISSIONER REDFORD: No.
COMMISSIONER KEMPTON: No.
COMMISSIONER SMITH: Nor I.
Thank you, Mr. Hickey and Mr. Budge.
(The witness left the stand.)
1633
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLINS (Di)
Monsanto
.
.
.
1 MR. BUDGE: Madam Chairman, that would conclude
2 the Monsanto witnesses and exhibits, and could they all be
3 excused if they hadn't been?
4 COMMISSIONER SMITH: Is there any obj ection to
5 excusing the witnesses of Monsanto?
6 MR. WOODBURY: No.
7 MR. HICKEY: None.
8 COMMISSIONER SMITH: Okay, they are excused.
9 Thank you.
10 MR. BUDGE: And I assume that the custom of the
11 Chair is that at the conclusion of the case would be all
12 exhibits identified would be offered.
13 COMMISSIONER SMITH: Yes. And if I somehow fail
14 in my duty to do that, by Rule, they are automatically
15 admitted.
16 MR. BUDGE: Thank you.
17 COMMISSIONER SMITH: So in order to -- well,
18 actually, let's take a seven-minute break; and then when we
19 come back, in order to alleviate Ms. Davison's further angst,
20 we will go to the Industrial Customers.
21
22
MS. DAVISON: Thank you.
MR. SOLANDER: Madam Chair, if I could have your
23 attention just for a moment?
24
25
COMMISSIONER SMITH: Mr. Otto.
Oh, I'm sorry. I knew it was on this side.
1634
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLINS (Di)
Monsanto
.
.
18
19
20
21
22
23
24
. 25
1 MR. SOLANDER: We're not clear if we excused
2 Mr. Griffith, and if not, I would ask that he be excused for
3 the rest of the proceeding.
4 COMMISSIONER SMITH: Any obj ection to excusing
5 Mr. Griffith?
6 He's free to go. Thank you.
7 (Recess. )
8 COMMISSIONER SMITH: All right, we'll go back on
9 the record now.
10 Ms. Davison.
11 MS. DAVISON: Thank you, Madam Chair. First, I
12 want to express my appreciation to the Commissioners and to the
13 Idaho Irrigation Pumpers Association and the Idaho Conservation
14 League in letting my witnesses jump ahead on the schedule.
15 Thank you very much.
16 I'd like to call Greg Meyer to the stand.
17
1635
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
COLLINS (Di)
Monsanto
.
.
.
1 GREG MEYER,
2 produced as a witness at the instance of PacifiCorp Idaho
3 Industrial Customers, being first duly sworn, was examined and
4 testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MS. DAVISON:
9 Q.Good afternoon, Mr. Meyer. Could you please
10 state your full name and spell your last name for the record,
11 please?
12 A.Greg Meyer: M-E-Y-E-R.
13 Q.And by whom are you employed?
14 A.I'm a senior consultant with Brubaker and
15 Associates in Chesterfield, Missouri.
16 Q.And are you the same Mr. Meyer that prepared
17 testimony in this case on behalf of the PacifiCorp Idaho
18 Industrial Consumers (sic) on October 14th, 2010?
19
20
A.Yes, it is. Yes, I am.
Q.Do you have any changes or corrections to your
21 testimony?
22
23
A.No, I do not.
Q.If I were to ask you the same questions today,
24 would your answers be the same?
25 A.Yes, they would.
1636
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
MEYER (Di)
PIIC
.
.
19
20
21
22
23
24
. 25
1 MS. DAVISON: Madam Chair, I i d like to move that
2 the testimony and exhibits of Mr. Meyer, which are premarked as
3 610, 611, 612, 613, 614, and 615, be spread upon the record as
4 if they were read today.
5 COMMISSIONER SMITH: Thank you. If there's no
6 obj ection, we will spread the prefiled testimony of Mr. Meyer
7 upon the record as if read, and identify Exhibits 610 through
8 615.
9 (The following prefiled direct testimony
10 of Mr. Meyer is spread upon the record.)
11
12
13
14
15
16
17
18
1637
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
MEYER (Di)
PIIC
.
.
.
1 Q.
2 A.
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
Greg R. Meyer. My business address is 16690 Swingley Ridge Road, Suite 140,
3 Chesterfeld, MO 63017.
4 Q.
5 A.
WHAT IS YOUR OCCUPATION?
I am a Senior Consultant in the field of public utilty regulation with Brubaker &
6 Associates, Inc., energy, economic and reguatory consultats.
7 Q.
8
9 A.
10 Q.
11 A.
12 Q.
13 A.
PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
EXPERIENCE.
This information is included in Exhibit No. 610.
ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?
I am appearng on behalf ofPacifiCorp Idaho Industrial Customers ("PIlC").
WHAT IS THE SUBJECT OF YOUR TESTIMONY?
I am addressing issues surounding Rocky Mountain Power Company's ("RMP"
1 4 or "Company") proposed revenue requirement.
is Q.
16 A.
17
18
19
20
PLEASE SUMMARIZE YOUR RECOMMENDATIONS.
1. Post-Test Year Rate Base Additions - RMP has failed to correctly reflect
known increases and decreases to RMP's post-test year rate base including
its effect on anualized depreciation expense. I recommend that the post-
test year rate base be restated to reflect all changes to rate base and
anualized depreciation expense.
21 2. Cash Working Capita ("CWC") - The Company has included an allowance
22 for working capital using two methodologies. I recommend elimination of
23 one working capital methodology on the basis of duplication. I also
24 recommend a zero CWC allowance.
1
Meyer, Di
PacifiCorp Idaho Industral Customers
1638
.
.
.
1
2
3
3. Normalization of Revenues - RMP's weather-normalized usage per
residential customer is too low. I recommend that the residential usage per
customer be based on a five-year average.
4
5
6
7
4. SOi Emission Allowance Sales Revenues - RMP proposes to amortize the
historical sale of SOz emission allowances prior to June 30, 2009 over
fifteen years. I recommend this historical balance of SOz emission
allowance sales revenue be amortized over five years.
8
9
10
5. Injuries and Damages ("I&D") Expense - The Company has proposed to
increase I&D expense based on the accrued methodology. I recommend
that I&D expense should be based on actual expenses from claims paid.
11
12
13
14
6. Avian Settlement - RMP has proposed to increase the accrual level of I&D
expense as it relates to this settlement. I recommend disallowance of this
expense because I&D expense was anualized separately and this
adjustment may result in double-recovery of expenses.
15
16
17
18
19
7. Incentive Compensation - RMP's incentive compensation plan contains
goals which are not well defined, hard to quantify, relate to normal job
requirements, do not motivate employees to achieve above-average
performance, and may enhance shareholder value. I recommend that one-
half of the incentive payments be disallowed.
20
21
22
8. Management Fees - RMP has proposed to include $7.3 millon for
management fees. I recommend that $2.1 milion on a total company basis
be disallowed from this amount.
23
24
25
9. Outside Services - RMP has included the test year level of outside services
expense in its cost of service. I recommend that outside services expense be
based on a four-year average of expenses from 2006-2009.
26
27
28
29
10. Generation Overhaul Expense - RMP has proposed a four-year average of
generation overhaul expense for both existing and new generation. RMP
has escalated its historic costs. I recommend no escalation of historic costs
and a different level of generation overhaul expense for new generation.
30
31
11. Uncollectibles - RMP has included the test year level of uncollectibles. I
recommend a four-year average ofuncollectibles.
2
Meyer, Di
PacifiCorp Idaho Industrial Customers
1639
.
.
.
1 Table 1 sumarizes the Idaho allocated revenue requirement impact of the
2 adjustments I am proposing in this proceeding. I have not reviewed all aspects of
3 the Company's filing, and PUC will likely support or adopt other revenue
4 requirement proposals made by other paries.
TABLE 1
Revenue Requirement Value
of Issues Addressed in Testimony
Issue
Change to Company
Revenue Requirement
(Idaho Situs)
Post-Test Year Plant Additions
Rate Base Changes
Depreciation Expense
Cash Working Capita
Residential Revenue
S02 Emission Allowance Sales Amortization
Injures and Damages Anualization
Avian Settlement
Incentive Compensation
Affliate Management Fee
Outside Services Expense
Generation Overhaul Expense
Uncollectibles
Total
$(4,046,053)
(361,744)
(364,248)
(1,205,179)
(2S6,767)
(75,456)
(26,961)
(653,785)
(111,601)
(327,080)
(134,918)
(68,807)
$(7,632,S99)
3
Meyer, Di
PacifiCorp Idaho Industrial Customers
1640
. 1 Post-Test Year Rate Base Additions
2 Q.
3 A.
ARE YOU PROPOSING ANY ADJUSTMENT TO RMP'S RATE BASE?
Yes. RMP has significantly overstated the change to rate base that will be caused
4 by post-test year plant additions. Specifically, RMP witness Steven McDougal
S states that the Company has identified capital projects that will be completed by
6 the end of the test period (December 31, 2010). Mr. McDougal states that the
7 capital projects identified will have expenditues over $5 milion and those
8 projects will be used and useful by December31, 2010.
9 Q.
10
11
12 A..13
WHY DO YOU BELIEVE THAT MR. MCDOUGAL HAS OVERSTATED
HIS RATE BASE ADJUSTMENT BASED ON THE POST-TEST YEAR
PLANT ADDITIONS?
Mr. McDougal has not properly reflected both known and measurable increases
and decreases to Idaho jursdictional rate base for factors that wil occur after the
14 test year and extending through December 2010. Signficantly, Mr. McDougal
15 reflected increases to post-test year gross plant in-service, but only parially
16 reflected known and measurable gross plant offsets caused by post-test year
17 increases to accumulated depreciation reserve. Therefore, he has 'Substantially
18 overstated the impact on RMP's test year rate base that will be caused by post-test
19 year changes through December 2010.
20 Q.
21
22 A.
23
.
PLEASE DESCRIBE HOW RM'S TEST YEAR RATE BASE CAN
CHANGE BY THE INCLUSION OF POST -TEST YEAR ADJUSTMENTS.
A utilty's rate base can increase or decrease over time depending on the change
to "net" plant investment. Net plant investment represents the difference between
4
Meyer, Di
PacifiCorp Idaho Industrial Customers
1641
.
.
.
1 gross plant additions less the total change to accumulated depreciation reserve.
2 When utilties make plant additions they increase gross plant investment.
3 However, RMP's net plant investment will change by the amount of post-test year
4 plant additions (Le., increases to gross plant investment) less the total increase to
S accumulated depreciation reserve that will occur durng the same post-test year
6 time period as the plant additions. Hence, while RMP may be making plant
7 additions afer the test year, which will increase its delivery service gross plant,
8 these plant additions will not directly increase delivery servce net plant
9 investment on a dOiiar- for-dollar basis because the gross plant additions will be
10 offset by increases to accumulated depreciation reserve that wil occur durng the
11 same post-test year time period.
12 Q.
13
14
CAN YOU PROVIDE AN EXAMPLE THAT SHOWS THAT THE
CHANGES IN GROSS PLANT DO NOT CORRLATE EXACTLY WITH
CHANGES IN NET PLANT INVSTMENT?
15 A.Yes. This is ilustrated by an example provided in Table 2. In the table, I show
16 the impact on a hypothetical utilty company with an initial gross plant amount of
17 $1 milion, that makes $100,000 per year capital additions to its gross plant, and
18 depreciates its plant investment at a rate of approximately 3% per year. As shown
19 under the colum "Gross Plant," the company's gross plant would increase by
20 $100,000 a year reflecting plant additions. However, the impact on net plant (Le.,
21 the primar rate base factor) shown under colum 3 would not be a dollar-for-
22 dollar increase as it is in the gross plant colum. The impact on net plant caused
S
Meyer, Di
PacifiCorp Idaho Industrial Customers
1642
.1 by gross plant additions is the difference between the gross plant investment less
2 the change in accumulated depreciation reserve, colum 2.
3 Importantly, in order to properly track changes in net plant investment
4 over time, one must properly consider all increases in gross plant in post-test year
5 periods, along with all increases in accumulated depreciation reserve from gross
6 plant, and depreciation reserve, in the same time period. Without the proper
7 consideration of both increases, it is not possible to accurately estimate the impact
8 on net plant investment caused by post-test year capital additions.
TABLE 2
Hypothetical Net Plant Investment Example
Accumulated.Gross Depreciation Net Capital Depreciation
Year Plant Reserve Plant Additions Expense
(1)(2)(3)(4)(5)
2006 $1,000,000 $1,000,000 $30,000
2007 $1,100,000 $30,000 $1,070,000 $100,000 $33,000
200S $1,200,000 $63,000 $1,137,000 $100,000 $36,000
2009 $1,300,000 $99,000 $1,201,000 $100,000 $39,000
2010 $1,400,000 $138,000 $1,262,000 $100,000 $42,000
9 Q.
10
11
12 A.
DID RMP INCLUDE AN ACCUMULATED DEPRECIATION RESERVE
OFFSET TO PLANT ADDITIONS FOR ITS POST-TEST YEAR PLANT
ADJUSTMENT TO RATE BASE?
No, not completely. RMP reflected increased accumulated depreciation, but only
13 for the amount that corresponds with the post-test year plant additions. RMP
14 ignored the known and measurable increase to post-test year accumulated
.6
Meyer, Di
PacifiCorp Idaho Industrial Customers
1643
.
.
.
1 depreciation that wil be booked by the recovery of test year plant in-service
2 durng the same post-test year time period that RMP is projecting plant additions.
3 The recovery of depreciation expense associated with test year plant in-servce
4 will increase accumulated depreciation reserve in the post-test year time period
5 and mitigate the increase in delivery service rate base caused by the post-test year
6 plant additions.
7 Q.
8
9
10 A.
HOW DID YOU DETERMINE THE ADJUSTMENT TO RMP'S TEST
YEAR RATE BASE CAUSED BY THE PRO FORMA PLANT
ADDITIONS PROPOSED BY RMP?
The pro forma plant additions will be offset by known and measurable changes to
1 1 accumulated depreciation reserve . during the same time period that pro forma
12 plant additions are to be placed in-service. In addition, normalized plant
13 retirements must also be considered as these plant retirements will lower the
14 depreciation expense and thus affect the accumulated depreciation reserve.
1 S Matching plant additions with changes to accumulated depreciation will more
16 accurately estimate the changes to RMP's net plant investment.
17 Q.
18
19 A.
20
21
22
23
WHAT IS THE IMPACT OF YOUR PROPOSED ADJUSTMENT TO
RMP'S RATE BASE AND REVENUE REQUIREMENT?
I adjusted RMP's projected plant additions by reflecting additional accumulated
depreciation for test year plant in-service that wil be booked durng the same
time period that the projected plant additions wil be placed in service. I also
estiinated the impact on accumulated deferred income taxes related to that same
plant durng the same post-test year time period. It should be noted, that the
7
Meyer, Di
PacifiCorp Idaho Industrial Customers
1644
.
.
.
1
2
3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
17
18 Q.
19 A.
20
21
22
estimate of changes to accumulated deferred taxes was based on test year data
which reflects depreciation expense for the plant recorded in the test year.
Depreciation expense for test year plant in the post-test year period may change.
Therefore, it may be appropriate for the Commission to require RMP to update
this estimated change in accumulated deferred income ta balance for the post-
test year net plant investment estimate.
The impact based on my recommendation to post-test year plant
adjustments to test year rate base results in a decrease of approximately $66S.8
milion, which reduces RMP's claimed revenue requirement by approximately $4
milion.
is THERE ANOTHER IMPACT FROM THIS PROPOSED
ADJUSTMENT?
Yes. The normalized retirements that will occur from December 31, 2009,
though December 31, 2010, will lower anualized depreciation expense and
should be adjusted. I have recalculated anuaized depreciation expense based on
the normalized retirement of plant during 2010 and have reduced anuaized
depreciation by $361,744 (Idaho Situs).
HOW DID YOU ESTIMATE THE RETIREMENTS FOR 2010?
I calculated a five-year average plant retirement ratio from the Company's
Federal Energy Regulatory Commission ("FERC") Form 1 report. This ratio is
the relationship between retirements in a year and plant (before retirements) at
year's end.
8
Meyer, Di
PacifiCorp Idaho Industrial Customers
1645
.
7
8
9
10
11
12.13
14
is
16
17
18
19
20
21
22
.
1 Q.
2
3 A.
WHY DO YOU BELIEVE THE RETIREMENTS NEED TO BE
CAPTURED?
If you do not recognze the retirement of plant, you will overstate the anualized
4 depreciation expense for the cost of service. This would result in ratepayers
5 paying for depreciation expense on plant which is not in servce.
6 Cash Working Capital
Q. DID THE COMPAN INCLUDE AN ALLOWANCE FOR CWC IN ITS
DIRECT FILING?
A. Yes. RMP witness Steven R. McDougal presented direct testimony which
includes an allowance for CWC of $2,134,SLO in rate base. In addition, RMP is
requesting an additional $961,4S9 of Other Working Capita. In total, RMP is
requesting $3,09S,969 of working capitaL.
Q. DO YOU CONTEST THE INCLUSION OF THIS AMOUNT IN RMP'S
RATE BASE?
A. Yes, I do. RM is requesting an allowance for working capital using two
different methodologies. I am recommending that the Other Working Capital
amount of $961,459 be disallowed because it is merely another method to
determine working capital and should not be included with a CWC analysis.
Based on the lead-lag study, the Company is attempting to double-recover an
allowance for working capital.
I am also recommending that the CWC allowance of $2.1 milion be
disallowed from RMP's rate base.
9
Meyer, Di
PacifiCorp Idaho Industrial Customers
1646
.
.
.
1 Q.
2
3 A.
WHY DO YOU PROPOSE TO NOT RECOGNIZE ANY ALLOWANCE
FOR CWC IN THIS PROCEEDING?
It has been my experience that electric utilties generally have a negative CWC
4 allowance when a properly calculated lead-lag study is pedormed. I both
5 'performed and supervised several electrc utilty lead-lag studies while employed
6 by the Missouri Public Service Commission which resulted in negative CWC
7 allowances. In fact, in Missour, it is most often the case for electrc utilties to
8 have negative CWC allowances for puroses of rate cases.
9 In this instance, RMP is relying on a lead-lag study filed in a previous rate
10 case. I have submitted a data request to obtan the lead-lag study but, to date, I
11 have not received a response to this request. I may update my testimony afer I
12 review that data response.
13 Q.
14
15 A.
PLEASE EXPLAIN WHY YOU PROPOSE TO DISALLOW THE $961,459
OF OTHER WORKNG CAPITAL.
The $961,459 of Other Working Capital is comprised of netting selective assets
16 and liabilties of RM. Specifically, RMP has requested working capita
17 recognition of accounts receivables and payables. These components are
18
19
20
considered in the lead-lag study and should not be included in PacifiCorp's
proposed CWC allowance. RMP is requesting double-recovery of certain aspects
of the lead-lag study.
10
Meyer, Di
PacifiCorp Idaho Industrial Customers
1647
.1 Q.WHY is AN ALLOWANCE FOR CWC NECESSARY?
2 A.The purose of a CWC adjustment is to allow a utilty to ear a rate of retu on
3 the amount of cash necessary for operations that is "supported by capital on ,which
4 investors are entitled to a retu."l! The lead-lag study determines who provides
S the amount of cash that is necessar to fud operations on a day-to-day basis. If a
6 utilty spends cash for an expense before the ratepayer provides cash for utilty
7 service provided, the shareholder must supply that cash. However, if the utilty
8 receives cash from the ratepayer for utilty service provided before the utilty must
9 pay cash for expenses incured to provide that service, then ratepayers have
10 provided the cash.
ii Q.WHY is YOUR RECOMMENDATION TO NOT INCLUDE CWC IN THE
12 CALCULATION OF RATE BASE REASONABLE?.13 A.As I stated previously, my experience would suggest that a negative CWC
14 allowance is a reasonable conclusion based on a properly conducted lead-lag
is study. I have requested that the Company provide a copy of its lead-lag study. I
16 will review the response to this data request which provides the lead-lag study
17 from a previous RMP rate case to determine if the lead-lag study prepared by
18 RMP does produce a reasonable allowance for CWC. However, as I have stated
19 previously, it is my experience from the lead-lag studies I have been involved in
20 the preparation of, a negative CWC allowance is the normal outcome.
jj WUTC v. PacifiCorp, Docket No. UE-050684, Final Order' 189 (April 17,2006) (stating, "(wJe
agree with Staff that the objective is to quantify the amount of working capital and curent assets
supported by capital on which investors are entitled to a retu.").
11.Meyer, Di
PacifiCorp Idaho Industrial Customers
1648
.
.
.
1 Q.
2
3
4
5 A.
YOU TESTIFIED THAT IN YOUR EXPERIENCE THAT ELECTRIC
UTILITIES OFTEN HAVE A NEGATIVE CWC ALLOWANCE. CAN
YOU CITE ANY SPECIFIC COMMISSION ORDERS WHICH
RESULTED IN NEGATIVE CWC ALLOWANCES?
Yes. In Case No. ER-2008-0318, the Missour Public Service Commission Order
6 reflected a negative CWC allowance of $94.672 milion including interest and tax
7 offsets? In Docket Nos. 09-0306 though 09-0311, Consolidated, the Ilinois
8 Commerce Commission Order reflected a negative CWC allowance of $1.598
9 milion for AmerenCILCO, a negative $3.040 milion for AmerenCIPS and a
10 negative $9.031 milion for AmerenlP electric operations.JI I have attached the
11 rate base schedules which depict these amounts to this direct testimony as Exhibit
12 NO.611.
13 I have also attached as Exhibit No. 612 to this direct testimony the fiing
14 AmerenUE made in Case No. ER-2010-0036. As can be seen from this exhbit,
15 AmerenUE fied for a negative CWC allowance of $18,350,000.1/
16 Q.
17 A.
18
19
20
PLEASE SUMMARZE YOUR TESTIMONY REGARDING CWC.
I recommend the CommisSion recognize no CWC allowance for RMP and
approve my adjustment of $364,248 (Idaho basis) to RMP's cost of service. I
believe RMP is utilzing two methods to request a working capital allowance. I
believe that RMP is requesting double-recovery of certain components of working
y Missouri Public Service Commission Case No. ER-2008-0318, Staffs Recommendation to
Approve Tariff Sheets (Feb. 10, 2009); Exhibit No. 611 at 1.
Central Ilinois Light Company et ai', Docket Nos. 09-0306 et ai', Corrected Order (May 6, 2010);
Exhibit No. 61 i at 2-4.
Exhibit No. 612 at i, lines 6-10.
'J
~
12
Meyer, Di
PacifiCorp Idaho Industrial Customers
1649
.1 capitaL. I also have not been able to check RMP's lead-lag study as the study was
2 not provided to the parties in this case.Therefore, I recommend no CWC
3 allowance be allowed in RMP's cost of service.
4 Normalization of Revenues
5 Q.DO YOU BELIEVE THE LEVEL OF ELECTRIC REVENUES IN RMP'S
6 COST OF SERVICE IS APPROPRIATE?
7 A.No. RMP's proposed level of residential revenue is understated.I. recommend
8 that the level of residential revenues be increased by approximately $1.2 milion.
9 This amount is net of additional fuel cost.
10 Q.WHAT IS THE BASIS FOR YOUR STATEMENT THAT THE LEVEL OF
11 RESIDENTIAL REVENUES IS TOO LOW?
12 A.I have . reviewed the usage per customer for the calendar years 200S-2009 as.13 compared to the Company's weather-normalized usage for the test year. Table 3
14 lists the anual average usage per customer for the residential class for 200S-2009
15 and the test year weather normalized.
.13
Meyer, Di
PacifiCorp Idaho Industrial Customers
1650
.
.
.
TABLE 3
Historic Analysis of
Residential Use per Customer
Year
Residential Use
Per Customer
(kWh)
12,336
12,714
12,785
12,8S3
12,687
2005
2006
2007
2008
2009
Company Test Year
(Weather Normalized)12,309
Five-Year Average
(200S-2009)12,675
Sources:
FERCForm 1
Testimony of Peter C. Eelkema, Table 1
Response to Monsanto Data Request No. 1.17
in Case No. PAC-E-1O-07
1 Table 3 shows that the average usage per customer used by RMP to anualize
2 residential revenues (12,309 kWh) is too low. The residential usage proposed by
3 RMP has been exceeded for each year since 2005. The amount of normalized
4 residential usage I recommend be used (12,675 kWh), is still lower than the actual
5 2009 usage durng the current economic recession (12,687 kWh).
14
Meyer, Di
Pacifi Corp Idaho Industral Customers
1651
.
.
.
1 Q.
2
3 A.
WHY is IT IMPORTANT TO ANNUALIZE REVENUES USING THE
CORRCT USAGE PER CUSTOMER?
It is important to anualize revenues using the correct usage per customer because
4 that level of anualized revenues determines the incremental revenue requirement
5 needed by the utilty to pay the expenses to operate the utilty and provide. the
6 opportunity for a reasonable retur to shareholders. If the usage per customer is
7 set too low, the utilty will collect more revenues than is necessar to pay its
8 expenses and provide the opportunity for a reasonable retu to shareholders. If
9 the usage per customer is set too high, the opposite will occur.
10 Q.
11
12 A.
13
PLEASE DESCRIBE YOUR RECOMMENDED ADJUSTMENT TO
RMP'S RESIDENTIAL CLASS.
I analyzed the residential usage per customer for the period 2005-2009 and
compared those usages to the level proposed by RMP. I calculated a five-year
14 average usage per customer for the residential class and multiplied that usage by
15 the normalized test year customers and the curent average residential margin
16 energy rate. Based on ths analysis, I believe test year residential revenues should
17 be increased by $1.2 millon.
18 SO~ Emission Allowance Sales Revenues
19 Q.
20
21 A.
22
HAS RMP INCLUDED REVENUES FROM THE SALE OF S02
EMISSION ALLOWANCES IN ITS COST OF SERVICE?
Yes. RMP has included a 15-year amortization of SOi emission allowance sales
which occured prior to June 30, 2009 in its cost of service.
is
Meyer, Di
PacifiCorp Idaho Industrial Customers
1652
.1 Q.
2
3 A.
DO YOU AGREE WITH THE AMOUNT RMP HAS INCLUDED IN THE
COST OF SERVICE?
No. I recommend that the sale of 802 allowances be amortized over five years. I
4 am pröposing that the unamortized balance of S02 allowance revenues occurng
5 before June 30, 2009, be amortized over five years instead of the 1S-year
6 amortization period proposed by RMP.
7 Q.
8
9 A.
WHY ARE YOU PROPOSING TO AMORTIZE THE S02 ALLOWANCE
SALES OVER FIVE YEARS?
I believe the current IS-year amortization period is too long. The revenues
10 generated from the sale of 802 allowances should be flowed back to customers in
11 a more expedited maner.
12 Q..13 A.
14
15
16
17
18
19
20
21
22
.
WHY DID YOU CHOOSE A FIVE-YEAR AMORTIZATION PERIOD?
Generally, five-year amortizations are proposed when addressing extraordinar
events, or recuring events with impacts that canot be easily predicted. For
example, when a major storm strkes the service territory of a utilty, the utilty is
usually granted recovery of those external costs over five years. Five years, in my
experience, is generally the most widely accepted amortization period for
extraordinary events or recuring events with volatilty uness a trend in the
activity can be observed. Obviously, shorter and longer amortizations have been
adopted by commissions, but five years is generally appropriate and reasonable.
In this instance, a five-year amortization period is more appropriate
because it credits customers' rates in a more timely maner from the sales of S02
16
Meyer, Di
PacifiCorp Idaho Industrial Customers
1653
.1 allowances. A shorter amortization period is also appropriate in this case because
2 it reduces the impact ofRMP's nearly 14% overall proposed rate increase. This is
3 a very signficant proposed rate increase, particularly in this economic climate.
4 Q.
S
WHAT is THE TOTAL VALUE OF YOUR S02 ALLOWANCE SALES
ADJUSTMENT?
6 A.Reducing the amortization period for 802 allowance sales from 15 years to
7 5 years reduces revenue requirement by $2S6,767 on an Idaho jursdictional basis.
8 Injuries and Damages Expense
9 Q.DID THE COMPANY PROPOSE AN ADJUSTMENT FOR I&D EXPENSE
10 IN THEIR COST OF SERVICE?
11 A.Yes. The Company proposed to increase test year I&D expense by $86,480 on an
12 Idaho basis (Adjustment 4.14.1)..13 Q.DO YOU AGREE WITH THE ADJUSTMENT PROPOSED BY THE
14 COMPANY?
15 A.No. I recommend that the $86,480 adjustment be reduced by $7S,456.
16 Q.
17 A.
WHAT is THE BASIS FOR YOUR ADJUSTMENT?
My adjustment is based on actul claims paid averaged for the years 2007-2009,
18 less insurance reimbursements that have been received by the Company.
19 Q.
20 A.
HOW is YOUR ADJUSTMENT DIFFERENT FROM THE COMPANY'S?
The Company's proposed adjustment is based on the average accrual of expenses
21 for the thee years from 2007-2009. I recommend that I&D expense for puroses
22 of ths rate case be determined on the actual claims paid during the period 2007-
23 2009, and not the amount accrued for possible claims.
.17
Meyer, Di
PacifiCorp Idaho Industrial Customers
1654
.
.
.
1 Q.
2
WHY DO YOU BELIEVE THE CASH BASIS APPROACH IS BETTER
THAN THE ACCRUAL APPROACH?
3 A.By establishing rates based on the actual claims paid or cash approach, ratepayers
4 are only required to pay in rates the actual expenses associated with I&D claims.
5 Ratepayers are not being asked to fud futue claims which may not materialize.
6 The cash approach also eliminates the possibilty of over-accruing for I&D
7 claims, thus, requiring ratepayers to pay fictitious expenses. The estimation
8 process is eliminated from ratepayer rates and it does not allow for the
9 manipulation of the accrual process between rate cases.
1 0 Avian Settlement
11 Q.
12
PLEASE DESCRIBE RMP'S AVIAN SETTLEMENT (ADJUSTMENT
4.17).
13 A.RMP has increased operations and maintenance ("O&M") expense and capital
14 cost to protect the wildlife habitat in and around the Company's transmission and
is distribution assets. Among the proposed increases, the Company is proposing to
16 increase the I&D expense to reverse an April 2009 accounting entr made to
1 ì Account 92S. Ths accounting entr lowered RMP's expense leveL. This
18 Company adjustment is in addition to RM's proposed anualization of I&D
19 expense.
18
Meyer, Di
PacifiCorp Idaho Industrial Customers
1655
.
.
.
1 Q.
2 A.
DO YOU AGREE WITH THE PROPOSED ADJUSTMENT?
No. I would recommend that the Company's Avian Settlement adjustment for
3 Account 92S - Injures and Damages - be disallowed ($26,961 - Idaho
4 jursdictional basis).
5 Q.
6
7 A.
WHY ARE YOU PROPOSING TO DISALLOW TmS DOLLAR
AMOUNT?
My adjustment for I&D expense as discussed above is based on actual cash
8 expenditues for claims less than the amount received by insurance. To increase
9 the revenue requirement through a separte adjustment is improper. To the extent
10 that actual payments for this event have been made, I believe those payments
11 would have been included in the claim totals provided in response to PILC Data
12 Request No. 74.
13 My proposed adjustment is based on a three-year average of actua claims
14 paid. Finally, this adjustment may represent a double-counting of expenses. If
15 the expenses are included in the claim totals, then by recognizing this expense, the
16 Commission would be allowing double-recovery of the expenses.
17 Q.
18
19
20 A.
ARE YOU PROPOSING TO ELIMINATE ALL OF THE PROPOSED
AVIAN SETTLEMENT INCREASES TO THE COMPANY'S REVENUE
REQUIREMENT?
No. I am proposing only the elimination of the Avian Settlement adjustment to
21 Account 92S, I&D expense. My concern is that the Company's proposal
22
23
improperly inflates revenue requirement by proposing a second adjustment to an
expense that the Company has already anualized.
19
Meyer, Di
PacifiCorp Idaho Industral Customers
1656
.
.
.
1 Q.
2
3
4 A.
IF THIS ADJUSTMENT IS INTENDED TO INCREASE THE ACCRUAL
LEVEL OF EXPENSE, DO YOU BELIEVE THE ADJUSTMENT WAS
CORRCTLY INCLUDED BY RMP IN THE RATE CASE?
No, I do not. If the adjustment is intended to increase the accrual level of I&D
S expense, then separating this adjustment from RMP's I&D adjustment overstates
6 the cost of service. If the adjustment had been included as a component ofRMP's
7 I&D adjustment, only one-third of the adjustment would have been recognized
8 instead of the entire amount. Ths is due to the fact that RMP proposed a thee-
9 year average on the accrual level of expenses for their cost of service.
lO Q.
11 A.
PLEASE SUMMAZE YOUR POSITION.
I believe the I&D expense adjustment for the Avian Settlement (Adjustment 4.17)
12 should be disallowed. The I&D adjustment for the Avian Settlement could allow
13 double-recovery of expenses or, in the alternative, could overstate the accrued
14 level of expense. Therefore, I recommend, consistent with my I&D adjustment,
is that this portion be disallowed.
16 Incentive Compensation
17 Q.
18
19
20 A.
21
22
DID THE COMPAN INCLUDE IN ITS COST OF SERVICE EXPENSES
ASSOCIATED WITH THE PAYMENT OF INCENTIVE
COMPENSATION?
Yes. Company Exhbit No.2 (Case No. PAC-E-lO-07, page 4.3.4) identifies that
RMP is proposing to include $32.2 milion (approximately $1.3 milion, on an
Idaho jurisdictional basis) to cover incentive compensation payments.
20
Meyer, Di
PacifiCorp Idaho Industrial Customers
1657
.
.
.
1 Q.
2
3 A.
4
5 Q.
6 A.
7
8
9
10
11
12
13
14
is
16
17
18
19
20
21
22
DO YOU CONTEST THE INCLUSION OF ANY PORTION OF THIS $1.3
MILLION?
Yes. I recommend that half or $653,78S of the incentive compensation expense
be removed from cost of service.
WHAT IS THE BASIS FOR YOUR PROPOSED DISALLOWANCE?
Based on my review of the goals (included as an attchment to PacifiCorp witness
Erich Wilson's direct testimony in Washington Utilties and Transporttion
Commission ("WUTC") Docket No. UE-100749 and attached as Exhibit 613 to
my testimony), I believe the goals for the achievement of incentive compensation
payments are not well defined.
On page 6 of his direct testimony in the referenced docket, PacifiCorp
witness Mr. Wilson states:
Individual employee goals sta with the goals set for the Company
as a whole. Each year, the Company President, in conjunction
with MidAerican Energy Holdings Company, sets the overall
goals for the Company.
In my opinion, many of these goals are more related to normal job
requirements/duties and do not motivate employees to achieve above-average
performance. Furermore, many of the goals are not quatitative, thus, making it
hard for an employee to gauge performance at any paricular time frame. Based
on these observations, I am recommending that one-half of the incentive
payments be disallowed.
21
Meyer, Di
PacifiCorp Idaho Industral Customers
1658
.
.
.
1 Q.
2 A.
PLEASE DESCRIBE RMP'S ANNUAL INCENTIVE PLAN ("AlP").
RMP's AlP is based on the achievement of group employee goals and
3 achievement of individual goals. In addition to group goals and individua goals,
4 employees may be evaluated based on new issues or opportties that afect
S RMP durng the year.
6 Employees are evaluated by their performance against six group goals.
7 The group goals describe the characteristics the Company believes are importt
8 to the success of RMP. RMP's employees establish their own individua goals
9 which are designed to advance the achievement of the group goals of the
10 Company. The individual goals are weighted 70% of the employees' overall
11 evaluation, while the group goals are weighted 30% towards the employees'
12
13 Q.
14
is A.
16
17
18
19
20
21
overall evaluation.
PLEASE DESCRIBE WHAT STANDARDS YOU BELIEVE SHOULD BE
INCLUDED IN A PROPERLY CONSTRUCTED INCENTIVE PLAN.
I believe an acceptable incentive plan should be developed that contains goals that
improve or maintain RMP's existing operational performance. The payments
associated with the incentive plan should be directly related to the achievement of
those goals.
The goals for the incentive plan should be easily understood by the
affected employees. Employees should also easily be able to determine their
performance against those goals at any time durng the year.
22
Meyer, Di
PacifiCorp Idaho Industrial Customers
1659
.
.
.
1 Q.
2
3 A.
WHAT TYPES OF GOALS WOULD YOU RECOMMEND BE INCLUDED
IN AN INCENTIVE PLAN?
Appropriate goals for an incentive plan could include safety, managing O&M
4 expenses, system reliabilty, and customer service.
S Q.
6
7
8 A.
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
ARE YOU AWARE OF COMMISSION ORDERS WHICH SUPPORT
YOUR IDEAS ABOUT A PROPERLY CONSTRUCTED INCENTIVE
PLAN?
Yes. In WUTC v. Washington Natual Gas Co., the Commission stated:
The Commission does agree with Staff that some of the incentives
fall short in terms of sending employees the message that the
purose of the program is to encourage improved service. The
Commission believes however that the company can do a far better
job in the future of creating incentives and setting goals that
advantage ratepayers.... Such goals might include controllng
costs, promoting energy efficiency, providing good customer
service, and promoting safety. Plans which do not tie payments
directly to goals that clearly and directly benefit ratepayers will
face disallowance in future proceedings. ~
Also, in Union Electric Case No. EC-87-114, the Missour Public Service
Commission stated:
At a minimum, an acceptable management performance plan
should contain goals that improve existing performance, and the
benefits of the plan should be ascertainable and related to the
plan.§!
'-I WUTC v. Washington Natul Gas Co., Docket No. UG-920840, Fourh SuppI. Order at 19 (Sept.
27, 1993).
Starry. Union Elec. Co., 29 Mo. P.S.C. (N.S.) 313,325 (1987).§l
23
Meyer, Di
PacifiCorp Idaho Industrial Customers
1660
.
.
.
1 Q.
2
3
4 A.
DO YOU BELIEVE THE GROUP GOALS AS LISTED IN EXHIBIT
NO. 613 CONTAIN THE STANDARS AND CRITERIA YOU
DESCRIBED ABOVE?
No. I have reviewed the group goals. I continue to believe that these goals do not
5 provide the employees with the quantitative goals to assess their performance. It
6 is also diffcult to assess or ascertain how some of the goals improve or maintan
7 RMP's existing operational performance. Finally, I believe some of the goals are
8 more properly classified as standard job requirements/duties and therefore should
9 not be considered performance goals tied to incentive compensation payments.
10 Q.
11
12
13
14 A.
15
16
17
18
19
20
21
22
23
24
25
CAN YOU PROVIDE SOME EXAMPLES OF PERFORMANCE
FACTORS CONTAINED IN THE GROUP GOALS WHICH DO NOT
GIVE EMPLOYEES THE ABILITY TO ASSESS THEIR
PERFORMANCE?
Yes. I have listed below certain performance factors which I believe would not
be easily quantifiable for use as a performance measure. These are examples
from RMP's AlP group goals.
~ Customer Focus:
. Proactively meets internal or external customer
expectations by anticipating needs and effectively
addressing and resolving problems, issues and concerns in
a timely maner.
~ Job Knowledge:
. Ensures that all compliance aspects of position are known
and followed; understads and complies with all policies,
codes and regulations applicable to position and company.
24
Meyer, Di
PacifiCorp Idaho Industrial Customers
1661
.
.
.
1
2
3
4
S
6
7
8
9
10
11
12
13
14
is
16 Q.
17
18
19 A.
20
21
22
23
~ Planing and Decision Makng:
. Demonstrates high levels of personal accountabilty.
~ Productivity:
. Holds self and others accountable to quality results.
~ Builds Relationships:
. Accepts personal differences and values diversity.
~ Leadership:
. Embraces change and motivates others to achieve goals.
The above list contains performance factors from each of the six group
goals. I believe these performance factors are not quatifiable to different levels
of performance. For example, how would a person exceed performance for the
performance factor "Embraces Change and Motivates Others to Achieve Goals"?
These performance factors also lead to subjective evaluation by the manager.
Subjective evaluation of employees for incentive compensation should be
minimized.
CAN YOU PROVIDE SOME EXAMPLES OF PERFORMNCE
FACTORS WHICH YOU CONTEND SHOULD BE CONSIDERED AS A
JOB DUTY OR REQUIREMENT?
Yes. I have listed below certin performance factors which I believe should be
considered job duties or requirements.
~ Customer Focus:
. Shares information with customers to build their
understanding of issues and capabilties.
2S
Meyer, Di
PacifiCorp Idaho Industrial Customers
1662
.
.
.
1 ~ Job Knowledge:
2
3
. Keeps up with curent developments and trends in area of
expertise as a par of personal development.
4 ~ Planing and Decision Makng:
S
6
. Not afaid to make decisions and ensure appropriate people
are informed.
7 ~ Productivity:
8
9
. Performs well under pressure and does not create undue
pressure for others; meets deadlines.
10 ~ Builds Relationships:
11
12
. Acts with integrty by demonstrating professional,
coureous, ethical and fair behavior at all times.
13 ~ Leadership:
14
15
. Demonstrates passion; personal commitment and
enthusiasm.
16 The above list contains performance factors from each of the six group
17 goals. I believe these performance factors are more properly classified as job
18 requirements or duties. I canot understand, for example, why an incentive plan
19 needs to incent an employee to "act with integrty by demonstrating professional,
20 coureous, ethical and fair behavior at all times." This performance factor should
21 be a job requirement for all employees working at RMP and should not be used as
22 a performance factor for incentive compensation.
26
Meyer, Di
PacifiCorp Idaho Industrial Customers
1663
.
.
.
1 Q.
2
3
4 A.
DO YOU HAVE ANY FURTHER COMMENTS REGARING THE
PERFORMANCE FACTORS CONTAINED IN THE SIX GROUP
GOALS?
Yes. I would like to point out that I only provided examples of performance
5 factors which could not be quatified or which should be job requirements. I am
6 not suggesting these examples are exhaustive, or that the categories are mutully
7 exclusive.
8 Also, referring back to Exhibit No. 613, I would argue that many of the
9 performance factors do not have performance metrcs associated with them to
10 determine if the operations of RMP are improved or maintained.
11 Q.
12
13
14 A.
15
16
17
18
19
20
21
22
23
24
25
26
27
IN YOUR REVIEW OF THE COMPANY'S AlP GROUP GOALS DID
YOU FIND ANY GROUP GOALS THAT COULD BE ATTRIBUTABLE
TO THE ATTAINMENT OF SHAREHOLDER VALUE?
Yes. Both the Customer Focus and Productivity performance goals have
attnbutes that are designed to enhance shareholder value.
. Customer Focus: Dedicated to meeting the expectations of
internal and external customers, co-workers and stakeholders;
obtains first-hand information from customers and uses it to
improve processes and services; acts with customers in mind;
establishes and maintans effective relationships with
customers and gains their respect and trust.
. Productivity: Achieves a high level of relevant
accomplishments for the benefit of the company and its
customer. Uses appropriate methods to implement solutions;
checks processes and tasks to ensure accuracy and effciency;
initiates action to correct problems or notifies others of quality
issues as appropriate.
27
Meyer, Di
PacifiCorp Idaho Industral Customers
1664
.
.
.
1 Along with these performance goals, many of the performance factors improve
2 shareholder value.
3 Q.
4
S A.
ARE YOU REJECTING ALL OF THE PERFORMANCE FACTORS
WHICH COMPRISE THE SIX GROUP GOALS?
No. I believe that several of the performance factors which comprise the six
6 group goals would be good staring points to develop performance stadards for
7 an incentive compensation plan that are understandable, quatifiable and
8 performance-enhancing.
9 For example, a performance factor under the Planing and Decision
10 Makng Goal states, "(u)ses metrcs and milestones, and goal reassessment to
11 measure execution and determine whether correction to plan is needed." I believe
12 this performance factor could be used to implement several performance criteria
13
14 Q.
15
16 A.
17
18
19
20
21
22
for different deparents in adhering to O&M expense control.
PLEASE SUMMARIZE YOUR INCENTIVE COMPENSATION
ADJUSTMENT.
I am recommending that SO% of the incentive compensation payments be
removed from cost of service. I have discussed some of the concerns I have with
the six group goals of the AlP. The individual goals are weighted 70% while the
group goals are weighted 30% for the employees' overall evaluation. A SO%
reduction to the incentive plan is a fair and reasonable adjustment to the incentive
compensation expense leveL. i believe ths is a conservative recommendation.
Paricularly, considering the curent economic environment, the Commission may
28
Meyer, Di
PacifiCorp Idaho Industrial Customers
1665
.
.
.
1 wish to eliminate all incentive compensation from the RM's Idaho revenue
2 requirement.
3 Management Fees
4 Q.
5
6 A.
PLEASE DESCRIBE THE "MANAGEMENT FEE" THAT RMP HAS
INCLUDED IN ITS TEST YEAR OPERATING EXPENSES.
RMP pays an anual "Management Fee" to MidAmerican Energy Holdings
7 Company ("MEHC") under an "Intercompany Administrative Services
8 Agreement." The Services Agreement allocates certain of MEHC's costs to its
9 subsidiaries. The Agreement describes "Administrative Services" as including,
10 but not being limited to: services by executive, management, professional,
1 1 technical and clerical employees; financial services ta and accounting services;
12 use of offce facilties; and use of vehicles and equipment.V
13 In 2009, PacifiCorp booked $8,3S3,029 above-the-line for MEHC
14 management fees. Before allocating any portion of this to Idaho operations, RMP
1S removed $1,OS3,029 of this amount pursuant to MEHC Merger Idaho
16 Commitment No. 28 which caps the amount allowable for the fee at $7.3
17 milion.~/ The Idaho-allocated portion of the resulting $7.3 milion fee is
18 $393,635 ($7.3 milion x Idaho SO allocation factor).
1/Exhibit No 614 at 4-5 (PacifiCorp's Response to Staff Data Request No. 25, Attchment 2, p. 1 in
Washington Docket No. UE-I00749).
Rocky Mountain Power Exhibit No.2, Case No. PAC-E-IO-07, page 4.8.w
29
Meyer, Di
Pacifi Corp Idaho Industrial Customers
1666
.
.
.
1 Q.
2
3 A.
ARE YOU RECOMMENDING A DISALLOWANCE OF ANY OF THE
AMOUNT THAT RMP DID NOT REMOVE?
Yes. I am recommending that the amount included in Idaho rates be reduced by
4 $111,601 to reflect disallowance of costs included in the management fee that are
5 not appropnate for inclusion in Idaho rates. Specifically these costs are: MEHC
6 and MidAerican Energy Company ("MEC") bonuses and legislative costs and
7 contnbutions. Table 4 summarizes the adjustment that I am proposing.
8 Q.
9
10
11
12 A.
13
TABLE 4
Adjustment to Affiliate Management Fee
System
Amount
Allocation
Factor3 Idaho Situs
MEHC Bonusesl
MEC Bonusesl
Legislative/Contributions2
5.392%
S.392%
5.392%
Total to Remove $2,069,661 $111,601
Sources:
lPacifiCorp response to WUTC Staff Data Request No. 25, Attchment 1,
(Exhibit No. 614).2PacifiCorp response to Washington Public Counsel Data Request No. 103,
Confidential Attchment (Exhibit No. 615).3Rocky Mountain Power Exhibit No.2, E-PAC-1 0-07, Page 4.8.
DOES THE $1 MILLION REDUCTION THAT RMP MADE IN
COMPLIANCE WITH CASE NO. PAC-E-05-08, ORDER NO. 29973,
FUNCTIONALLY REMOVE THE BONUS COSTS MENTIONED
ABOVE?
No. The Commitment to reduce the management fee established in Commission
Docket No. PAC-E-OS-08 appears to be designed to limit allowable management
30
Meyer, Di
PacifiCorp Idaho Industrial Customers
1667
.
.
.
1 fees and says nothing of any disallowed amounts covering those types of expenses
2 that should be booked below-the-line or otherwse not charged to RMP's Idaho
3 customers.2! Moreover~ the total amount of inappropriate costs well exceeds the
4 $1 milion removed for compliance with Idaho Commitment No. 28. Therefore,
5 the $7.3 milion limitation should be considered before inappropriate costs are
6 removed.
7 Q.
8
9 A.
is THERE SUPPORT FOR YOUR RECOMMENDATION IN RMP'S
OWN ADMINISTRATIVE SERVICES AGREEMENT WITH MEHC?
Yes. According to the terms of the Services Agreement, the Company must bear
10 those costs that are inappropriate for recovery in each state where it operates.
11 Aricle 4(a)(ii) of the Agreement states:
12
13
14
15
16
17 Q.
18
19 A.
20
21
It is the responsibilty of rate-regulated Recipient Paries to ths
Agreement (Le., PacifiCorp L to ensure that costs which would have
been denied recovery in rates had such costs been directly
incurred by the regulated operation are appropriatelro identifed
and segregated in the books of the regulated operation...
PLEASE EXPLAIN THE DISALLOWANCE
RECOMMENDING FOR MEC AND MEHC BONUSES.
YOU AR
RMP has included in Idaho rates _ for anual bonuses paid to MEC and
MEHC executives.ll I am recommending disallowance of this entire amount
because, after a review of page 12S of PacifiCorp's Form lO-K, it appears that
w
lQ
Re 2008 Idaho General Rate Case. IPUC Case No. PAC-E-05-08~ Order No. 29973 at 17.
Exhibit No. 614 at 5-6 (PacifiCorp's Response to Staff Data Request No. 25, Attachment 2, p. 3)
(emphasis added) in Washington Docket No. UE-100749).
See Id. at 2-3 (PacifiCorp's Response to Staff Data Request No. 25, Attachment 1 in Washigton
Docket No. UE-100749).
ll
31
Meyer, Di
PacifiCorp Idaho Industrial Customers
1668
.
.
.
1 these bonuses are tied to performance of PacifiCorp's parent company and
2 therefore not closely aligned to customer-related performance at the utilty leveL.
3 Unlike incentive compensation at the utilty-company level, MEHCand
4 MEC performance naturally relates more to financial success of the parent
5 corporation, the focus of which is on the financial performance of subsidiares.
6 MEHC's Form lO-K, page 144, states that the objective of anua bonus awards is
7 to "reward the achievement of significant anual corporate goals." The anual
8 bonuses are given on a subjective basis, but are based on defined objectives that
9 "commonly include financial and non-financial goals." MEHC's lO-K, on
10 page 143, states that the anual incentive awards are par of an overall
11 compensation philosophy meant to "create significant value for (MEHC)."
12 Q.
13
WHY ARE YOU RECOMMENDING DISALLOWANCE OF
LEGISLATIVE/CONTRIBUTION COSTS?
14 A.I believe costs associated with lobbying or influencing legislation should be
15 prohibited from recovery though rates. PacifiCorp's response to Public Counsel
16 Data Request No. 103 in WUTC Docket No. UE-100749 (Exhibit No. 615) shows
17 that the Company has included on a system-basis _ for "Legislative
18 (includes contributions)." Ths amount does not appear to include regulatory
19 costs, as there are separate "Regulatory" and "Reguation" cost categories. The
20 Idaho-allocated portion of legislative costs is _, which I have removed
21 completely.
32
Meyer, Di
PacifiCorp Idaho Industrial Customers
1669
. 1 Outside Services
2 Q.
3
DID RMP INCLUDE EXPENSES FOR OUTSIDE SERVICES IN ITS
COST OF SERVICE?
4 A.Yes. RMP has included the test year level (2009) of outside services expense in
5 its cost of servce.
6 Q. DO YOU AGREE WITH THE AMOUNT RMP HAS INCLUDED IN ITS
7 COST OF SERVICE?
8 A. . No, I do not. I believe the test year level proposed by RMP is too high.
9 Q. COULD YOU PROVIDE SOME EXAPLES OF OUTSIDE SERVICES
10 EXPENSE?
11 A.Yes. Outside services expense would include expenses for outside legal
12 expenses, engineering analysis, and other services.
.13 Q.
14
PLEASE PROVIDE THE HISTORICAL LEVELS OF EXPENSE RMP
HAS RECOVERED FOR OUTSIDE SERVICES EXPENSE.
15 A.Listed below in Table S are the levels of outside services expense assigned to
16 RMP's Idaho operations.
TABLES
Outside Services
Expense by Year
Year Amount
2006
2007
2008
2009
$1,067,814
$ S80,987
$ 670,661
$1,209,260
$ 882,181Four-Year Average
.33
Meyer, Di
Pacifi Corp Idaho Industral Customers
1670
.
.
.
1 As can be seen from the above table, the level of expense incured in 2009 is the
2 highest level of expense recorded by RMP since 2006.
3 Q.
4
5 A.
WHAT LEVEL OF EXPENSE DO YOU RECOMMEND FOR OUTSIDE
SERVICES?
I recommend a level of expense for outside services based on a four-year average
6 of the expenses listed above. I believe a four-year average is the more reasonable
7 level of expense. A four-year average of outside services expense would reduce
8 RMP's Idaho cost of service by $327,080.
9 Generation Overhaul Expense
10 Q.
11
12 A.
13
DID RMP PROPOSE TO ADJUST GENERATION OVERHUL
EXPENSES IN ITS COST OF SERVICE?
Yes. RMP proposed to decrease generation overhaul expense by $114,184 from
the test year leveL. RMP's adjustment normalizes generation overhaul expenses
14 using a four-year average methodology.
is Q.
16
17 A.
18
19
20
21
DO YOU AGREE WITH THE METHODOLOGY RMP USED TO
NORMALIZE THIS EXPENSE?
No. I am in disagreement with RMP on ths adjustment based on two points.
First, I do not agree that these expenses should be escalated for inflation in
calculating this adjustment. Second, I disagree with RMP's assumption used to
normalize expenses associated with new generation overhaul expenses. I am
proposing that RMP's adjustment to decrease generation overhaul expense by
34
Meyer, Di
PacifiCorp Idaho Industrial Customers
1671
.
.
.
1 $114,184 does not go far enough. The generation overhaul expense should be
2 fuher reduced by $134,918 on an Idaho basis.
3 Q.
4
PLEASE DESCRIBE RMP'S ESCALATION OF GENERATION
OVERHAUL EXPENSES.
5 A.RMP segregated the historical generation overhaul between Plants-Steam and
6 Plants-Other. For Plants-Steam, RM calculated an average where each year
7 prior to 2009 was escalated to 2009 dollars. RMP then compared ths inflation
8 adjusted average to the per book expense level for generation overhaul related to
9 Plants-Steam.
10 For Plants-Other, RMP calculated a historical inflation adjusted average
11 for existing generation. For new facilties in Plants-Other, the Company used an
12 inflation escalated average, but included some years of cost projections.
13 Suming the averages for both existing and new generation, RMP developed an
14 anualized level of generation overhaul expense.
15 Q.WHAT LEVEL OF EXPENSE HAS RMP RECORDED FOR
16 GENERATION OVERHAUL EXPENSE FOR THE YEARS 2006-20091
17 A.Table 6 shows the recorded expenses for generation overhaul expenses for RM.
3S
Meyer, Di
PacifiCorp Idaho Industrial Customers
1672
.
1
2
3
4.5
6
7
8
9
10
11
12
13
14
15
.
TABLE 6
Historical Analysis of Generation
Overhaul Expenses for Existing Generation
Steam Other
Year Generation Generation Total
2006 $29,613,264 $2,940,000 $32,5S3,264
2007 $28,S60,S41 $2,860,000 $31,420,S41
2008 $20,030,017 $1,72S,000 $21,7SS,017
2009 $2S,392,474 $2,SS2,000 $27,944,474
As can be seen from the table above, the level of actual generation
overhaul expenses over the historical period shows there are fluctuations from one
year to another, both upwards and downwards. The absence of an escalation
factor has not caused these fluctuations.
Q. WHY ARE YOU OPPOSED TO ESCALATING THE HISTORIC
GENERATION OVERHAUL EXPENSES?
A. The historic expenses recorded by RMP var by year, thus, indicating that past
expenses do not need to be escalated to present dollars.
Q. ARE YOU AWARE OF ANY STATEMENTS MADE BY RMP WHICH
WOULD ALSO LEAD ONE TO BELIEVE THAT AN ESCALATION
FACTOR SHOULD NOT BE USED FOR THESE EXPENSES?
A. Yes. In response to PIlC Data Request No. 63, RMP made the following
statement:
No other infation rates or escalation factors were used to estimate
test year cost levels.
36
Meyer, Di
PacifiCorp Idaho Industrial Customers
1673
.
.
.
1
2
3 Q.
4
S A.
6
7
8
9
10
11
12
13 Q.
14 Á.
is
I therefore recommend that the generation overhaul expense adjustment be
recalculated without the use of an escalation factor.
DO YOU HAVE CONCERNS WITH THE METHODOLOGY RMP USED
TO ESTIMATE NEW PLANT GENERATION OVERHUL EXPENSES?
Yes, I do. RMP developed four years of expenses for each new power plant by
estimating generation overhaul expenses for certain plants to be incured through
calendar year 2012. This methodology produced a level of expense of
$3,808,000. I believe ths methodology overstates the generation overhaul
expenses. I recommend that the new plant generation overhaul expenses be
developed using the four-year average of expenses incured for those plants from
2007-2010 (estimated expenses). Using my recommended methodology produces
an anual level of expense of $2,837,000 on an Idaho basis.
DO YOU FEEL THE LEVEL YOU HAVE PROPOSED IS REASONABLE?
Yes, I do. RMP has estimated what its generation overhaul expenses will be for
these new plants for 2010-2012. I have listed in Table 7 these expense levels.
TABLE 7
Estimated New Plant
Generation Overhaul Expenses
Year Amount
2010
2011
2012
$ 232,000
$2,S79,000
$1,898,000
37
Meyer, Di
PacifiCorp Idaho Industrial Customers
1674
.
.
.
1 As can be seen from the above table, the level I have recommended of
2 $2,837,000 is more than adequate to provide generation overhaul expenses for
3 these new plants.
4 Q.
5 A.
PLEASE SUMMARIZE YOUR POSITION.
I recommend that the escalation factor for generation overhaul expenses be
6 eliminated from RMP's adjustment. The history of ths expense does not reveal
7 that these expenses need to be escalated. Furermore, RMP states that no
8 expenses should be escalated.
9 I also recommend that the new plant generation overhaul expense level be
10 set at $2,837,000. RMP's proposed level of $3,808,000 is excessive and will not
11 be incured by RMP prior to 2013. If the Commission feels that the level of new
12 plant generation overhaul expense I have proposed is also excessive, then I would
13 suggest that the level of expense for 2011 as estimated by RMP be used
14 ($2,579,000).
15 RMP's cost of service should be reduced by $134,918 on an Idaho
16 jursdictional basis as a result of my recommended adjustments to generation
17 overhaul expenses.
18 Un collectibles
19 Q.
20
HAS RMP INCLUDED UNCOLLECTIBLE EXPENSE IN THEIR COST
OF SERVICE?
21 A.Yes. RMP is requesting that cost of service include the level of uncollectibles
22 recorded in the test year (2009) of $472,263.
38
Meyer, Di
PacifiCorp Idaho Industrial Customers
1675
.1 Q.
2
3 A.
4 Q.
S
6 A.
7
8
.
.
9
10
ii
12
13
14
is
DO YOU AGREE WITH THE AMOUNT RMP PROPOSES TO INCLUDE
IN THE COST OF SERVICE?
No, I do not. I believe that the level proposed by RMP is too high.
WHAT LEVEL DO YOU PROPOSE BE INCLUDED IN COST OF
SERVICE FOR UNCOLLECTIBLES?
I am recommending that a four-year average of uncollectibles be included in the
cost of service. Listed in Table 8 are the levels of uncollectibles and anua rate
revenues recorded by RMP for each calendar year from 2006-2009.
TABLES
Uncollectible Expense By Year
Year Amount Revenues
2006
2007
2008
2009
$529,196
$308,SLO
$303,8S6
$472,263
$140,2S0,947
$182,699,838
$197,SOS,456
$184,995,386
As can be seen from the above table RMP is proposing the highest level of
uncollectible expense that has been experienced by RMP since 2006. The table
also reveals that the level of revenue does not dictate the level of uncollectibles.
For example, in 2008 the revenues were the highest, yet the uncollectibles were
not the highest in that year. I believe a four-year average is the more reasonable
adjustment for this expense. A four-year average of the uncollectibles expense
would reduce the Company's Idaho cost of service by $68,807.
39
Meyer, Di
PacifiCorp Idaho Industrial Customers
1676
.
.
.
1 Q.
2 A.
DOES TIDS CONCLUDE YOUR DIRECT TESTIMONY?
Yes, it does.
40
Meyer, Di
PacifiCorp Idaho Industrial Customers
1677
.
.
.
18
19
20
21
22
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Is he ready for
4 cross-examination?
5 MS. DAVISON: Yes, Madam Chair.
6 COMMISSIONER SMITH: Mr. Purdy, do you have any
7 questions?
8 MR. PURDY: I do not.
9 COMMISSIONER SMITH: Mr. Olsen.
10 MR. OLSEN: I do not, Madam Chair.
11 COMMISSIONER SMITH: Mr. Otto.
12 MR. OTTO: No, I don't.
13 COMMISSIONER SMITH: Mr. Woodbury.
14 MR. WOODBURY: Staff has no questions.
15 COMMISSIONER SMITH: Mr. Budge.
16 MR. BUDGE: No questions.
17 COMMISSIONER SMITH: Mr. Hickey or Mr. Solander.
MR. HICKEY: Solander.
MR. SOLANDER: Thank you.
CROSS-EXAMINATION
23 BY MR. SOLANDER:
24
25
Q.Good afternoon, Mr. Meyer.
A.Good afternoon.
1678
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
MEYER (X)
PIIC
.
.
20
1 Q.You recognize an incentive pay can be an
2 appropriate and useful management tool?
3 A.Yes.
4 Q.And you would agree that an acceptable part of an
5 incentive plan would include goals that improve or maintain
6 Rocky Mountain Power's existing operational performance?
7 A.That's my testimony.
8 Q.And you would agree that providing or improving
9 customer service would fall under that umbrella?
10 A.Could you restate that? I'm sorry.
11 Q.Would you agree that giving employees an
12 incenti ve to provide or improve excellent customer service
13 would improve or maintain the Company's operational
14 performance?
15 A.If your question is would improving customer
16 service improve service, I would agree with that.
17 Q.Okay. And would you agree that incentives
18 intended to ensure provision of reliable service are an aspect
19 of improving operational performance?
A.I would hope that would be a goal. I'm not
21 sure -- I wouldn't agree with you that it would ensure it.
22 Q.Would you agree with Mr. English's statement that
23 any incentive with ties to operating budgets are inappropriate?
24.25
A.I probably would have some disagreement with
Mr. English. I believe that I'd much rather see improvements
1679
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
MEYER (X)
PIIC
.
.
20
21
22
23
24.25
1 in actual costs and actual savings. I have concerns sometimes
2 wi th the use of budgets because of their ability of being
3 manipulated.
4 Q.Do you believe that if the Commission finds that
5 the Rocky Mountain Power incentive programs includes the goals
6 that we discussed including customer service, reliability,
7 safety, 0 and M expenses, budgets, that those portions of the
8 incenti ve plan expense should be recovered in rates?
9 A.If you can demonstrate that the presence of
10 incenti ve compensation improved in those areas over actual
11 results, I would agree with you.
12 Q.So you believe that if the Commission makes that
13 finding, then those should be recovered in rates?
14 A.With the caveat I just made, yes.
15 MR. SOLANDER: I have no further questions.
16 COMMISSIONER SMITH: Do we have questions from
17 the Commissioners?
18 COMMISSIONER KEMPTON: No.
19 COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: Nor I.
Ms. Davison, any redirect?
MS. DAVISON: No, Madam Chair.
COMMISSIONER SMITH: Okay.
Thank you for your help.
THE WITNESS: Thank you.
1680
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
MEYER (X)
PIIC
.
.
.
1 COMMISSIONER SMITH: Would you like this witness
2 to be excused?
3 MS. DAVISON: Thank you for that reminder. Yes,
4 I would, Madam Chair.
5 COMMISSIONER SMITH: If there's no obj ection, he
6 may be excused.
7 (The witness left the stand.)
8 MS. DAVISON: I would like to call to the witness
9 stand Mr. Don Schoenbeck.
10
11 DONALD SCHOENBECK,
12 produced as a witness at the instance of PacifiCorp Idaho
13 Industrial Customers, being first duly sworn, was examined and
14 testified as follows:
15
16 DIRECT EXAMINATION
17
18 BY MS. DAVISON:
19 Q.Good afternoon, Mr. Schoenbeck. Could you please
20 state your full name and spell your last name for the record?
21 A.Certainly. My name is Donald W. Schoenbeck.
22 That's S-C-H-O-E-N-B-E-C-K.
23
24
25
Q.And by whom are you employed, Mr. Schoenbeck?
A.Regulatory and Cogeneration Services.
Q.Are you the same Mr. Schoenbeck who prepared
1681
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (Di)
PIIC
.
.
.
1 testimony on behalf of the PacifiCorp Idaho Industrial
2 Customers dated October 14th, 2010, in this docket?
3 A.Yes, I am.
4 Q.And do you have any changes or corrections to
5 your testimony?
6 A.I do have one at the bottom of page 8.
7 Q.And you said that was page 8?
8 A.Right, line 23.
9 Q.Yes.
10 A.Delete the word "same" S-A-M-E -- and delete the
11 words starting with "class values" through the end of that
12 sentence. Then insert after the word --
13 COMMISSIONER SMITH: Does that include on the top
14 of page 9?
15 THE WITNESS: Yes, it does.
16 COMMISSIONER SMITH: Thank you.
17 THE WITNESS: And then insert the words
18 "distribution peaks" after the word "coincident" on line 23.
19 So I'll read the sentence as it should be
20 corrected: For the main distribution demand allocation factor,
21 the Company starts with the 12 monthly coincident distribution
22 peaks. Period.
23 Q.BY MS. DAVISON: And, Mr. Schoenbeck, can you
24 explain the reason for that exchange?
25 A.Certainly. As it had been drafted, the
1682
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (Di )
PIIC
.
.
20
21
22
23
24
. 25
1 assumption was the system coincident peak and the distribution
2 peak were precisely the same hour for all 12 months. That is
3 not the case. For the month of January, it was indeed the same
4 hour, so it was the same value. For the other 11 months , it
5 was a different hour, though very close to the coincident
6 system peak hour.
7 Q.Thank you. If I were to ask you these questions
8 today, would your answers be the same?
9 A.Yes, they would.
10 MS. DAVISON: Madam Chair, we'd like to move that
11 Mr. Schoenbeck's testimony be spread upon the record, and
12 identified for the record Exhibits 601, 602, 603, and 604 for
13 Mr. Schoenbeck.
14 COMMISSIONER SMITH: If there's no objection, it
15 is so ordered.
16 (The following prefiled direct testimony
17 of Mr. Schoenbeck is spread upon the record.)
18
19
1683
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (Di)
PIIC
.I. INTRODUCTION AND SUMMARY
1 Q.PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A.My name is Donald W. Schoenbeck. I am a member of Regulatory &
3 Cogeneration Services, Inc. ("RCS"), a utilty rate and economic consulting firm.
4 My business address is 900 Washington Street, Suite 780, Vancouver, WA 98660.
5 Q.PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE.
6 A.I've been involved in the electric and gas utilty industries for over 35 years. For
7 the majority of this time, I have provided consulting services for large industrial
8 customers addressing regulatory and contractual matters. A further description of
9 my educational background and work experience can be is attached as Exhibit
10 601 in this proceeding..11 Q.ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?
12 A.I am testifying on behalf ofthe PacifiCorp Idaho Industrial Customers ("PIIC").
13 PIIC is a coalition of Idaho industrial companies served by Rocky Mountain
14 Power ("RMP" or the "Company").
15 Q.WHAT TOPICS WILL YOUR TESTIMONY ADDRESS?
16 A.I wil address the Company's hourly load data, certain aspects ofthe Company's
17 cost-of-service study presented in Exhibit No. 49, the Company's proposed rate
18 spread presented in Exhibit No. 50 and Schedule 6, 6A and 9 rate design. This
19 testimony wil not address revenue requirement issues. PUC is submitting
20 separate testimony regarding revenue requirement matters.
.1
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers1684
.
.
.
1 Q.
2
3 A.
4
S
6
7
8
9
10
11
12
13
14
is
16
17
18
19
20
21
22
PLEASE BRIEFLY SUMMARIZE YOUR FINDINGS AND
RECOMMENDATIONS ADDRESSED IN TIDS TESTIMONY.
The Company's jurisdictional separation study uses hourly load data from 2010 to
assign system costs between the varous state jursdictions with certin
adjustments. However, the Company's cost-of-service study uses hourly load
data from 2009 for most classes and an average of five historical years for the
irrgation class (Schedule 10) and one of the contract customers for assigning
generation and transmission demand-related costs. In future proceedings, PIlC
recommends the same load research data be used in both studies to more
accurately determine cost responsibilty. The demand allocation factors used in
the Company's cost of service study should be modified to more accurately assign
demand-related costs. I recommend the class demand allocation factor be based
on the comparable jurisdictional peak hour with a more up to date irrgation class
demand. The Company's twelve monthly coincident peak factor ("12 CP") for
assigning generation and transmission-related demand costs should be replaced
with a winter/sumer peak factor ("W/S CP") using the peak load months of July
and December. The weighted twelve monthly peak factor used by the Company
for distribution-related demand costs should be replaced with the class maximum
peak demands ("1 NCP") to more accurately assign distribution cost
responsibilty .
The Company's rate spread recommendation is based on the results
indicated by its cost study. PILC supports a cost-based rate spread approach, but it
2
ß.choenbeck, Di16 WcifiCorp Idaho Industral Customers
.1 should be done using the results of the PILC cost-of-service study.
2 The Company's Schedule 6, 6A and 9 rate design applies a slightly greater
3 increase to the demand charges as compared to the energy charges. PILC supports
4 this cost-based rate design for these rate schedules.
5 Q.
6 A.
7
8
9
10.11
12
13
14
15
16
17
18
19
20
.
II. HOURLY LOAD DATA
PLEASE EXPLAIN THE RELEVANCE OF LOAD RESEARCH DATA.
Load research data is the necessary foundation of any cost-of-service study. Most
of the meters installed for biling purposes do not have the capabilty to record
customer usage by time period (for example, at five minute intervals). Typical
meters for residential customers and small commercial customers simply record
accumulated energy usage (kilowatt-hours, or "kWhs"). The next most prevalent
meters-installed for customers on a tariff with demand charges-record the
accumulated kWhs and the peak hourly value for the biling period. Usually, only
the largest customers-such as those on Schedule 9-have "time-of-use" meters
installed. These meters record energy usage at very small time intervals-
typically every five minutes. Consequently, it is necessary to undertake a load
research program and install time-of-use meters-generally through a sampling
selection process-to ascertain class demand levels and class contributions to
system or local peaks for almost all classes of customers. Absent this critical
information, "guestimates" must be made to derive the demand allocation factors
used to assign class cost responsibilty within a cost-of-service study.
3
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers1686
.1 Q.DOES THE COMPANY HA VE CURRNT LOAD RESEARCH
2 INFORMTION FOR ALL CUSTOMER CLASSES?
3 A.Yes. The Company's response to the Idaho Irrigation Pumpers Association, Inc.
4 ("LIP A") Data Request 2D (attached as Exhibit 603) indicates the time period over
5 which the load research data was collected. Except for Schedule 19, the data
6 response indicates very recent time periods. The Company's response to IIPA
7 Data Request 8 (attched as Exhibit 604) includes an EXCEL spreadsheet that
8 contains the 2009 test period hourly loads for each class. The hourly load
9 research data from 2009 was adjusted upward or downward to achieve the
10 monthly energy sales level for each class. The Company provided this data as
ii support for the class cost-of-service study demand allocation factors.
12 Q.DID THE COMPANY USE THIS SAME TYPE OF HOURY CLASS.13 LOAD DATA IN ITS JURISDICTIONAL SEPARATION STUDY TO
14 DERIVE THE ALLOCATION OF SYSTEM COSTS TO IDAHO?
15 A.No. As noted in the written response to LIP A 8, the Idaho jursdictional loads
16 were not derived from class hourly load data. The response states that "different
17 data sources" are used and that the class load data does not "flow through to the
18 state jursdiction load."
19 Q.HAVE YOU ANALYZED AND COMPARED THE JURISDICTIONAL
20 PEAKS AND THE CLASS LOAD PEAKS?
21 A.Yes. The following table presents the monthly Idaho jurisdictional megawatt
22 ("MW") peak values from RMP's Exhibit 2, page 10.13, with the class peak
23 demands set forth in Exhibit 49.
.4
1 6 rShoenbeck, DiY,àcifiCorp Idaho Industral Customers
.
Jurisdictional Adjusted
Cost Study Difference CostMonthDataJurisdictionalDataStudy - Adj JurisData
January 406 406 466 60
February 416 416 434 18
March 399 399 396 -3
April 415 415 387 -28
May 503 503 442 -61
June 613 429 633 204
July 664 475 496 21
August 538 356 534 178
September 447 447 388 -59
October 406 406 372 -34
November 443 443 414 -29
December 467 467 40 -63
1 The values in the colum labeled "Jurisdictional Data" are the projected peaks
2 prior to any adjustments for any load curailment or dispatch program. The.3 colum labeled "Adjusted Jurisdictional Data" are the values that are used to
4 allocate and assign system related costs to Idaho. In this colum, the months of
5 June, July and August contain lower values (about 18S MWs) reflecting the
6 expected curtailment attibutable to the irrgation load control programs. The
7 colum labeled "Cost Study Data" shows the aggregate system peak used in the
8 cost study. For this colum, it should be noted that the peak demand for the
9 irrgation class is derived from five years of historical data affecting the demands
10 for the months of June through September. (The Company used a five year
11 average of historical data for one contract customer as well). The last colum in
12 the above table shows the difference between the adjusted jurisdictional load and
.5
~ S,choenbeck, Di1 6öpacifiCorp Idaho Industrial Customers
.1
2
3
4
S Q.
6
7 A.
8
class demand total. A cursory review of this column raises concerns over the
level of the irrigation peak demand in the cost study during the irrgation season
but there are differences in all other months that cannot be explained by simply
the one year difference represented by the data (2009 versus 2010).
ARE THE PEAK DEMANDS IN THE ABOVE TABLE FOR THE SAME
DAY AND HOUR OF EACH MONTH?
No. The following table shows the day and hour of the peak demand used in the
jurisdictional separation study and the class cost of service study.
Month Jurisdictional Compay Cost
Peaks Study
January 25th, 19:00 27th, 9:00
February 4th, 8:00 10th, 20:00 .March 30th, 8:00 lIth, 9:00
Apri 1st, 8:00 1st, 10:00
May 18th, 15:00 29th, 17:00
June 24th, 15:00 29th, 18:00
July 19th, 16:00 27th, 18:00
August 26th, 15:00 3rd,18:00
September 9th, 15:00 2nd, 17:00
October 4th, 19:00 28th, 1000
November 24th, 18:00 30th, 19:00
December 15th, 18:00 9th, 9:00
9
10
11
12
13
.
As shown by the table, there is only one single month-April-where the two
studies use the same peak day. There is no month when the same hour is used.
Given the readily available load research data the Company has, there should be a
direct linkage between the data used in the jurisdictional and class studies. By
doing so, the monthly peak hours and loads would be the same in the two studies.
6
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers1689
.1 Q.
2
3
HAVE YOU COMPARED THE CLASS LOAD DATA BETWEEN THE
JURISDICTIONAL PEAK HOUR AND THE COMPARABLE CLASS
PEAK HOURS
4 A.Yes. The following table shows the class peak for the same hour and same day
5 of the week as had been used in the jurisdictional study. In other words, as the
6 January system peak was a Monday, the class study value shown in the following
7 table is for Monday, January 26, 2009 at 19:00 hours.
Class Compay Cost Difference Cost
Month Study-Class Lod
Load Data Study Data
January 46 46 6
February 44 434 -6
March 365 396 31.April 428 387 -41
May 453 442 -11
June 601 633 32
July 567 496 -71
August 534 534 0
September 422 388 -34
October 373 372 - 1
November 395 414 19
December 387 404 17
8 The above table shows a wide variation between the two sources across all twelve
9 months. While there are some months where the values are quite close (January,
10 February, May, August and October), there are also several months where the
11 difference are quite large (March, April, July and September). These differences
12 would not exist ifthe Company used the same load research data for both the
.7
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1690
.1 jurisdictional and class studies. PIIC recommends the Commission require this of
2 the Company in future proceedings.
3 III. COST OF SERVICE - PEAK DEMAND SELECTION
4 Q.HAVE YOU ANALYZED THE COST -OF-SERVICE STUDY PRESENTED
5 BY THE COMPANY IN THIS PROCEEDING?
6 A.Yes. I analyzed the Company's cost-of-servICe study submitted as Exhibit 49,
7 reviewed the associated workpapers, reviewed the Company's responses to data
8 requests of other parties addressing cost-of-service matters and sought additional
9 information through PIIC data requests.
10 Q.DO YOU AGREE WITH THE MANNER IN WHICH THE STUDY WAS
11 DONE?
12 A.No. I disagree with the method employed by the Company to allocate demand-.13 related generation, transmission and distribution costs.
14 Q.HOW HAS THE COMPANY CALCULATED THE PEAK DEMANDS
15 USED IN ITS COST-OF-SERVICE STUDY?
16 A.The Company's study uses two main demand (or peak) allocation factors: class
17 coincident demands for generation and transmission costs and a weighted monthly
18 class coincident demand for major distribution costs (substations, pole, cable and
19 conductor). For each ofthese demands, the Company uses the class values from
20 all 12 months of the year. For the generation and transmission demand allocation
21 factor, it is simply the sum of all twelve monthly coincident peak values (" 12
22 CP"). For the main distribution demand allocation factor, the Company starts
23 with the same twelve monthly coincident class values as used for the generation
.8
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1691
.and transmission allocation factor. However, the Company applies a monthly
2 weighting factor to the class peaks based upon the number of distribution
3 substation peaks that have occurred in each month for the last five years. The
4 following table shows the derivation of these monthly weighting factors.
Month 2005 200 2007 2008 200 5YrAvg Weight
January 6 1 9 11 2 5.8 8.01%
February 4 0 3 6 1 2.8 3.87%
March 0 2 0 0 2 0.8 1.0%
April 2 1 1 1 1 1.2 1.66%
May 0 4 4 2 5 3 4.14%
June 17 13 20 8 5 12.6 17.40%
July 32 28 14 32 19 25 34.53%
August 4 12 13 8 22 11.8 16.30%
September 1 2 1 1 2 1.4 1.93%
October 2 0 1 0 0 0.6 0.83%.November 2 3 2 1 1 1.8 2.49%
December 2 6 5 3 12 5.6 7.73%
Total 72 72 73 73 72 72.4 ioo.()()01o
5 As shown by the final weighting factors, the Company's approach tends to
6 emphasize the peak demands that occur during the three summer months (with
7 factors ranging from 16.3% to 34.5%) as compared to all other months.
8 Q.WHY DO YOU DISAGREE WITH THE USE OF ALL TWELVE
9 MONTHLY PEAKS FOR THE GENERATION AND TRANSMISSION
10 DEMAND ALLOCATION FACTOR?
1 i A.Using a value based upon all twelve months is inappropriate as it dramatically
12 understates the demand level of certin classes. Giving each and every month
13 equal weighting ignores the fundamental driver of new generation, transmission
.9
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1692
.1 or distribution investment. The need for these facilties is determined based on
2 the peak demands placed on such facilties. Including other irrelevant demands in
3 the derivation of the class value simply causes a shift in cost responsibilty to
4 other classes in the cost study. This latter point can be appreciated by reviewing
5 the following table containing the adjusted PacifiCorpll system monthly peak data
6 from RMP's Exhbit 2, page 10.2.
Adjusted Percent of MWs
BelowMonthJurisdictionalPeakPeakDataMonthMonth
January 8,514 93%66
February 8,221 9Q1o 957
March 7,661 83%1,516
April 7,257 79%1,921.May 7,848 86%1,330
June 8,407 92%771
July 9,178 100%0
August 8,975 98%202
September 8,356 91%822
October 7,336 80%1,842
November 8,322 91%856
December 8,722 95%455
7 Most of the months have peak demands substantially below the sumer peak
8 value that occurs in July. However, the December value is relatively close
9 (within 5%) thereby identifying PacifiCorp as having a dual peak with both winter
11 When I reference PacifiCorp in this testimony, I am referring to PacifiCorp's entire six state
system and not just RM.
.10
Schoenbeck, Di16 %.cifiCorp Idaho Industrial Customers
.
.
.
1
2
3
4
S
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
17
18
19
20
21
22
and sumer months being important. For most of the remaining months, the peak
load level is significantly below the peak demand leveL. For example, the four
months of March, April, May and October are over 1,000 MWs less than the
system peak value. As generation and transmission demand-related costs
represent a substantial amount of the Company's proposed revenue requirement,
use ofthe Company's 12 CP system demand allocation factor is wrong. The
Company's generation and transmission demand related costs should be allocated
using the July and December jurisdictional peak hours, taking into account an
appropriate adjustment for the irrgation class in July to reflect the load control
programs.
WHY DOES THE IRRGATION CLASS LOAD NEED TO BE
ADJUSTED?
As previously noted, the irrigation class demand is based on the average load
level for the past five years. This is inappropriate as the Company's load control
programs for the irrgation class have grown substantially in recent years. The
following table shows the avoided MWs for just the irrigation dispatch program
compiled from the Company's Schedule 72 & 72A Idaho Irrgation Load Control
Program Reports. This shows a substantial growth in the program from just 2007
to 2009 of over 160 MW. Furter, the Company's response to IIPA Data Request
23 indicates an expected 2010 avoided load of282 MWs in July under the Idaho
load control programs. Basing the 2009 irrgation load level on years prior to
2009 will overstate the demand contrbution for this class due to the substatial
11
Schoenbeck, Di1 61'cifiCorp Idaho Industral Customers
.1 in program participation.
Highest Mean Highest
Year Event Hour
2007 76 76
2008 203 210
2009 237 242
Average:172 176
200-Avg 65
2 Q.
3 A.
4
5
6.7
8
9
10
11
12
13
14
15
16
HOW SHOULD THE IRRGATION CLASS LOAD BE ADJUSTED?
There are at least two ways in which a reasonable adjustment could be done.
Using the Company's historical class load data, the Company could re-construct
the hourly class loads assuming no curtilments had occurred in 2009. Then the
current expected program curtailment amount could be deducted from the summer
irrigation months to arrive at the value to use for cost allocation purposes. As an
example to ilustrate this approach, assume the "un-curtailed" irrigation demand
for the July peak hour is 350 MWs and the expected net avoided MWs given
current customer paricipation levels is 250 MWs. The adjusted July peak for this
class would be 100 MWs (350 MWs - 250 MWs = 100MWs). A second method
is to rely in part on the jurisdictional hourly load data using the assumed level of
net curtailment from the jurisdictional study applied to the class load data. To
ilustrate this approach, the unadjusted Idaho coincident peak for July is 664 MWs
while the adjusted peak is 475 MWs. For the comparable hour, the class load data
has an Idaho peak of 567 MWs, a value 92 MWs above the jurisdictional value.
.12
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers1695
.13
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1696
.
.
.
1 derivation of the distribution demand allocation factor ignores the localized
2 diversity that exists on the Company's distribution system. The 72 distribution
3 substations have a capacity of over 1,100 MW s in order to provide reliable
4 localized service. For 2009, these substations had an accumulated peak load of
5 628 MW s. Yet, the highest coincident peak for all twelve months used in the
6 Company's allocation factor is just 483 MWs and the average ofthe 12 monthly
7 distribution coincident peaks is less than 300 MWs.
8 Application of the Company's monthly weighting factors tends to lessen
9 the impact of using all 12 monthly values but in actuality, this is an unnecessary
10 step. Absent having the most accurate metrc (class loads at each substation
11 peak), a reasonable-and most often used-alternative is class non-coincident
12 demand levels as acknowledged by the NARUC Electric Utilty Cost Allocation
13 Manual ("1 NCP"). PIlC recommends this method be used to ascertain
14 distribution demand-related cost responsibilty. The following tables compare: 1)
15 the Company's weighted 12CP demand approach; 2) the maximum coincident
16 demand for each class; and 3) the class maximum non-coincident peak demand
17 ("1 NCP") I derived from the hourly load research data.
14
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1697
.
.1
2
3
4 Q.
5
6
7 A.
8
9
10
11
.
Company
Weighting Maxm Maxim Class
Class (Schedules)Method Coincident Peak Hourly Peak
Residential (1/36)113 194 208
Small Power (23)25 35 38
Large Power (6/35)53 64 68
Irrgation (10)199 314 320
Total:390 606 633
Class (Schedules)
Residential (1/36)
Small Power (23)
Lage Power (6/35)
Irrgation (10)
Total:
Company
Weighting
Method
28.90%
6.40%
13.60%
51.0%
100.00%
Maxum
Coincident Peak
32.00%
5.70%
10.60%
51.70%
100.00%
Maxium Class
Hourly Peak
32.80%
6.l001o
10.70%
50.50%
100.00%
It is apparent from the table that the Company's method has understated
the costs assigned to Schedules 1 and 36 while overstating the distribution
demand costs assigned to all other major rate schedules.
HAVE YOU PERFORMED A COST -OF-SERVICE SENSITIVITY
INCORPORATING ALL YOUR DEMAND ALLOCATION FACTOR
RECOMMENDATIONS?
Yes. Exhibit 602 to this testimony is the summary page from the Company cost-
of-service model modified to reflect my recommendations. The following table
compares the revenue to cost ratio (or "parity ratio") from the Company's study
and the PIlC for the major customer classes. The parity ratio is the most
appropriate yardstick for determining whether the rate schedule charges are
15
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers1698
.
.
.
1 equitable to each customer class. It is a statistic that takes into account both the
2 operating expenses and the rate base needed to serve each customer class. The
3 relationship between operating expense and rate base wil vary depending upon
4 the utilzation offacilties (or load factor) for each class. For example, a class
5 with a low load factor wil require a larger rate base investment relative to
6 operating expense. On the other hand, a class with a high load factor wil require
7 more operating expense as compared to rate base investment. As the parity ratio
8 includes both the return on rate base and the operating expenses of each class, it is
9 the most accurate measure to use in rate spread determinations. A parity ratio less
10 than 1.0 or 100% indicates a class is not paying its fair share of costs.
11 Conversely, a ratio greater than 100% indicates the class is paying charges in
12 excess of its cost responsibilty.
Class Company PIIC
Residential 105%104%
Residential - TOD 99%97%
General Service - Large 100010 103%
General Service - High Voltage 99%102%
Irrgation 104%105%
Street & Area Lighting 145%130010
Space Heating 102%97%
General Service - Small 103%103%
Contract 1 94%94%
Contract 2 97%108%
State ofldaho 100%100010
13 The difference in parity ratios for all major customers classes changes only
14 slightly from the Company's study. The largest parity change between the two
16
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1699
.1 studies is for the lighting class, but the PIIC parity ratio is stil quite high at 130%.
IV. RATE SPREAD
2 Q.HOW is THE COMPANY PROPOSING TO RECOVER ANY REVENUE
3 INCREASE GRANTED BY THE COMMISSION IN THIS PROCEEDING?
4 A.The Company proposal tracks the results of its cost of service study very closely.
5 The noted exception is for the lighting class where the Company is proposing no
6 rate decrease for this class even though the cost study indicates it would be
7 justified. For the lighting class, the Company is proposing no rate change at this
8 time.
9 Q.DO YOU SUPPORT THE COMPANY'S RATE SPREAD PROPOSAL?
10 A.I support the objective of achieving cost-based rates. However, the Company's
11 cost-of-service study should not be used for determining an equitable rate spread.12 in this proceeding. Instead, the PIIC cost study should be used as the foundation
13 to achieve a cost-based rate spread in this proceeding. The following table
14 compares the cost-base rate spreads from the Company and PIIC study at the full
15 increase sought by the Company.
.17
Schoenbeck, Di
PacifiCorp Idaho Industral Customers1700
.
Company Proposed Pnce Increase - $000
Company
Class Study PIlC Study Difference
Residential $3,167 $3,781 $614
Residential - TOD $3,236 $3,607 $371
General Service - Large $3,00 $2,357 ($6)
General Service - High Voltage $741 $572 ($169)
Irrgation $3,852 $3,443 ($410)
Street & Area Lighting ($165)($108)$57
Space Heating $65 $97 $32
General Service - Small $1,345 $1,455 $110
Contract 1 $11,741 $12,340 $599
Contract 2 $715 $155 ($561)
State ofIdaho $27,698 $27,698 $0
1 Q.WHAT is YOUR SPECIFIC RATE SPREAD RECOMMENDATION?
2 A.The following table presents my specific recommendation along with the
3 Company proposal for comparative purposes at the Company's full request.4 amount. As shown by the table, the PUC recommendation gives no increase to
S the lighting rate schedules and a cost-based increase to all other classes.
.18
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers1701
.
1 Q.
2 A.
3.
4
.
Class Company
Pro osal
$3,135
$3,219
$2,984
$737
$3,820
$0
$6
1,335
$11,696
$712
$27,702
Residential
Residential - TOD
General Service - Large
General Service - High Voltage
lnigation
Street & Area Lighting
Space Heating
General Service - Small
Contract 1
Contract 2
State ofIdaho
PIIC
Recommendation
$3,766
$3,593
$2,348
$570
$3,430
$0
$97
$1,450
$12,294
$154
$27,702
Difference
$632
$374
($636)
($167)
($390)
$0
$32
$115
$598
($558)
$0
HOW WOULD YOU ALLOCATE THE COMPANY'S RATE INCREASE?
The rate increase should be spread to the various classes using the following
percentages.
Class
Residential
Residential - TOD
General Service - Large
General Service - High Voltage
Inigation
Street & Area Lighting
Space Heating
General Service - Small
Contract 1
Contract 2
State ofIdaho
Rate Spread
Percentages
13.6Q1o
12.97%
8.47%
2.06%
12.38%
0.00%
0.35%
5.23%
44.38%
0.56%
100.00%
The percentages were derived from the PILC rate spread recommendation at the
19
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1702
.1 Company's full request amount.
V. INDUSTRIAL RATE DESIGN
2 Q.HOW IS THE COMPANY PROPOSING TO RECOVER THE REVENUE
3 INCREASE ASSIGNED TO INDUSTRIAL SCHEDULE 6, 6A AND 9
4 CUSTOMERS?
5 A.The Company's rate design increases the demand charges by a larger percentage
6 than the energy charges. Specifically, under the Company's full request, the
7 demand charges for Schedules 6 and 6A are being increased by about 17% while
8 the energy charges are being increased by 12%. For Schedule 9, the demand
9 charges are increased by 21 % while the energy charge is being inèreased by 12%.
10 Q.DOES PUC SUPPORT THIS RATE DESIGN PROPOSAL FOR THE
11 INDUSTRIAL SCHEUDLES?
12 A.Yes. The Company's cost-of-service model aggregates the costs allocated to.13 these schedule into three categories that are extremely useful for rate design
14 purposes. These categories are: customer, energy, and demand. A comparison of
15 the per unit costs for the demand and energy categories from the cost study with
16 the per unit revenue recovery from the industrial schedules provides valuable
17 infonnation on how to assign any schedule's rate increase. In the instant case,
18 this comparison shows that the Company's proposal is justified-the demand
19 charges should be given a greater percentage increase than the energy charges.
20 PILC supports the Company's industral rate design proposal in this proceeding.
21 Q.DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
22 A.Yes, it does.
.20
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1703
.
.
20
1 (The following proceedings were had in
2 open hearing.)
3 MS. DAVISON: Mr. Schoenbeck's ready for cross.
4 COMMISSIONER SMITH: Thank you.
5 Mr. Purdy, do you have questions?
6 MR. PURDY: I do not.
7 COMMISSIONER SMITH: Mr. Olsen.
8 MR. OLSEN: No questions, Madam Chairman.
9 COMMISSIONER SMITH: Mr. Otto.
10 MR. OTTO: No questions, Madam Chair.
11 COMMISSIONER SMITH: Mr. Woodbury.
12 MR. WOODBURY: Thank you, Madam Chair, just one.
13
14 CROSS-EXAMINATION
15
16 BY MR. WOODBURY:
17 Q.Mr. Schoenbeck, directing you to your testimony
18 on page 11
19 A.Yes, I have that.
Q.-- at line 7, you propose to use two coincident
21 peaks for July and December to allocate demand-related
22 generation and transmission costs to customer classes, do you
23 not?
24.25
A.That's correct.
Q.Do you know if any electric utility regulated by
1704
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (X)
PIIC
.
.
20
1 this Commission has a Commission-approved allocation method
2 that uses anything other than 12 monthly coincident peaks as
3 proposed by the Company and Staff in this case?
4 A.Certainly. For example, we can take the current
5 Company -- PacifiCorp -- and in their Washington jurisdiction,
6 their
7 Q.No, not in other jurisdictions, but in Idaho.
8 A.Oh, I'm sorry, I misheard.
9 Q.So I'm speaking of Avista and PacifiCorp and
10 Idaho Power.
11 A.I'm not aware of another utility in Idaho.
12 Q.Please turn to page 18 of your direct testimony,
13 and there is a chart at the top of that page. Correct?
14 A.Yes, there is.
15 Q.And your customer grouping for -- where does it
16 fall in as far as the classes in that chart?
17 A.The large general service class, the general
18 service high voltage class, the irrigation class, and the
19 Contract 2 class.
Q.Does your proposed methodology require a smaller
21 increase for the classes you represent than Idaho -- Rocky
22 Mountain Power's methodology?
23 A.A modestly smaller increase. My testimony
24 advocates that two changes be incorporated into the Company's.25 cost study. The first is dealing with system coincident
1705
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (X)
PIIC
.
.
1 demands going to just a winter/summer peak as you had noted,
2 and the second change goes to the allocation of distribution
3 demand-related cost.
4 Q.So the answer was "yes" then?
5 A.Yes.
6 MR. WOODBURY: Madam Chair, Staff has no further
7 questions.
8 COMMISSIONER SMITH: Mr. Budge.
9 MR. BUDGE: No questions.
10 COMMISSIONER SMITH: Mr. Solander.
11 MR. SOLANDER: Thank you. Just a few.
12
13 CROSS-EXAMINATION
14
15 BY MR. SOLANDER:
16 Q.Would you agree that the Company historically
17 allocated generation and distribution-related demand costs
18 using the 12 CP method?
19 A.Are we talking actually, I've been testifying
20 in PacifiCorp cases since prior to the merger, so if you go
21 back to PP&L in the 1980s, of course there they were using the
22 three highest winter peaks.
23 Q.Would you agree that, currently, the Company uses
24 the 12 CP method in five of the six states, with the exception.25 of Washington?
1706
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (X)
PIIC
.
.
.
1 A.Yes, the 12 CP method, at least with respect to
2 distribution costs, is different in the states of California
3 and Oregon as it is in the state of Idaho where, not to leave a
4 misconception from Mr. Paice' s testimony, they start off with a
5 12 CP in all jurisdictions -- Idaho, Washington, and
6 California -- but they do not weight the 12 CPs by the
7 substation peaks in either California or Oregon, as he has done
8 in the case here in Idaho.
9 Q.I'm sorry, could you repeat the last sentence?
10 A.He does not weight the 12 CP distribution peaks
11 by the substation peaks as he has in Idaho in the jurisdictions
12 of Oregon and California.
13 Q.In your testimony, is it true that you recommend
14 that the Commission allocate distribution demand-related costs
15 for primary lines and substations using the class single
16 noncoincident peak method?
17 A.That's correct. And let me explain why:
18 This utility in the state of Idaho has over 1,100
19 MVA of distribution transformer capacity. Their allocation
20 factor using the 12 CP method, as I point out -- I believe it
21 is on page 15 of my testimony -- allocates the cost of the
22 1,100 MVA of distribution substation transformer capacity by
23 only 390 megawatts.
24 My approach, which I believe captures a more
25 accurate load di versi ty factor, allocates the cost over 633
1707
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (X)
PIIC
.
.
.
1 megawatts, these facilities and distribution peaks, individual
2 distribution peaks, totaling 628 megawatts. So I believe my
3 distribution allocation factor is much more of a cost causation
4 method than the 12 CP method used by the Company.
5 Q.Does that mean that you disagree with Mr. Paice' s
6 assertion that individual customers' distribution peak demands
7 generally occur at different times?
8 A.I think -- well, you have to be very careful.
9 We're talking about the distribution peaks, the distribution
10 coincident peaks, and those are by class, not individual
11 customer.
12 In actuality, if you would look at the residence
13 class, that peaks in January; the irrigation class, according
14 to their 2009 load research data coupled with the forecasted
15 2010 energy, peaks in June. So the various maj or classes do
16 peak at different times.
17 Q.And isn't that the foundation of the concept of
18 load di versi ty?
19 A.It is load di versi ty, but, again, I think I'd
20 agree with Mr. Paice that the most accurate substation
21 allocation factor would be if you had the class specific loads
22 at each distribution substation.
23 Q.But wouldn't you agree
24 A.Since that data is not available, then the most
25 accurate would be, in my view, the class's noncoincident peak.
1708
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (X)
PIIC
.
.
1 That's what's being missed in the distribution factor that is
2 deri ved from the weighting the substation peaks is it greatly
3 understates the residential contribution to the residential
4 substations, thereby forcing too much cost responsibility to
5 the irrigation class and the large power users.
6 Q.But wouldn't you agree that there generally is
7 load di versi ty present at the substation and primary line
8 level, as described in the NARUC manual on page 97?
9 A.Yes, that is -- I'm glad you brought up page 97.
10 That does talk in terms of load diversity. And, of course,
11 Mr. Paice left out the last two sentences in his rebuttal
12 testimony, and the last sentence does state that, indeed, the
13 most typically used method is the single NCP method for
14 allocating distribution substation in primary wire costs.
15 Q.I'm sorry, I didn't hear that.
16 A.In primary wire costs.
17 Q.Doesn't the NARUC manual, in fact, recommend
18 using customer class peaks when allocating the cost association
19 to primary feeders?
20 A.No, it does not. I have page 97 if you would
21 like me to read it into the record.
22
23
Q.Please do.
COMMISSIONER SMITH: Could we please have a more
24 explicit description of the NARUC manual that's referred to?.25 THE WITNESS: Certainly. I'm referring to the
1709
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (X)
PIIC
.
.
.
1 Electric Utility Cost Allocation Manual that was published in
2 January 1992, and on page 97 -- actually, starting prior to
3 that -- it talks in terms of how distribution costs should be
4 allocated.
5 In Mr. Paice' s testimony, he stops with the
6 sentence: The load di versi ty at distribution substations and
7 primary feeders is usually high. For this reason, customer
8 class peaks are normally used for the allocation of these
9 facilities.
10 The sentences he has left out read: The
11 facili ties near the customer, such as secondary feeders and
12 line transformers, have much lower load di versi ty. They are
13 normally allocated according to the individual customers'
14 maximum demands. All those these are the methods normally
15 although these are the methods normally used for the allocation
16 of distribution demand costs, some exceptions exist.
17 Q.BY MR. SOLANDER: That's all I wanted to hear.
18 Thank you.
19 MR. SOLANDER: I have no further questions.
20 COMMISSIONER SMITH: Do members of the Commission
21 have questions?
22 COMMISSIONER KEMPTON: No questions.
23 COMMISSIONER REDFORD: No.
24 COMMISSIONER SMITH: Nor I.
25 Ms. Davison, do you have some redirect?
1710
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
SCHOENBECK (X)
PIIC
.
.
.
1 MS. DAVISON: Madam Chair, I do not.
2 COMMISSIONER SMITH: I want to thank you for your
3 help.
4 THE WITNESS: Thank you.
5 MS. DAVISON: We call our last witness: Randy
6 Fal kenberg .
7 COMMISSIONER SMITH: And Mr. Schoenbeck can be
8 excused if there's no obj ection.
9 MS. DAVISON: Thank you, Madam Chair. I'm sorry.
10 COMMISSIONER SMITH: You're welcome.
11 (The witness left the stand.)
12
13 RANDALL FALKENBERG,
14 produced as a witness at the instance of PacifiCorp Idaho
15 Industrial Customers, being first duly sworn, was examined and
16 testified as follows:
17
18 DIRECT EXAMINATION
19
20 BY MS. DAVISON:
21 Q.Good afternoon, Mr. Falkenberg. Could you please
22 state your full name and spell your last name for the record?
23
24
25
A.Randall James Falkenberg: F-A-L-K-E-N-B-E-R-G.
Q.And, Mr. Falkenberg, by whom are you employed?
A.RFI Consulting, Incorporated.
1711
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FALKENBERG (Di )
PIIC
.
.
1 Q.And are you the same Mr. Falkenberg who submitted
2 direct testimony in this case on October 15, 2010, and try
3 to get the date -- and then also surrebuttal testimony on
4 December 1, 2010, on behalf of the PacifiCorp Idaho Industrial
5 Customers?
6 A.Yes.
7 Q.And, Mr. Falkenberg, do you have any changes or
8 corrections to your testimony?
9 A.I do not.
10 Q.If I were to ask you these questions today, would
11 your answers be the same?
12 A.Yes.
13 MS. DAVISON: Madam Chair, I would move the
14 testimony -- the direct and surrebuttal testimony -- of
15 Mr. Falkenberg into the record, as well as identification of
16 Exhibit 605, 606, 607, 608, and 609, and be spread on the
17 record as if read.
18 COMMISSIONER SMITH: If there's no obj ection, we
19 will spread the testimony of both the direct and surrebuttal on
20 the record as if read, noting that on some pages some
21 confidential information has been redacted so the public
22 portion of the transcript will not include the material that on
23 my pages is shaded.
24 (The following prefiled direct and.25 surrebuttal testimony of Mr. Falkenberg is spread upon the
1712
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FALKENBERG (Di)
PIIC
.1 record. )
2
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
1713
HEDRICK COURT REPORTING FALKENBERG (Di)
P. O. BOX 578, BOISE,ID 83701 PIIC
.
.
.
1 Q.
2 A.
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
Randall J. Falkenberg, PMB 362, 8343 Roswell Road, Sandy Springs, GA
3 30350.
4 Q.
5 A.
BY WHOM ARE YOU EMPLOYED?
I am President of RFI Consulting, Inc. ("RFI"). I am appearng in this
6 proceeding as a witness for the PacifiCorp Idaho Industrial Customers
7 ("PILC"). My qualifications are in Exhbit No. 605. I have been involved in
8 PacifiCorp (or "the Company") power cost related cases for more than ten
9 years in Californa, Oregon, Utah, Washington and Wyoming.
10 Q.
11
12 A.
13
WHAT KIND OF CONSULTING SERVICES ARE PROVIDED BY
RFI?
RFI provides consulting services in the electric utilty industr. The firm
provides expertise in system planing, financial analysis, cost of service,
14 revenue requirements, rate design, and energy cost recovery issues.
is
16 Q.
17 A.
18
19
20
21
22
23
I.INTRODUCTION AND SUMMARY
WHAT IS THE PURPOSE OF THIS TESTIMONY?
My testimony addresses PacifiCorp's GRID study of normalized net power
costs ("NPC") for the December 31, 2010 test period. I identify certain
problems in the GRID model that overstate PacifiCorp's proposed Idaho
.
revenue requirements. I also address a related issue concerning combined
cycle plant Operations & Maintenance ("O&M"). Because Idaho uses a tre-
up mechanism for PacifiCorp, I am not presenting a complete analysis ofNPC
modeling issues. Instead, I am concentrating more effort on issues that also
1
1 7 JFlkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1
2
3
4
S Q.
6 A.
7
8
9
10
11
12
13
14
15
16
17
18
19
have an implication for the Energy Cost Adjustment Mechanism true-up, or
revenue requirements not subject to the tre-up. I am discussing some
important modeling issues as it is important to set the NPC baseline as
accurately as possible.
PLEASE SUMMARZE YOUR TESTIMONY.
I have identified and quantified certin adjustments to the Company's GRI
model study. These adjustments are shown on Table 1 and are sumarized
below. All adjustments are addressed in more detail later in this testimony.
Following Table 1 is a sumary explaining the basis for all proposed
adjustments and other recommendations.
Conclusions and Recommendations
PacifiCorp's requested 2010 NPC of $1,070 milion (total Company) in
NPC is overstated by at least $25 milion. My corrections result in a
reduction to Idaho jurisdictional NPC of $1.51 milion. I also recommend
additional reductions of $29 thousand to the Idaho allocation revenue
requirements related to reductions to combined cycle plant O&M. As I
explained earlier, I have not done a complete analysis of the Company's
NPC in this case, and additional reductions to the Company's NPCs may
well be warranted.
2
1 7 Falkenberg, Di
PacifiCorp Idaho Industrial Customers
.Table 1
Summary of Recommended Adjustents
SE
SG
Es 10
Jurisdicton
6.36%
5.51%
Total
Company
I. GRID (Net Variable Power Cost Isses)
PacifiCorp Request NPC
A. GRID Commitment Logic Error and Start Up Cost
1 Commitment Logic Screens1/
2 Start Up Energy 21
B. Long Term Contract Modling
3 SMUD Contrct Delivery Pattrn
C. OATT Wind Integration Cost
4 Non-owned Inter Hour Wind
5 Non-owned Intra Hour Wind
D. Outage Modeling and Other NPC Adjustents
6 Lake Side Outage
7 Colstip Outage
8 JBFuel Adjustents
9 Naughton Outage
10 Heat Rate Adjustment
E. Transmisson Isses
11 DC Interte Cost
12 Populus to Ben Lomond Line Losss
13 Idaho Power PTP Contract
Notes
1/ Adjustment Incresed if Adjustment 14 Is not approved. In that case Adj. 1:
21 Adjustment assumes Co. SCreens. Adjustment if ICNU screens adopted:
1,069,701,315 69,200,000
(588,429)(34,912)
(1,676,474)(99,465)
(1,566,786)(92,957)
(2,041,963)(121,150)
(4,320,031)(256,307)
(2,163,834)(128,380)
(1,300,710)(77,171)
(2,460,037)(145,954)
(700,273)(41,547)
(1,831,473)(108,661)
(4,766,400)(282,791)
(1,146,067)(67,996)
(842,386)(49,979)
(25,404,863)(1,507,271)
1,04,296,452 67,692,729
(490,000)(29,072)
(25,894,863)(1,536,342)
(1,259,760)(74,742)
(1,393,200)(82,659)
.Subtotal NPC Baseline Adjustments.
Allowed. Final GRID Result*
G. Other Adjustments
14 Combined Cycle O&M Adjustent
Total Adjustents
1 A.
2
3
4
S
6
7
8
9
10
11.
GRID Commitment Logic Error and Start Up Costs
Adjustment 1. The Company acknowledges that GRID
contains a logic error that results in incorrect start up and
shut down decisions for gas-fired resources. This error
produces an upward bias on NPC. The Company attempts
to correct this error with a "screening" methodology.
However, the Company's correction is ineffective. I
ilustrate a more effective solution to this problem as
applied to the Currant Creek unit.
Adjustment 2. The Company includes the cost of fuel used
to start up gas plants, but ignores energ generated in the
3
1 7 JKlkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
is
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
process. I recommend reflecting the value of start-up
energy in the test year.
B.Long Term Contract Modeling
Adjustment 3. The Company incorrectly models the
Sacramento Municipal Utilty District ("SMUD") sales
contract by assuming the counterpart wil take power only
during the highest cost months. Actual contract delivery
data shows the contract should be modeled to reflect a
lower cost delivery pattern.
C.OATT Wind Integration Adjustments
Adjustments 4-5. The Company includes various costs
related to integration of non-owned wind resources. These
costs should be excluded because the Company is not
compensated for providing these integration services. The
Company has already acknowledged that it does not need
to provide inter-hour wind integration services for non-
owned wind farms. The Commission should also make
comparable adjustments in true-up proceedings.
D.Outage Rate Adjustments
Adjustments 6-7. These adjustments cap exceptionally long
outages at Lake Side and Colstrip 4 at 28 days in the four-
year average outage rate calculation. It is unrealistic to
assume such an extreme event wil occur once every four
years.
Adjustment 8. This adjustment addresses the high cost and
low quality of the Bridger fuel supply. Fuel quality
problems result in inordinately high levels of lost
production as compared to other plants.
Adjustment 9. The Company includes an outage at the
Naughton plant that was due to the negligence of a
subcontractor. The costs of such events should be assigned
to the Company rather than customers.
Adjustment 10. GRID biases average heat rates due to its
modeling of forced outage rates as capacity derations.
When GRID models a unit at its derated maximum
4
1 7 JTlkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1
2
3 E.
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
31
32
capacity, the heat rate normally exceeds the full loading
average heat rate. This adjustment corrects this problem.
Transmission Issues
Adjustment 11. It appears the Company includes no
transactions that utilize the DC Intertie in the test year. I
recommend removal of intertie costs to match costs and
benefits in the test year. I further recommend the
Company be required to demonstrate the prudence of its
management of this contract.
Adjustment 12. I don't take any position on including the
Populus to Ben Lomond transmission line in the test year.
However, if included, I recommend an adjustment to reflect
reductions in losses the line wil produce.
Adjustment 13. The Company includes an expiring
transmission contract that wil no longer be needed after
completion of the Populus to Ben Lomond line. If the new
line is included in the test year, transmission wheeling
expense should be reduced to remove the cost of this
contract.
F.Non Fuel Start up O&M
Adjustment 14. My proposed screening adjustment
reduces the number of starts of combined cycle plants in
the test year, overstating O&M costs. If this adjustment is
not adopted, a higher value for Adjustment 1 should be
used as is shown in Table 1.
G.Filng Requirements
I recommend the Company be required to file specific
GRID workpapers in future cases. The Company has
agreed to these requirements in other states. It should not
be diffcult for the Company to comply with this
requirement.
5
1 7 Jìilkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 GRID COMMITMENT LOGIC ERROR
2 Adjustment 1: Commitment Logic Screens
3 Q.
4
5 A.
PLEASE PROVIDE SOME BACKGROUND CONCERNING TIDS
ISSUE.
GRID has a logic error that results in improper unit commitment and dispatch
6 decisions for gas units and call options. The Company acknowledges the
7 problem exists in GRID. This problem has existed since the model was
8 developed, and has been acknowledged by the Company in numerous recent
9 cases in the varous states.
10 Absent user-supplied workarounds, GRID frequently fails to develop
11 the least cost sequence of star-ups and shut-downs of gas-fired resources.
12 Left alone, there are many hours when gas-fired generators fail to operate
13
14
is
16
17
18
19
20
21
22
economically within the modeL. Ths has a spilover effect on coal-fired
generation because the uneconomic operation of gas plants forces lower cost
coal unts to have their output curled.
The problem occurs because the logic in GRID separates the decision
to commit (star up or to not shut down) a resource from the operating
constraints (transmission and market capacity limits) imposed by other model
inputs. However, these operating constraints are used later to determine the
optimal dispatch of resources. The model unealistically assumes there is
always a market for energy when makng the commitment (sta up or shut
down) decision, but once the units are ruing GRID assumes there is no
6
1 7 ~lkenberg, Di
PacifiCorp Idao Industral Customers
.
.
.
1 market for the energy these resources could otherwse sell due to the
2 previously ignored constraints.
3 Q.
4 A.
EXPLAIN YOUR INVOLVMENT IN THIS ISSUE.
I have addressed this issue in testimony in several states. I first brought it to
S the Company's attention in Wyoming Public Service Commission docket No.
6 20000-277-ER-07 in Janua 2008. Since that time both the Company and I
7 have addressed various solutions in cases in Oregon, Washington, Wyoming
8 and Uta. The Utah Public Service Commission ("Utah Commission")
9 adopted my proposed adjustments related to this issue in Docket Nos. 07-035-
10 89l/ and 09-035-23.Y All of the other cases where this matter was at issue
11 resulted in settlements that did not adopt any specific adjustment related to
12 this problem.
13 Q.
14
HAS THE COMPANY ATTEMPTED TO ADDRESS THIS PROBLEM
IN ITS FILING?
is A.Yes. Dr. Shu has included a daily "screening adjustment," which is intended
16 to correct this problem. In the response to Monsanto Data Request ("DR")
17 2.8, the Company provided the workpapers used to develop the screens.
18 Essentially, this methodology forces a specific daily schedule or screen for gas
19 plants if it can reduce NPC relative to the GRID model's internal logic.
20 Otherwse, the Company allows GRID to develop its own schedule, using the
l/Re Rocky Mountain Power 2007 General Rate Case, Uta Commission Docket No. 07-035-
93, Report and Order on Revenue Requirements at 30 (August 11,2008).
Re Rocky Mountain Power 2009 General Rate Case, Utah Commission Docket No. 09-035-
23, Report and Order on Revenue Requirements, Cost of Service and Spread of Rates at 29
(Feb. 18,2010).
Y
7
1 7 ltlkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1
2
3
4 Q.
S
6 A.
7
8
9
10 Q.
11 A.
12
13
14
15
16
17
18
19
20
flawed logic. The Company's method is an improvement over its prior
efforts. However, it can and should be improved upon to eliminate as much of
the error induced cost as possible.
is THE COMPANY'S NEW SOLUTION ONE THAT YOU HAVE
PREVIOUSLY PROPOSED?
No. The Company's proposal was developed in response to my previous
proposal to use daily screens; however, the Company's approach differs from
my recommended solutions and from the solutions previously accepted by
regulators.
HOW CAN THE COMPANY'S SCREENS BE IMPROVED?
Two basic improvements are required. The Company should tum off the
GRID commitment logic entirely. It has become apparent that the internal
logic is more flawed than previously thought. In the past, it was assumed that
the only problem in GRID was that it sometimes allowed plants to ru when
they should have been shut down. However, it is now apparent that at times,
the logic may actually shut down plants when they should be allowed to ru.
Consequently, relying on the internal logic as the staring point fails to
identify the optimal solution. However, solving ths problem requires only
that the cycling unts be modeled on a must ru basis in the preliminar ru
used to develop the screens.
8
1 7 ~lkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 Q.
2
3 A.
WHAT OTHER PROBLEMS EXIST IN THE COMPANY'S DAILY
SCREENS?
The Company method examines only a limited number of possible daily
4 screens or schedules. For example, the Company examines 18 possible
5 screens for Curant Creek. Ths limits the number of sta-up/shut down
6 choices. For example, a 10 PM shutdown of6, 7, or 8 hours is considered, but
7 not a longer and more accurate shutdown period. Consequently, one problem
8 is the inflexibilty of the Company approach and its failure to examine more
9 optimal schedules.
10 Q.ARE THERE OTHER PROBLEMS IN THE COMPANY'S ANALYSIS?
11 A.Yes. Another problem with the Company's methodology is that it may be
12 using an erroneous assumption regarding star up O&M costs. The Company
13 assumes that staing up of a combined cycle plant requires a specific amount
14 of fuel be bured and that other, incremental non-fuel O&M expenses will be
15 incured as well. In principle, I agree on both counts. However, the Company
16 fails to recognize the energy produced durng the star up sequence in its test
17 year, and it appears that the Company may not be accounting for the
18 incremental effect of these non-fuel O&M expenses in the preparation of its
19 test year. If so, then both problems need to be addressed.
20 Q.
21 A.
DESCRIBE THE METHODOLOGY YOU PROPOSE.
The proposed methodology is similar, but more flexible. First, the GRID
22 internal logic is tued off by invoking the must ru status for each cycling
23 unit screened. Consequently, when the screening method is applied, it
9
1 7 :Flkenberg, Di
PacifiCorp Idaho Industrial Customers
.1 determines each hour of the year when cycling units should be rung or not.
2 The Company recently agreed to make this change along with other
3 improvements to its screening method in OPUC Docket No. DE 216.JI Rather
4 than limiting the analysis to 18 screens per day, it examines 168 daily screens,
5 and considers the possibilty of a star-up or shut down every hour ofthe day.~
6 The method also will allow a single screen to ru for days or even weeks in
7 succession if that is the optimal choice.
8 Q.EXPLAIN THE ADJUSTMENTS YOU COMPUTED IN TABLE 1.
9 A.In Table 1, I estimate the effect of implementing more optimal screens for the
10 Curant Creek plant. Because my screens result in a much smaller number of
11 star-ups than the Company screens, there is also change in the amount of.12 incremental star-up fuel and fixed (non-varable NPC) O&M expenses
13 included in the test year.I have identified the star up O&M component of
14 cost on Table 1, as Adjustment 14, while the fuel and purchased power cost
15 impacts are included in Adjustments 1 and 2.
16 Q.HAS THE COMPANY APPLIED ITS SCREENING METHOD TO ALL
17 RESOURCES SUBJECT TO THE LOGIC ERROR?
18 A.No. The Company did not apply its correction to the duct firing capabilty of
19 Curant Creek or Lake Side, nor to call options. In the case of Lake Side this
20 is a substatial problem, as the capabilty is invoked many hours (1048) when
21 it is uneconomic to ru. Considering the resource is only economic to ru for
"J Re PacifiCorp's 2011 Transition Adjustment Mechanism, OPUC Docket No. UE 216,
Stipulation at 3-4 (July 7, 2010).
It is not diffcult to expand the number of screens fuher and I would not object to doing so.~.10
1 7 2flkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1 1683 hours, this means GRI produces an incorrect dispatch 38% of the time.
2 In fact, there are four entire months when it would be less costly if the GRID
3 model never used the Lake Side duct firing. I have also corrected this
4 problem in Table 1. The Commission should require the Company to address
S this problem as well.
6 Q.
7
8 A.
WHY DON'T YOU DEVELOP SCREENS FOR ALL OF THE
P ACIFICORP GAS-FIRED PLANTS?
The final screens will depend on the adjustments adopted by the Commission
9 and any other updates or corrections. My purose in this case is to explain
10 and ilustrate the correct way to develop the screens, and recommend the
1 1 Commission require this approach in its final order. I recommend the
12 Commission require the Company to implement my proposed screening
13 method after the Company models all Commission approved adjustments as a
14 "final" GRID ru for ths case.
15 Adjustment 2: Start Up Energy
16 Q.
17
18
19 A.
20
21
22
23
DR. SHU TESTIFIES ON PAGE 8 THAT SHE INCLUDED START UP
GAS COSTS IN GRID. DO YOU AGREE WITH INCLUSION OF
START-UP GAS COSTS IN NPC?
Yes, these are legitimate net power costs. However, the Company only
considers the cost of fuel required to tae the unt from a war shut-down
state to minimum load but ignores the energy produced during ths process.
During the period the units are ramping up (about 2 hours), the power output
of these units is gradually increasing.
11
1 7 2ßalkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1 Q.
2
3 A.
4
S
6
7
8 Q.
9 A.
10
11
12
13
14
is
16
17
18
19
20
HAS THE COMPANY OPPOSED THIS ADJUSTMENT IN OTHER
STATES?
Yes. The Company has argued various points including: 1) Within an hour
there is no market for the energy; and 2) Sta-up energy imposes additional
reserve requirements on the system.~ Based on these kinds of qualitative
arguents, the Company argues no value should be ascribed to start-up
energy.
DO YOU AGREE WITH THESE CRITICISMS?
No. Were the Company to apply the same arguments to wind energy, it would
suggest that wind energy has zero value, or worse - that integration costs
actually exceed the dispatch benefits of wind resources. All of these concerns
apply more directly to wind energy than to star-up energy. For example,
sta-up energy is far more predictable on a day ahead, hour ahead, and intra-
hour basis than is wind energy. Whle dispatchers do not know if wind will
blow the next day or the next hour, suddenly quit, or ramp up unexpectedly,
this is not the case for combined cycle plant star-up energy. Gas plant
schedules are a plan made a day in advance, while a "wind schedule" is
merely a weather forecast. One can predict combined cycle star energy far
more reliably than wind power. The arguents concerning the lack of an
intra-hour market apply to wind energy even more-so than sta-up energy.
l!See Utah Commission Docket No. 09-035-23, Rebuttl Testimony of Gregory N. Duvall at
15-16 (Nov. 14,2009). Mr. Duvall also made an argument concerning minimum down times
which I have addressed in my analysis in this case.
12
1 7 :Flkenberg, Di
PacifiCorp Idaho Industral Customers
.1 Q.DID YOU ALSO CONSIDER THE CONCERNS REGARING THE
2 NEED TO INCREASE RESERVES TO COVER THE RAP UP OF
3 THE COMBINED CYCLE PLANTS IN YOUR ANALYSIS?
4 A.Yes. The approach I have taken is to conservatively assume that start up
S energy results in a back-down of coal generation which is then used for load
6 following and providing reserves. This provides a floor on the value of sta-
7 up energy, which should be reflected in the test year.
8 Q.HAVE OTHER EXPERTS SUPPORTED THIS TYPE OF POWER
9 COST ADJUSTMENT?
10 A.Yes. In the 2009 Utah General Rate Case (Utah Commission Docket No. 09-
11 03S-23), the Utah Division of Public Utilties power cost expert, Mr. George
12 Evans, proposed a similar adjustment. Mr. Evans also testified in response to
13 one of the Commissioner's questions that modeling of sta-up energy was the.14 industry standard approach. §l Mr. Evans has testified in numerous cases
15 throughout the US and has approximately 30 years expenence in power cost
16 modeling.
17 Adjustment 14: Start Up O&M
18 Q.EXPLAIN WHAT IS MEANT BY START UP O&M.
19 A.The Company assumes that staring up a gas combined cycle plant wil result
20 in incremental non-fuel O&M expenses. The logic used in its screening
21 method considers this cost before allowing these units to restar afer a
22 shutdown. I agree with this, in principle, and have included the same kinds of
§j Re 2009 Utah General Rate Case, Utah Commission Docket No. 09-035-23, Transcript at 549
(Dec. 14, 2009)..13
1 7 :Flkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1
2
3
4
S
6
7
8
9
10
11
12
13 Q.
14
15
16 A.
17
18
19
20
21
22
23
costs in my screening method. Because my proposed screens are more
effcient, they result in 9S fewer sta ups for Curant Creek than the Company
screens allow. This implies lower non-fuel O&M costs should result for the
unt. The Company's screening method actually increases the number of
stars relative to the case with no screens, suggesting an increase to non-fuel
O&M would is waranted if one accepts Dr. Shu's screens. Consequently,
Adjustment 14 provides my calculation of the benefits of the reduced non-fuel
O&M expense for the Curant Creek plant. When coupled with the
Company's generation overhaul cost for Curent Creek (see McDougal
Exhibit No.2 at 4.10.1), it would lower the Curant Creek overhaul costs to a
level closer to that of Lake Side and Chehalis for the test year. Consequently,
I recornmend this adjustment to the test year as well.
DOES THE COMPANY ACTUALLY INCLUDE ANY ADJUSTMENT
TO THE TEST YEAR TO ACCOUNT FOR THE CHANGE IN START
UP O&M DUE TO ITS SCREENS?
It appears they may not be doing so. I don't see any adjustment to account for
the star up O&M in either the Net Power Cost adjustments or the Generation
Overhaul expense adjustments. If so, then it may not be appropriate to make
the reduction to non-fuel O&M recommended in Adjustment 14. However, if
that's the case, then the assumption the Company uses in setting its screens
(which includes a non-fuel sta up O&M cost of per start) is
most certainly wrong, and should be eliminated. Either the cost is real (and
should be included in the test year) or its not (and should not be used in
14
1 7 ~lkenberg, Di
PacifiCorp Idaho Industral Customers
.1
2
3
4
5
6
7
8
9 Q.
10 A.
11
12
13 Q.
14 A.
is
16
17
18
19 Q.
20 A.
21
22
23
.
.
computing the screens). Only one of these choices can be correct. If it's the
former, the Adjustment 14 is appropriate. If it's the later, then a different
screen is optimal and the reduction to NPC in Adjustment 1 would be
substantially greater as shown on the footnote to Table 1. This is because the
lower star up costs result in more economic stars, and a bigger impact from
the use of a proper screen as compared to the Company rus. In either case
the test year revenue requirements are lower than proposed by the Company.
B. LONG TERM CONTRACT ADJUSTMENTS
DOES GRID MODEL PURCHASE AND SALES CONTRACTS?
Yes. GRI includes the costs and energy produced by its long-term and
short-term contracts, along with its thermal generation resources.
Adjustment 3: SMUD Contract Delivery Pattern
WHAT is A CALL OPTION CONTRACT?
This is a contract that allows the purchaser the right to pre';schedule energy
deliveries based on expected market prices and/or the purchaser's
requirements. The Company is both a buyer and seller of call option
contracts. The Company models a "call option sale" contract for the SMUD
in the GRID modeL.
EXPLAIN THE MODELING OF CALL OPTION SALES IN GRID.
In GRID, inputs specify contractul energy limits on an hourly, daily, weekly,
monthly or anual basis. For sales with anual contract energy limits, such as
the SMUD contract, GRID schedules the contract energy during the highest
cost hours of the year. Because the contract has an anual energy limit of
15
1 7¡?jlkenberg, Di
PacifiCorp Idaho Industrial Customers
.1 approximately 3S0,400 MWh (with a 100 MW maximum hourly tae), the
2 Company assumes SMUD will call the energy from the contract during the
3 highest costl 3S04 hours~ in the year.For SMUD, GRID assumes the
4 counterpary finds the most costly way possible to use the energy available
S under the contract.In effect, the Company's modeling assumes the "worst
6 case" scenaro.
7 Q.is THIS REALISTIC?
8 A.No. In fact, it simply does not happen in actual operation.Figure 1, below,
9 compares the actu monthly delivery patterns of the SMUD contract to the
10 GRID assumptions.Generally, SMUD use this resource in a maner that is
11 far less costly than assumed by the Company. Whle the Company assumes.12 SMUD will never take power durng low cost months such as April through
13 June, in reality SMUD takes substantial deliveries durng those months.
7J
'§
Based on COB market prices.
350,400/100= 3504..16
1 7 l'~lkenberg, Di
PacifiCorp Idaho Industral Customers
.
1
2.3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14.
Figure 1: SM UD Monthly Sales Jan 2006-Dec 2009
60,000
50,000
40,000'"
~30,000 -Actual:i
3:
:E -GRID
20,000
10,000
1 2 3 4 5 6 7 8 9 10 11 12
There are many reasons why this is be the case. First, SMUD is not
using the same forward price cures as the Company. It is safe to assume that
SMUD has no specific knowledge of the Company's forward price cures or
vice-versa. Differences in delivery location, transmission constraints,
availabilty of the SMUD's own generation and many other factors will drve
decisions to use the available energy. In the end, SMUD is interested in
serving its own customers at the least possible cost (subject to its own
constraints), not in maximizing the cost to PacifiCorp. The Company's
approach does not represent "normalization" of the contract, but rather the
very worst possible outcome for the Company.
DOES THE COMPANY USE HISTORICAL DATA IN THE
MODELING OF OTHER CONTRACTS?
Yes. The Company uses historical data to compute various inputs for the
various contracts including APS, Black Hils Power, GP Camas, small
17
1 7 nlkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1
2
3
4
5 Q.
6
7
8 A.
9
10
11
12
13
14
15
16
17
18
19
'l
lQ/
purchase contracts, and reserve requirement inputs for non-owned generation
located in its service area. Furher the market caps used in GRID are based on
historical data as well. Use of historical data is common in the Company's
modeling of contracts.
IN UTAH COMMISSION DOCKET NO. 07-035-93, YOU PROPOSED
THE SAME NORMALIZATION ADJUSTMENT FOR THE SMUD
CONTRACT. WHAT WAS THE OUTCOME OF THAT CASE?
The Uta Commission accepted the adjustment.2! The Uta Commission also
declined to act on the Company's request for reconsideration regarding the
matter. Finally, in Docket 09-03S-23, the Uta Commission reaffirmed its
support of this adjustment. 101 As in the case of the screens, this issue has not
been resolved in other states. Despite all this, the Company stil disagrees
with the adjustment and does not apply it in any other state. The Company
has made a number of different arguents regarding ths issue. In other
testimony, the Company suggested that if it were correct to not use the actual
data in determining the dispatch of call option sales contracts, one should
assume the Company would not make the least cost decisions concernng its
own purchase agreements such as the Hermiston purchase or the Bonnevile
Power Administration ("BP A") contract.
Re Rocky Mountain Power 2007 General Rate Case, Utah Commission Docket No. 07-035-
93, Report and Order on Revenue Requirements at 23 (August 11,2008).
Re Rocky Mountain Power 2009 General Rate Case, Utah Commission Docket No. 09-035-
23, Report and Order on Revenue Requirements, Cost of Service and Spread of Rates at 36
(Feb. 18,2010).
18
1 7l'lllkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1 Q.
2 A.
3
4
S
6
7
8
9
10
11
12
13
14
15
16
17
18
19
DO YOU AGREE WITH THESE ARGUMENTS?
No. Based on such reasoning, one would not depar from the "highest cost"
modeling of SMUD unless one abandoned the least cost modeling of
Hermiston, BP A or other resources. Such arguents miss the fudamenta
point of this analysis and of power cost modeling in general. The Company
decides when to use, or not use the BP A and Hermiston purchases and does so
to minimize costs, subject to the constraints the Company is facing. In the
case of SMUD, the Company simply does not know and has not modeled any
of the loads, constraints or forward prices cures used by SMUD. Were the
Company able to do so, it might make sense to model them in GRID without
any adjustments derived from historical data. In effect, GRID is "flying
blind" when it comes to the counterparies and has no reasonable basis for
assuming the counterparies can even use the power available at all the highest
cost hours. History shows they simply do not do so. In the end, the
adjustments 1 make to the SMUD delivery pattern are simply a proxy for the
constraints and other assumptions related to the SMUD contract that are
unown and probably unowable to PacifiCorp. I recommend that
Commission adopt Adjustment 3, to implement a more realistic shape for the
SMUD contract.
19
1 7 :ilkenberg, Di
PacifiCorp Idao Industrial Customers
.
.
.
1
2 Q.
3
4
S A.
C. NON -OWNED ("OATT") WIND INTEGRATION COSTS
DOES THE COMPANY INCLUDE WID INTEGRATION COSTS
FOR ANY NON-OWNED WIND FARMS LOCATED IN ITS SERVICE
AREA?
Yes. The projects are generally transmission customers taing service under
6 the terms and conditions of the Company's Open Access Transmission Tarff
7 ("OATT").
8 Q.
9
10 A.
DOES PACIFICORP'S OATT INCLUDE ANY CHARGES FOR WIND
INTEGRATION SERVICES?
No. Whle the OATT does provide for charges for reserves for transmission
11 customers, it does not provide any charges for wind integration service. As a
12 result, the Company is providing integration services to these customers
13 without compensation. Unfortunately, retail customers will be required to
14 subsidize wholesale transmission service, if this is allowed by the.
15 Commission.
16 Q.
17
18 A.
19
20
21
22
23
DO OTHER TRASMISSION PROVIDERS INCLUDE WIND
INTEGRATION CHARGES IN THEIR OATT?
Yes. BPA includes such charges in its OATT, and PacifiCorp pays BPA for
wind integration services. The Company has included these charges in its
GRID test year for some time. There is no reason why the Company should
not seek approval to include such charges in its OATT. Until such approval is
granted, the Company should not be allowed to charge retail customers for
providing services to its wholesale transmission customers.
20
1 7 :Flkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 Q.
2
3
4
5 A.
is THERE ANY REASON WH THE COMPANY COULD NOT
HAVE ALREADY MADE A FILING AT THE FERC SO THAT IT
COULD HAVE INCLUDED WIND INTEGRATION CHARGES IN ITS
OATT, OR IMPLEMENT SOME OTHER MECHANISM?
No. The Company has expected since at least the time of its 2004 IRP that it
6 would experience substantial costs for wind integration. Its 2004 IRP
7 supported a value of $4.64/MWH.W By Januar 1,2011, the Company wil
8 have had more than six years to have made the appropriate filings with the
9 FERC to recover wind integration costs from transmission customers. Furher,
10 the Company has conducted numerous meetings relative to its jurisdictional
1 1 allocation procedures for the past decade. There is no reason why the
12 Company should not have engaged the FERC in ths process to address an
13 equitable solution to the OATT wind integration issue. The Company's lack
14 of dilgence is no excuse to charge retail customers such costs.
15 Adjustment 4: Non-Owned Wind Farm Inter-Hour Integration Costs
16 Q.PLEASE EXPLAIN THE BASIS FOR THIS ADJUSTMENT.
17 A.The Company models a charge of $6.50/MWH for wind integration costs in
18 GRID. This includes both intra and inter-hour integration costs for non-
19 owned wind farms for which it provides transmission services. The Company
20 did not differentiate between these two kinds of costs in this case, but has
21 done so in its IRP studies.
22 Adjustment 4 removes the cost of inter-hour wind integration from
23 GRD for non-owned generators. This is much the same as the case of the
ll Re PacifiCorp Large QF Avoided Cost Case, Utah Commission Docket No. 03-035-14,
Report and Order at 23 (Oct. 31, 2005).
21
1 7 :Flkenberg, Di
PacifiCorp Idaho Industrial Customers
.1
2
3
4
S
6
7
8
9
10
11
12 Q.
13 A.
14
15
16
17 Q.
18
19 A.
20
21
22
w
.
.
Goodnoe and Leaning Juniper projects which are located on the BP A
transmission system. The Company assumes it must provide its own inter-
hour integration for these wind fars, and that BP A will not do so. Likewise,
it stads to reason that non-owned projects located on the PacifiCorp
transmission system should not require or be provided inter-hour integration
from PacifiCorp. The Company recently indicated in an Oregon discovery
response that it agrees with this position. 12/ I estimated this adjustment by
removing the Company's estimated 2010 inter-hour wind integration cost
($2.09/MWH) from the Company's assumed total wind integration cost used
in this case ($6.S0/MWH).
Adjustment 5: Non Owned Intra Hour Wind Farm Integration Costs
PLEASE DISCUSS THIS ADJUSTMENT.
This adjustment completes the disallowance of the cost of integrating OA TT
customer wid fars by removing the intra-hour cost component. It is
computed by tang the residual of the figures quoted above ($6.50-$2.09)
times the OATT wind far MWH.
DOES THIS ADJUSTMENT HAVE AN IMPLICATION FOR THE
TRUE-UP PROCEEDING?
Yes. The true up should make a parallel adjustment for OATT wind fars to
eliminate the actual cost of providing integration services to these entities. If
this is not done, retail customers will be charged for providing service to
wholesale transmission customers.
Exhibit No. 607 at 1 (Response to OPUC DR 22, OPUC Docket No. UE 216).
22
1 7l"ilkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1 D. OUTAGE RATE MODELING ISSUES
2 Q.EXPLAIN THE USE OF THERMAL DERATION FACTORS IN GRID.
3 A.In GRID, thermal deration factors (also called unplaned outage rates) control
4 the amount of generation available from thermal unts. The more energy
5 available, the lower net varable power costs. If a generator has an average
6 unplaned outage rate of 20%, GRID assumes a thermal deration factor of
7 80%. This means that only 80% of the unit's capacity is available to produce
8 energy. The remaining capacity is assumed to be permanently unavailable.
9 The Company computes thermal deration factors based on a four year moving
10 average of outage rates. This calculation includes all outage events that
11 occured durng the four year period (2006-2009). This provides a mechanism
12 for the Company to recover costs associated with prior outages, albeit at
13 curent market prices.
14 Q.
is
ARE UNPLANNED OUTAGES AN IMPORTANT DRIVER IN
OVERALL NET POWER COSTS?
16 A.Yes. Any increase in unplaned outages increases NPC. Consequently, it is
17 important to review unplaned outages .to determine if they were prudent or
18 reasonable to included in a four year moving average.
19 Adjustment 6-7: Lake Side and Colstrip 4 Extreme Outage Events
20 Q.PLEASE EXPLAIN TIDS ADJUSTMENT.
21 A.In reviewing Dr. Shu's workpapers, I noticed that Lake Side had an extremely
22 high outage rate modeled in GRID. Based on the historical data period used
by the Company, Lake Side had an outage rate of". In examining the data23
23
1 7 :ilkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 supporting this figure, I found that more than . of the lost energy was due
2 to a single event starting
3
4 Q.PLEASE DISCUSS THE LONG OUTAGE AT COLSTRIP 4 IN 2009.
5 A.A problem was discovered durng the 2009 planed outage of Colstrp 4,
6 which prevented the units' retu to service in May. The outage extended for
7 _ before the equipment could be repaired. This single event was
8 responsible for . of the lost generation at the plant in the entire four year
9 period. As a result, the Company computes an average outage rate for
10 Colstrip 4 of_. For 2009 this equates to an outage rate in
1 1 for the unit.
12 Q.
13
SHOULD THE ENTIRE DURATION OF THESE EVENTS BE
REFLECTED IN RATES?
14 A.No. These were extremely rare events and not ones likely to recur once every
is four years, as is assumed in the Company's four year moving average
16 calculation. It is very unikely that these events are representative of
17 conditions in the rate effective period. As a result, it is quite likely that
18 including these events in the test year outage rate will produce an inaccurate
19 forecast. Furer, the extreme length of these events suggests a prudence
20 investigation should be underten in the appropriate tre up proceeding.
21 Q.
22 A.
WHAT IS YOUR RECOMMENDATION?
I recommend these outages be capped at 28 days in the outage rate
23 calculation. This approach was recently recommended by a Company witness
24
17 :Flkenberg, Di
PacifiCorp Idaho Industrial Customers
.1 in a recent OPUC docket, UM 13SS, and provides a reasonable method for
2 dealing with extremely long outages. The figue below ilustrates in par, why
3 this is the case.4 Figure 2
PacifCorp Thermal Plant Outage Duration: 2004-2008
720
640
560
l
480
400
~320
240.160
80
0
..............................,..................................................................... .... ............ .... ,....,...... ... ............. .... .......... .., ......"... .... ........... .. .. .. , . .. .. . ............:-.......... -:-.......... -:-............:............:............ -:-........ ...:............:............:............:-............ ............... ... ............ ... . ........ ... .. ........ ... .. .......... . . . .. .. , .. .. ..
::::: i::::: :1:::::::::::::: i::::::::::::: r:::: i::::: i:::::: i::::::i::::::.:::::::.. .. .. . .. .. . .. .. ... . .. . .. .. .. .. .. ... . .. . .. .. . .. .. ... . . . .. .. .... .... , .. . .. .. .... .... . .. .. .. .. .. ........................................................................................... ............ ................. ............ ....,.. ....,.. ....,.. ..".. . .. .. .. .. .. .. .. . .
....LJ.r.........r..r.r....¡....CJ...... ¡....... .............. . . .. ..,.... . . .. ... .. .. ., ........ .. . . . . . . . . .............................................................................................. ............. . . . . .. ..,. . . . . ., .... . . . . .. ..,. . . . . .. . .. . . . . ., . .. . . . . . . .. . . . . . .
o 12 24 36 48 60
Percentile
72 84 96
5 Q.PLEASE EXPLAIN THE FIGURE ABOVE.
6 A.This char shows the cumulative percentage of forced outages occuring as a
7 fuction of outage duration. The data was based on all forced outages at
8 PacifiCorp plants from July 2004 to June 2008.13/ For example, more than
9 half of these events were lasted for five hours or less. Ninety percent were Sl
10 hours or less duration. Virtualy all of the events that occured (99.8%) were
11 less than 672 hours (28 days) duration. This clearly establishes that outages
.U This data was used because it is now considered "non-confidential" by the Company..25
1 7 ::kenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1 longer than 28 days are extremely rare and simply won't occur once every
2 four years for a specific resource.
3 Q.
4
S
PLEASE ELABORATE ON YOUR COMMENT THAT PACIFICORP
SUPPORTED THE CAPPING OF OUTAGES AT 28 DAYS IN A
RECENT OREGON CASE.
6 A.Oregon Docket UM 13S5 was a generic investigation into methods to improve
7 outage rate forecasts. Varous proposals were made by the paries.
8 PacifiCorp's final proposal was a "collar" mechanism that would eliminate
9 extremely high or low outage rates from the four year average calculation.
10 However, prior to applying its collar, PacifiCorp proposed to cap outage
11 durations at 28 days. 14/ If the anual average outage rate for the resource was
12 stil outside of a range based on historical data, the Company would fuher
13 reduce the outage rate under its collar proposaL.
14 Q.
15
16 A.
ARE YOU ADOPTING THE ENTIRE PACIFICORP OREGON
COLLAR PROPOSAL?
No, the PacifiCorp proposal has not been accepted by regulators, and has
17 varous other unrelated defects. In the Oregon case there are several other
18 competing alternatives and a decision is pending. In any case, capping the
19 long outages at 28 days would result in an outage rate for 2009 that would be
20 unikely to require adjustment based on the PacifiCorp proposaL. If any of the
21 UM 1355 collar proposals were applied, however, it would only serve to
22 fuher reduce the Lake Side and Colstrip outage rates.
HI Re OPUC Investigation Into Forecasting Forced Outage Rates for Electrc Generating Units,
OPUC Docket No. UM 1355, Supplemental Testimony of David J. Godfrey, PPL Exhibit No.
102 at 9 (July 24, 2009).
26
1 7 l'ilkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 Q.
2
WAS THIS TREATMENT OF LONG OUTAGES PREVIOUSLY
REQUIRED BY THE OREGON COMMISSION?
3 A.Yes. In the final order in Oregon Docket UE 191, the OPUC stated as
4 follows:
S The Company documents show that the anticipated duration of
6 the resulting outage was five to seven weeks. An outage of that
7 duration, no matter what the cause, is anomalous, and raises
8 issues regarding its inclusion in normalized rates. In ths case,
9 we find that a 28-day period is a reasonable limit on the lengt
10 of the outage for the purose of calculating the TAM
11 adjustment factor. To the extent the actual outage exceeded 28
12 days, the Company should make an appropriate adjustment to
13 the outage rate used in rung the GRID modeL. 15/
14 Q.
is
WILL CAPPING FORCED OUTAGES AT 28 DAYS RESULT IN
IMPROVED ACCURACY FOR OUTAGE RATE FORECASTS?
16 A.Yes. This issue was analyzed also in Oregon Docket UM 1355. Based on an
17 analysis of four year moving average forecast of outage rates for PacifiCorp
18 plants from 1989 to 2008, the use of the 28 day cap reduced the sum squared
19 forecast error by more than 9% as compared to use of four year moving
20 average based on the uncapped data. I also performed statistical tests to
21 determine the validity of this accuracy gain. The results indicate that the
22 accuracy improvement is statistically signficant at the 99% percent
23 confdence leveL.
24 Q.WHAT IS YOUR RECOMMENDATION?
2S A.I recommend the Commission limit the long 2009 Lake Side and Colstrip
26 outages to 28 days. The impact ofthis adjustment is shown on Table 1.
1l Re PacifiCorp's 2008 Trasition Adjustment Mechanism, OPUC Docket No. UE 191, Order
07-446 at 21 (Oct. 17, 2007).
27
1 7 'llkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1 Adjustment 8: Bridger Fuel Quality
2 Q.
3
CAN FUEL PROBLEMS CAUSE GENERATOR OUTAGES OR
DERATIONS?
4 A.Yes. Fuel problems can result in a reduction to capacity, or a complete
S shutdown of a plant. Some problems, such as frozen or wet coal are caused
6 by bad weather and are beyond the Company's control. However, fuel quality
7 testing is a normal practice at all power plants and is intended to prevent
8 output reductions, violation of air quality standards or damage to power
9 plants. Utilties report to Nort American Electric Reliabilty Council
10 ("NERC") the instances where fuel quality problems result in lost energy due
1 1 to outages or derations.
12 Q.
13
DOES IT APPEAR THAT PACIFICORP HAS PROBLEMS WITH
FUEL QUALITY AT ANY OF ITS PLANTS?
14 A.There appears to be an inordinate number of derations at the Bridger plant
15 related to fuel quality problems. Review of data from 2006-2009 shows that
16 on average, the Company loses far more energy due to fuel quality issues at
17 Bridger than any other plant. In fact, 78% of all energy lost due to fuel quality
18 problems occured at Bridger. Bridger fuel quality losses are more than twice
19 the NERC average for comparably sized plants.
20 Q.
21 A.
WHAT IS YOUR RECOMMENDATION?
Bridger coal is produced at a Company owned captive mine. The level of fuel
22 quality losses is excessive and both the production of coal and the operation of
23 the plant are under the Company's direct control. Absent justification for
28
1 7 4Plkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 these circumstaces in its rebuttal case, I recommend the Commission
2 disallow the additional costs resulting from this problem.
3 Q.
4
HAVE YOU REVIEWED THE COMPAN'S COST INFORMATION
FOR THE BRIDGER PLANT?
5 A.Yes. The Company also has included substantial costs in the test year related
6 to management bonuses, employee meals and gifts and donations as par of
7 the Bridger coal costs. Given the fuel quality issues at this plant, I believe it
8 would be reasonable to require the Company to absorb these costs until it can
9 demonstrate that its overall performance has improved. Adjustment 8 on
10 Table 1 includes both of these adjustments.
11 Adjustment 9: Naughton 3 Outage
12 Q.PLEASE EXPLAIN THE BASIS FOR ADJUSTMENT 18.
13 A.This adjustment removes outage events that occured at Naughton Unit 3 in
14 April and May 2009 from the historical record used to compute outage rates
is for GRID. Exhbit 607 (page 2) is a copy of a recent discovery requesil/
16 concerning this event. Exhibit 608 (pages 6-9) is a copy of confidential
17 discovery information from another discovery responsel7/ demonstrating that
18 the Company's contractor,
19 According to the Company, the contractor
20
21
22
12
11
See Exhibit 607 at 2 (Response to ICNU DR 2.5).
See Exhibit 608 at 6-9 (Response to ICNU DR 2.3).
29
1 7 f4kenberg, Di
PacifiCorp Idaho Industral Customers
.1
2
3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
17 Q.
18 A.
19
20
21
22
23
.
.
Because the
Company was compensated by Siemens for these problems, imprudence
and/or negligence is not debatable.
Consequently, I made adjustments to both planed and forced outages.
DOES THE LIQUIDATED DAMAGES PAYMENT COMPENSATE
CUSTOMERS FOR THIS EVENT?
No. Replacement power costs were much higher and if the outage is included
in the historical record for the next four years it would result in customers
bearing substantially greater costs, at curent market price levels.
Adjustment 10: Heat Rate Deration Adjustment
WHAT IS THE PURPOSE OF ADJUSTMENT 10?
This adjustment adjusts heat rates so they are not arificially inflated due to
the deration of unt maximum capacities used to model forced outages in
GRID. A modeling technque designed to eliminate this problem is already
used by at least one other regional utilty, Portland General Electrc ("PGE"),
in its power cost model, MONET. I believe this represents standard industr
practice, as do other experts. For example, in Utah Commission Docket No.
30
1 7 fâkenberg, Di
PacifiCorp Idaho Industrial Customers
.1
2
3
4
5
6
7
8 Q.
9 A.
10
11
12
13
14
15
16
17
18
19
20
w
J2
.
.
07-03S-93, another power cost modeling expert, Mr. Philp Hayet, testified
that the technique is well accepted in the 'communty of production cost
modeling experts. 181 Furher, ths technique was recommended for application
to PacifiCorp by OPUC Staf witness, Kelcey Brown in OPUC Docket UM
13SS. 191 Finally, PacifiCorp itself uses the same technique for modeling of
fractionally owned unts, such as Bridger and Colstrp. The adjustment I
propose in this case is a simplification intended to parially address ths issue.
WHY is AN ADJUSTMENT NECESSARY?
In GRID, and some other power cost models, forced outages are modeled by
"shrinking" the capacity to account for outages. For example, a 100 MW unit
with a 20% forced outage rate is seen as an 80 MW unt.
A problem with the GRID modeling is that when'the capacity of units
is derated to model outages, there is a mismatch with the heat rate cure. The
char below shows what happens when a heat rate cure sized for a 100 MW
unit is applied to the now shren 80 MW unit. The unit arificially "moves
up the heat rate cures" and efficiency appears to be reduced. As the forced
outage rate increases for a unt, its heat rate normally increases in the GRID
modeling. This, however, is highly unealistic, as lengthening the period of a
forced outage should have no effect on the resources average heat rates. The
GRID method also "rewards" the Company for having high outage rates.
Re Rocky Mountain Power 2007 General Rate Case, Uta Commission Docket No. 07-035-
93, Direct Testimony of Philp Hayet, Exhibit No. CCS 5D at 25 (April 7, 2008).
Re OPUC Investigation Into Forecasting Forced Outage Rates for Electric Generating Units,
OPUC Docket No. UM 1355, Supplemental Reply Testimony of Kelcey Brown, Staff Exhibit
No. 300 at 20 (August 13, 2009).
31
1 7 -Flkenberg, Di
PacifiCorp Idaho Industrial Customers
.
.
.
1 Q.
2 A.
Figure 3
GRID Heat Rate Penalty
9.0
8.5
:i
! 8.0
3" 751; .
:æ
:æ 7.0
6.5
-Average Heat Rate Curve 10% FOR
6.0
60 64 68 72 76 80 84 88 92 96 100
MWCapacit
DO YOU HAVE AN DATA THAT ILLUSTRATES THIS PROBLEM?
Yes. When the long outage for the Lake Side plant, discussed above, was
3 removed from the GRID database, the average heat rate for Lake Side was
4 decreased by .9%. However, it stads to reason that the time spent when a
5 plant is sitting idle should have no impact on its average heat. The fact that it
6 does in GRID, is proof that ths problem is reaL.
7 Q.
8
9 A.
10
ii
12
HAS THE COMPANY ALREADY CONCEDED THERE IS VALIDITY
TO THIS ARGUMENT?
In Oregon Docket UM 13SS, the Company's witness, Mr. Gregory N.
Duvall's testimony indicated he agreed that at least at the derated maximum
capacity of a unt, the criticism was valid. Mr. Duvall testified that the
solution I propose was not correct below the derated maximum capacity and
32
1 7 ~lkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1
2
3
4
5
6
7
8 Q.
9 A.
10
11
12 Q.
13
14 A.
15
16
17
18
19
20
21
that "the issue that ICNU is trying to address (i.e. the heat rate to use at the
derated capacity level) is near zero in this example, and is not nearly as large
as the error they create.,,201 His testimony addressed different aspects of this
problem, for which I proposed a more comprehensive solution in the Oregon
case using the techniques alluded to above. The reference to the adjustment
being "near zero" was based on the heat rate cure for a single plant, which
was unepresentative.
DO YOU AGREE WITH THE COMPAN ABOUT THIS?
No. However, for puroses of this case, I will concentrate solely on the
impact of the problem when generators are modeled as rung at the derated
maximum capacity, which the Company has apparently conceded.
CAN YOU PROVIDE AN EXAMPLE WHICH ILLUSTRATES THIS
PROBLEM?
Yes. The Confidential table below ilustrates the problem. It shows the heat
rate equation used in GRID for Bridger Unit 2. Based on the data used in
GRID, the capacity of Unit 2 is approximately _. However, there are
parial outage derations that occur, that lower the available capacity to .
. on average. These events do not result in shutdown of the plant, but do
degrade the average heat rate in the field and should do so in GRID as well.
Based on the average _ capacity loading, the heat rate for the unit is
.. MMBTU/MWh.
Wi Re OPUC Investigation Into Forecasting Forced Outage Rates for Electric Generating Units,
OPUC Docket No. UM 1355, Supplemental Testimony of Gregory N. Duvall, PPL Exhibit
No. 405 at 19 (July 24,2009).
33
1 7 4lkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 In GRID, however, full forced outages are assumed to reduce the
2 maximum available capacity of the unt by an additional. MW, resulting
3 in a maximum derated capacity in GRID of. MW. When the GRID heat
4 rate cure is applied, the result is _ MMBTU/MWh. When the Bridger
5 fuel cost difference is applied to the difference between the two heat rates, the
6 resulting error is close to. This may seem like an inconsequential amount,
7 however this problem occurs thousands of hours per year for nearly every unt
8 and can become a very substantial sum of money.
9 Q.
10
HAVE YOU PERFORMED AN ANALYSIS USING GRID THAT
ISOLATES THE IMPACT OF THIS PROBLEM?
11 A.Yes. I isolated the effect based on only the hour when units were dispatched
12 to the maximum derated capacity in GRID. I computed the hourly cost
34
1 7 4F7alkenberg, Di
PacifiCorp Idaho Industrial Customers
.1
2
3 Q.
4 A.
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
differences in the same maner as shown above. The result is the amount
shown on Table 1.
ARE THERE OTHER ASPECTS OF TIDS PROBLEM?
Yes, as I mentioned above. This adjustment only isolates the problem at the
high end of the heat rate cure. A similar problem exists at lower loadings.
Furher, the Company reduces the maximum capacity of unts in GRID to
model outages, but does not do so for the minimum loading levels. It is
possible to implement a more comprehensive adjustment in GRID to address
these issues. However, given the presence of a true-up which tends to mute
the importance of modeling issues, and because Adjustment 10 captues the
majority of the effect, I have not included the other components of this
adjustment, in the interest of economy.
E. TRANSMISSION ISSUES
Adjustment 11: DC Intertie Costs
Q. WHAT IS THE PURPOSE OF THE DC INTERTIE CONTRACT?
A.
w Exhibit 608 at 1 (WUTC Docket No. UE-I00749, Response to ICNU DR 1.33)..3S
1 7 4llkenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1
2
3
4
5
6 Q.
7 A.
8
9
10
11
12
13
14
15
16
17
18
WHAT is YOUR RECOMMENDATION?
This contract should be removed from the test year to match costs and
benefits. There are few, if any, transactions that rely on this contract.
Presumably, in actual practice the Company would not make such purchases
unless they resulted in cost savings. The contract may provide compensating
benefits, but because the test year is largely based on projected data there are
none that can be identified and included at ths time. However, it is possible
that if the contract is not really useful to the Company any longer, it may be
the Company should consider sellng its rights, or seeking to escape from it.
Transmission capacity in the region is limited, and it is hard to imagine that
this importt link has no value. The Company should be required to
demonstrate the prudence of its management of this contract in the next
ECAM true-up.
'l Exhibit 609 (WUTC Docket No. UE- 100749, Response to ICND DR i 0.3).
36
1 7 61kenberg, Di
PacifiCorp Idaho Industral Customers
. 1 Adjustment 12 - Populus to Ben Lomond Line Loss Adjustment
2 Q.
3
4
5 A.
ARE YOU TAKING A POSITION REGARDING THE RATE
TREATMENT OF THE POPULUS TO BEN LOMOND LINE IN THIS
CASE?
No. The issues related to timing, prudence and used and usefulness of the line
6 are beyond the scope of my testimony and presumably will be addressed by
7 other witnesses. However, if the Commission chooses to include the line in
8 rates, there are certin issues that should be addressed.
9 Q.
10 A.
WILL THE POPULUS TO BEN LOMOND LINE REDUCE LOSSES?
Yes. The Company agrees that the line would produce a reduction in 10sses.W
1 1 One of the advantages of using higher voltages is that losses are reduced.
12 This follows from the equation Ploss = p2R/2. However, the above equation.13
14
is appropriate for a single line viewed in isolation, but is not directly
applicable in the case of a complex transmission network. 24/ The Company
is has produced an estimate indicating that at a 700 MW loading, savings in
16 losses with the Ben Lomond line in place would amount to 10.8 MW based on
17 a load flow study. 25/
18 Q.
19 A.
HOW DID YOU QUANTIFY THE LOSS REDUCTIONS?
I assumed that most of the savings were the result of higher voltages on the
20 segment covered by the Populus to Ben Lomond line. I therefore computed
21 the reduction in losses based on the squaed ratio of loadings on the line. For
w
W
'l1.
See Exhibit 606 (Utah Commission Docket No. i 0-035-89, Response to OCS DR 2.5, 6.5,
and 6.7).
Id.
Id.
37
1 7 $àlkenberg, Di
PacifiCorp Idaho Industrial Customers
.1 example, when the line was loaded to 700 MW, the loss reduction was lO.8
2 MW. If the loading was 600 MW, the loss reduction was (600/7ooi*lO.8?6/
3 I computed these savings on an hourly basis outside of GRID, though I expect
4 results using GRID would be quite close. The results are shown on Table 1. I
S believe this is a reasonable, if not conservative, approach, but would certinly
6 welcome input from the Company on this matter.
7 Adjustment 13: Transmission Contract Adjustment
8 Q. DOES COMPLETION OF THE POPULUS TO BEN LOMOND LIN
9 REDUCE THE NEED FOR PURCHASED TRASMISSION
lO CAPACITY?
11 A. Yes. The Company will no longer need some of the short term firm and
12 contract capacity it is purchasing, once the new line is completed. There is a.13 61 MW contract that expires of the
14 new transmission line.
15 Q.
16
17 A.
IS THE 61 MW CONTRACT NEEDED AFTER COMPLETION OF
THE POPULUS TO BEN LOMOND LINE?
No, for two reasons. First, it produces no economic benefits in the GRID
18 study. Second, if capacity were actually needed for reliabilty purposes, it
19 would be far more cost effective to purchase 61 MW ofSTF capacity.27/
20 Q.
21 A.
22
23
1,/
7J.
DID YOU EXPLORE THIS ISSUE IN DISCOVERY?
Yes. While the Company does not agree that the new line eliminates the need
for the 61 MW contract, it does not indicate the contract would be extended.
Instead the Company merely indicated it would study whether the additional
This method turs out to be more conservative than simply using the ratio ofthe loadings.
See Exhibit 606 at 2 (Response to OCS DR 6.2).
38
1 7 .ilkenberg, Di
PacifiCorp Idaho Industrial Customers
.1
2
3
4
S
6
7
8
9
10 Q.
11 A.
12
13
14
15
16
17 Q.
18 A.
19
20
21
'l!
?J!
.
.
capacity was needed in the futue.281 Conversely, in other discovery
responses,291 the Company clearly indicated it would require additional
capacity if the Populus to Ben Lomond line was delayed. I believe that ths
demonstrates the avoidance of ths high cost transmission contract is one of
the benefits of the line that should be included as a par of the pro-forma
adjustment to reflect all of the costs and system benefits of the project,
assuming it is included in the test year. The impact of this adjustment is
shown on Table 1.
F. NON FUEL START UP O&M
IS ADJUSTMENT 14 DISCUSSED ABOVE A NPC ADJUSTMENT?
No. It is a reduction to non-fuel O&M and is not in one of the accounts
included in the definition ofNPC. For this reason, it is included at the bottom
of Table 1, and not par of the NPC adjustments listed. However, these are
legitimate test year costs, so they should be reflected in the test year, as
discussed above.
G. RECOMMENDED FILING REQUIREMENTS AND WORK APERS
DOES ICNU HAVE ANY OTHER RECOMMENDATIONS?
Yes. In stipulations in Oregon Docket UE 199 , Washington Docket UE-
09020S and Wyoming Docket 20000-341-EP-09, PacifiCorp has agreed to
provide certain workpapers and supporting documents at specific times, as
well as immediate access to the GRID model with its fiings. Experience with
Id.
See Exhibit 606 at 3 (Response to OCS DR 6.3).
39
1 7 ~kenberg, Di
PacifiCorp Idaho Industral Customers
.
.
.
1 these requirements in other states has become increasingly positive as time
2 passes. Exhibit 609 provides a copy of the documents agreement related to
3 the filing requirements from Washington. I recommend comparable
4 workpaper fiings be required for Idaho as well.
5 Q.
6 A.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
40
1 7 Pàlkenberg, Di
PacifiCorp Idao Industral Customers
.
.
.
Q.
2 A.
3
4 Q.
S A.
6
7
8
9
10
11 Q.
12 A.
13
14
is
16
17
18
19
20
21
22
23
24
2S
26
27
28
29
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
Randall J. Falkenberg, PMB 362, 8343 Roswell Road, Sandy Sprigs, GA
303S0. I am the same witness who fied direct testimony October 14,2010.
WHAT IS THE PURPOSE OF THIS TESTIMONY?
My testimony addresses the rebuttal testimony filed by PacifiCorp witness Dr.
Hui Shu on November 16 and on November 24. I update my Table 1
adjustments and address issues related to the screening adjustment, star up
energy, sta up O&M, wind integration, and the heat rate adjustment. Unless
otherwse noted, I find the various PacifiCorp criticisms of all my other
adjustments unpersuasive.
PLEASE SUMMARZE YOUR TESTIMONY.
My conclusions are as follows:
1. The GRID unit commitment logic contains a serious error,
acknowledged by the Company. Dr. Shu agrees with my proposal to
entirely replace the faulty GRID logic with manual calculations of
daily screens. For puroses of this case, I accept Dr. Shu's screen
modeling methodology, though I disagree with one of her
assumptions.
2. Dr. Shu's opposition to Adjustment 14 (starup O&M) is inconsistent
with her inclusion of these undocumented and unsupported costs in
calculating the daily screens. Remove the impact of startup O&M
increases Adjustment 1 (Commitment Logic Screens) on Table 1 -
SurebuttL.
3. Dr. Shu opposes Adjustment 2 (starp energy) based on two GRID
runs performed using the uncorrected GRID logic. Consequently, her
analysis simply measures the random effect of the GRID logic error on
two different scenarios and not the issue of staup energy.
4. Table 1 -Surebuttal updates Adjustment 2 (Starp Energy) to reflect
the Company's rebuttl GRID run and proposed screens.
i
1 7 ~lkenberg, Di - Sur
PacifiCorp Idaho Industrial Customers
.
I
2
3
4
5
6
7
8
9
10
II
12
13
14
is
16
17
18.19
20 Q.
21 A.
22
.
s. Adjustment 2 is quite conservative. Inclusion of the energy and
minimum downtime considerations in GRID, as suggested by Dr. Shu
would support a larger adjusent.
6. I accept Dr. Shu's proposal to remove the Seattle City Light Stateline
contract from Adjustments 4 and S (Non-Owned Wind Integration).
However, I continue to support the remainder of these adjusents.
This change is reflected on Table 1 - Surebutt.
7. Dr. Shu's criticism of Adjustment 13 (Idaho Power Point to Point)
fails to recognize the purse of a balanced pro-forma adjustment.
The Company seeks to include the costs of the new trsmission line
as if it came on line in Janua 2010 nearly a year prior to its actul in-
service date. However, in the case of the no longer needed Idaho
Power PTP contrct, the Company would continue to include the costs
of the contract in the test year.
8. Dr. Shu's rebutt of the Adjustment 10 (Heat Rate Adjustment)
addresses a proposal adopted by regulators in Oregon, not my curnt
proposaL. My adjustment addresses only the impact of the heat rate
modeling problem at the maximum derated capacity, which Dr. Shu
acknowledges may be valid.
HAVE YOU UPDATED TABLE 1?
Yes. Below is my new Table i reflecting my current position on my varous
adjustments:
2
1 "ßenberg, Di - Sur
PacifiCorp Idaho Industrial Customers
.Table 1 Surrebuttl
Summary of Recommended Adjustents
.
i. GRID (Net Variable Power Cost Isses)
PacifiCorp Request NPC
A. GRID Commitment Logic Err and Start Up Cost
1 CommifmeRt logc SCFeel.f
1 Commitment Logic Screens1/
2 SIa i. éAeFgy :I
2 Start Up Energy 'l
B. Long Term Contrct Modling
3 SMUD Contrct Delivery Pattm
C. OATT Wind Integration Cost
4 A'(n Oved lAte Heur Wind
4 Non-Oned Inter Hour Wind
S NOA O'llfeEl ¡Aba 1=0l:F VViAS
5 Non-Oned Intr Hour Wind
D. Outage Modeling and Other NPC Adjustents
6 Lake Side Outage
7 Colstp Outage
8 JBFuel Adjustents
9 Naughton Outage
10 Heat Rate Adjustent
E. Transmisson Isses
11 DC Interte Cost
12 Populus to Ben Lomond Line Losss
13 Idaho Power PTP Contrct
Subtotal NPC Baseline Adjustents .
Allowed. Final GRID Result*
G. Oter Adjustents
~ COMbined Cycle O&M AdjY6ent
Total Adjustents
Notes
1/ Company Screen Result accepted but Increased to reflect 0 start up O&M
'l Based on original (coal value) method. If Min Down Time/GRlDvalue used
.
Total
Company
Es ID
Jurisdicton
6.36%
5.51%
SE
SG
1,069,701,315 69,200,000
(5B,42 ~
(3,642,909)(216,134)
(1; 616,474)(9
(1,629,483)(96,6n)
(1,566,786)(92,957)
(2,04'1196)('12"' 60
(1,367,359)(81,125)
(4.3~O,OO1)(256.307)
(2,892,820)(171,631)
(2,163,834)(128,380)
(1,300,710)(77,171)
(2,460,037)(145,954)
(700,273)(41,547)
(1,831,473)(108,661)
(4,766,400)(282,791)
(1,146,067)(67,996)
(842,386)(49,979)
(26,310,536)(1,561,004)
1,043,390,n9 67,638,996
(490,00)~
(26,310,536)(1,561,004)
(1,946,856)(115,507)
3
17 tfé11kenberg, Di - SurPacifiCorp Idaho Industrial Customers
.
.
.
i Screening Adjustment and Startup O&M
2 Q.
3 A.
WHY is THE GRID SCRENING ADJUSTMENT NECESSARY?
The GRID model contans a serious logic error that prevents it from correctly
4 determining the most economic sta and stop sequence for cycling resources.
5 The problem is so serious that the Company has agreed with the proposal I
6 made in my direct testimony to abandon the GRID logic entirely, to replace it
7 with a manual calculation to determne the optimal daily schedule for cycling
8 resources.
9 Q.
10
11 A.
12
13
HAVE YOU EXAMINED THE COMPANY'S PROPOSED
SCREENING METHOD?
Yes. It appears to produce results that approach those of the screening
analysis I have developed. For puroses of this case, I accept their proposed
methodology. However, time for review was limited so, I would hesitate to
14 accept it care blanche for all futue cases.
is Q.
16
17 A.
DO YOU HAVE ANY REMAINING CONCERNS REGARING THIS
ISSUE?
Yes. The screening methodology considers whether the cost of staring up a
i 8 unit is offset by the power costs it wil avoid. Starp costs have two
19
20
21
22
23
components - starup fuel and staup O&M. In general, higher staup costs
reduce the overall efficiency of operation and increase NPC because they
prevent certin economic sta ups from occurng.
As my screening method would change the number of sta, I
recommended that these increments to starup O&M be reflected in the test
4
1 'Filkenberg, Oi - Sur
PacifiCorp Idaho Industral Customers
.
2
3
4
S
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
22
23.
year. Dr. Shu opposes this adjustment on the basis that such incrementa
O&M costs were not originally included in the test year. I disagree with her
reasoning. Either star up O&M represents a legitimate test year cost or it
does not. If they are legitimate, they should be included in the test year. If
not, then they should be excluded from the screening calculation.
The Company can't have it both ways - they can't increase NPC on
the basis of including starp O&M in the screening calculation, while
ignoring the impact eliminating some of these stars on overall revenue
requirements. It is puzzling to me that in at least one prior case, the Company
did seek to include the incremental sta up O&M when it produced higher
revenue requirements. In this case, the Company opposed my adjustment
when it would lower revenue requirements.
Q. DO YOU HAVE ANY OTHER CONCERNS REGARDING THE
STARTUP O&M EXPENSES?
A. Yes. I have examined this issue for several years. On numerous occasions I
have directed discovery questions at this issue. In all that time, the Company
has never once provided any documentation supporting the assumed level of
the starup O&M figures they rely upon. Given the circumstances, I am now
questioning whether this "cost" really has any basis in fact. Considering that
they do not wish to reflect this cost in the test year, I recommend it be
eliminated from the determination of the screens. As a result, I have
recomputed Dr. Shu's screening adjustment to reflect the more optimal
sequence of stas and stops that would accompany the removal of the
S
1 7 nlkenberg, Di - Sur
PacifiCorp Idaho Industral Customers
.
2
3
4
S Q.
6
7
8 A.
questionable and undocumented stap O&M expense. This adjustment is
shown on Table i. i also remove Adjustment 14, the original stap O&M
adjustment as recommended by Dr. Shu.
Start Up Energy
ON PAGE 25, DR. SHU SUGGESTS THAT NPC SHOULD BE
INCREASED BY $4.7 MILLION IF YOUR START UP ENERGY
ADJUSTMENT IS ACCEPTED. DO YOU AGREE?
No. First, I'~_.p"';~~led why the Company would not want to include this
9 additional cost if there trly was a sound basis for doing so. However, review
1 0 of the caculation of the $4.7 millon figure reveals it is totaly lacking in
11
12 Q..13 A.
14
15
16
17
18
19
20
21
22
.
merit.
PLEASE EXPLAIN.
Dr. Shu contends that if staup energy is included in GRID, the minimum
downtimes for gas plants should be increased. She then claims that doing so
would increase NPC by $4.7 milion. However, her calculation of the $4.7
milion is based on taking the difference between two GRID rus with and
without the longer downtimes. Unfortately, her GRID studies are
meaningless because they relied completely upon the faulty GRID logic which
Dr. Shu has now abandoned. Dr. Shu made no attempt to detennine the
optimal sequence of sta and stops using a proper screening method. As a
result, she seems to be taking the position that two wrongs can make a right.
The $4.7 millon figure does nothing more than determine which of the two
6
1Fãtttenberg, Oi - Sur
PacifiCorp Idao Industrial Customers
.
.
.
1
2
3 Q.
4
S A.
6
7
8
9
10
11
12
13
14
15
16
17
18
19
scenaros is impacted the most by the GRID logic errr, not what the actu
impact of modeling minimum downtime would be.
DO YOU HA VE ANY OTHER COMMENTS REGARING THIS
ISSUE?
Yes. Dr. Shu has ignored the fact that my approach, which values the stap
energy at the cost of coal generation, is very conservative. A more detailed
analysis, which takes account of the actual downtimes and value of
replacement energy as determned in GRID, would support a larger rather than
smaller adjustment. This is because in many cases shut down times are
already long enough to accommodate longer downtimes. Furter, in most
cases, the value of the energy offset (even when reserves and other factors ar
accounted for) is much higher than the cost of coal energy. A footnote on
Table 1 shows the value of my adjustment based on an hourly analysis of
GRID rus which considers all these factors which relies on the Company's
GRID runs with the proposed screening adjustment.
In the end, I continue to rely on the original coal based analysis of
staup energy updated for the Company's proposed screens. I continue to
support the coal based analysis because it is simpler and as shown above,
conservative.
7
1 7 9(lkenberg, Di - Sur
PacifiCorp Idaho Industral Customers
.
.
.
14
15
16
17
1 OA IT Wind Integration Issue
2 Q.
3
4
DO YOU AGREE WITH DR. SHU'S PROPOSAL TO REMOVE THE
SEATTLE CITY LIGHT ("SCL") STATELINE CONTRACT FllOM
YOUR WIND INTEGRATION ADJUSTMENTS?
5 A.Yes. The revised adjustments are shown on Table 1. However, I do have
6 concerns regarding whether the SCL contract is compensatory. I find it
7 concerning that the Company may be adopting a strategy of subsidizing
8 wholesale wind generators at the expense of retail customers. I recommend
9 the Commission require the Company to justify the prudence of SCL and all
10 similar wind contracts in the next ECAM filing. In this maner, if the contract
ii costs tu out to be unjustified, ratepayers will be relieved on most of the costs
12 associated with it.
13 I continue to support the remainder of these adjustments for the
reasons stated in my direct testimony. As I pointed out before, the Company
has had more than six years to have obtaned approval to include wind
integration charges in its transmission rate strctue. Table 2 (source PUC
166) shows the Company's IRP wind integration costs since 2004.
Table 2 PaåfiCo IRP Wind Integraion Costs
IRPYear Wind Integraon Cost Reference to IRP Document
200IRP $4.64/MWh in 20 Dollars 200IRP, Appendix J - Renewable Generation Assumptions, pI! 15.
200IRP Update $4.64/MWh in 20 Dollars 200IRP, Appendix J . Renewable Generation Assumptions, pg 150.
20071RP $5.i0/MWh 20071RP , Appendix J - Wind Resource Methodology, pg 195
20071RP Update $5.10/MWh 2007IRP, Appendix J. Wind Resource Methodology, pI! 195
Proxy value of $11.45/MWh.
$8 tax C02 cost Scenario: $9.96/ MWh
200IRP $45 tax C02 cost Scenario: $1185 / MWh 200IRP, Appendix F - Wind Integration Cost Update
$8 tax C02 cost Scenario: $9.96 / MWh
200IRP Update $45 tax C02 cost Scenario: $11.85 / MWh 200IRP Appendix F . Wind Integration Cost Update
2011IRP $9.70MWh 2010 Wind Integration Cost Study (9-1-2010)
8
1flálllenberg, Di - Sur
PacifiCorp Idaho Industrial Customers
.
2
3
4
S
6
7
8
9
10
11
12.13
14
is
16
17
18
19
20
21
22
23.
Heat Rate Adjustment
Q. DO YOU HAVE ANY COMMENTS CONCERNING DR. SHU'S
TESTIMONY REGARDING THE HEAT RATE ADJUSTMENT?
A. Yes. Dr. Shu addresses an issue not in dispute in this case, albeit one similar
to my current proposal. Oddly, she makes almost no specific comments about
my actual adjustment other than to concede that at the derated maximum
capacity an adjustment to the heat rates may be waranted (Page 31, lines 18-
21, and page 34, lines 3-5). Ths was exactly what my adjustment does -
nothng more or less. This was clearly shown in my workpapers.
Examination of my workpapers would have also shown that for 40% of the
units, the adjustment is zero or positive (implying an increase to the full
derated heat rate). There is no basis for suggesting this adjustment is
systematically biased.
Q. PLEASE EXPLAIN THE DIFFERENCE BETWEEN THE PROPOSAL
YOU AR MAKING AND THE ONE DR. SHU ADDRESSES.
A. Dr. Shu seems to believe that I modified the entire heat rate curve. On page
3 1, she says PH C would "alter thermal units' heat rate curves...." The
remainder of her testimony, included the figures on page 33 are directed at
adjustments made to the overall heat rate curve, not the heat rate at derated
maximum capacity. For example, on page 33, she discusses that adjusting the
heat cure would, in her view, misstate heat rates below the derated maximum
capacity. While her contention is arguable at best, it has nothng to do with
my proposal in this case and I won't debate here. Likewise, in the additional
9
17 f:ãlkenberg, Di - Sur
PacifiCorp Idaho Industral Customers
.
2
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.
testimony she filed on November, 24, 2010, (page 3S, lines 1-4) she addresses
heat rates at loading below the derated maximum. Again, this was not a par
of my adjustment. Consequently, I continue to support my adjustment as Dr.
Shu has not provided any relevant or persuasive arguments against it.
Q. ON PAGE 31, DR. SHU CRITICIZES ADJUSTMENTS TO TH
MINIMUM CAPACITY OF GENERATORS. IS THIS PART OF
YOUR PROPOSAL?
A. No. Again, she is addressing modeling methods I did not apply in ths case,
for reasons explained in my original direct testimony and to focus solely on
the par of this issue which the Company has already conceded has validity.
Finally, it is wort noting that the modeling methods Dr. Shu disparages in
this cae were in fact adopted by the Oregon Public Utilty Commission
("OPUC") in its Final Order in the recently completed Case, UM 13SS. Also,
the testimony she presents was also presented in that case and found
unpersuasive by the OPUC. That case was conducted over a two-year period
and examined a wide range of modeling issues including the interplay
between heat rate and outage modeling methods.
Idaho Power Point to Point Contract
Q. WHY DOES DR. SHU OPPOSE YOUR IDAHO POWER POINT TO
POINT CONTRACT ADJUSTMENT?
A. Her reasoning escapes me. On page 38, she acknowledges the Idaho contract
was set to terminate based on consideration to the completion of the Populus
to Terminal line. Consequently, she seems to acknowledge the contract is not
needed after completion of the new line.
10
1 Fálenberg, Di - Sur
PacifiCorp Idaho Industrial Customers
In this case, the Company seems confused about the purose of a pro-
forma adjustment. A pro-forma adjustment is intended to reflect how all
system costs would have changed had the new resource been available for the
entire test year under normalized conditions. Whle the Company includes all
of the costs of the new line as if it wa in place for the entire test year, they
don't wish to consider the fact that par of the value of the line is eliminate the
need for varous transmission purchases. Oddly, the Company does agree to
exclude some of the low cost transmission purchases which are no longer
needed, but prefers to retain this one high cost contract. I see no basis for the
distinction between the contracts the Company has agreed to exclude and the
one it proposes to continue to include. I continue to recommend this
adjustment.
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
.
1 1
1 7 d4llkenberg, Di - Sur
PacifiCorp Idaho Industral Customers
.
.
.
18
19
1 (The following proceedings were had in
2 open hearing.)
3 MS. DAVISON: Thank you, Madam Chair.
4 Mr. Falkenberg is available for cross.
5 COMMISSIONER SMITH: Mr. Purdy.
6 MR. PURDY: No questions.
7 COMMISSIONER SMITH: Mr. Olsen.
8 MR. OLSEN: No questions.
9 COMMISSIONER SMITH: Mr. Otto.
10 MR. OTTO: No questions.
11 COMMISSIONER SMITH: Mr. Budge.
12 MR. BUDGE: No questions.
13 COMMISSIONER SMITH: Mr. Woodbury.
14 MR. WOODBURY: Staff has no questions, thanks.
15 COMMISSIONER SMITH: Mr. Hickey.
16 MR. HICKEY: I do.
17
CROSS-EXAMINATION
20 BY MR. HICKEY:
21
22
23
24
25
Q.Good afternoon, Mr. Falkenberg.
A.Good afternoon.
Q.Good afternoon, Mr. Falkenberg.
A.Good afternoon.
Q.I'd like to visit with you about a couple of the
1765
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 FALKENBERG (X)
PIIC
.
.
.
1 areas of adjustment to net power cost that you have proposed,
2 and I'd like to start with the Lake Side outage and the
3 Colstrip outage. And if you'll allow me, sir, to put some
4 context around this, you have looked at what the Company has
5 proposed to set as its base net power costs and tried to peel
6 back to specific issues embedded in that calculation, and this
7 would be one of those events that you have pulled out and
8 identified as an adjustment to the $1,070,000,000 worth of net
9 power costs proposed. Correct?
10 A.Yes. Those events go into the calculation of
11 outage rates, which does impact the net power cost.
12 Q.And the basis of this adj ustment is that you say
13 the Lake Side outage and the Colstrip outage at these
14 generation resources were too long, and because they're too
15 long, they're outliers and should be thrown out of the process
16 of calculating net power costs associated with outages.
17 Correct?
18 A.Well, I just -- I'm not I wouldn't agree
19 necessarily if you're saying too long in a sort of pej orati ve
20 sense, but they're longer than would normally be expected to
21 occur. So if we're trying to get the best forecast for the
22 rate-affected period, we would want to remove the extra link of
23 those outages and limit them to 28 days.
24
25
Q.Well, at least you and your client propose that.
The Company certainly doesn't agree with it. Correct?
1766
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 FALKENBERG (X)
PIIC
.
.
.
22
1 A.I don't believe they do, no.
2 Q.And there was testimony regarding this that was
3 supported by Mr. Chad Teply. Were you here when Mr. Teply
4 testified?
5 A.I was not.
6 Q.But to be fair about it, you've seen his prefiled
7 testimony?
8 A.Yes, absolutely.
9 Q.And you understand that Mr. Teply actually has
10 field responsibilities over the generation fleet of assets and
11 resources owned by Rocky Mountain Power and PacifiCorp?
12 A.Correct. That's right, but I don't think that he
13 testified that they expected outages of those magnitudes to
14 occur every four years.
15 Q.Well, let's talk about what he did testify to
16 then. You're aware of his testimony and you're aware that he
17 addresses in detail the Company's response to these two events
18 that you're saying are -- my words, maybe not yours -- outliers
19 and should be taken out of the average, and he went into detail
20 on what happened at those two resources, didn't he?
21 A.That's right.
Q.You don't dispute the fact that the Lake Side
23 outage was unplanned?
24
25
A.Yes.
Q.And you wouldn't disagree with the actions of the
1767
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 FALKENBERG (X)
PIIC
.
.
.
1 Company in bringing Siemens to Lake Side as -- to the Lake Side
2 plant as soon as possible to inspect the damaged equipment.
3 Did that seem like a responsible step?
4 A.Well, I don't have any problem with him doing
5 whatever it takes to get it back online. I guess that without
6 getting into some of the confidential material, it's my
7 recollection that they had some disputes with Siemens related
8 to another outage, and so --
9 Q.Well, I think you're alluding to the Naughton
10 outage, and I'm not identifying that one.
11 Are you aware of the fact that Mr. Teply, in his
12 filed testimony in this case, identified bringing someone from
13 Siemens to the plant to inspect the damaged Siemens equipment
14 at the Lake Side plant? Aren't you?
15 A.Yes.
16 Q.Seems like a prudent thing to do if the Siemens
17 generator is not working, to say, We need your help, come out
18 and look at it. Correct?
19 A.Yes, I agree.
20 Q.You don't question the Company's employment of an
21 independent generator expert in order to have an independent
22 analysis and recommendation and on how best to address this
23 repair work, do you?
24
25
A.No.
Q.And you're aware of the fact that the expert
1768
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FALKENBERG (X)
PIIC
.
.
.
1 stated that a stator -- S-T-A-T-O-R -- replacement was the only
2 option to return that unit to service. No facts to disagree
3 with that?
4 A. I agree with -- your question's a little
5 confusing. It seems like it was a double negative, but I don't
6 disagree with what the Company did.
7 Q.And I don't mean it to be a double negative.
8 Simply saying that recommendations were made when the Company
9 tried to first identify the problem and then deploy the
10 resources to fix the problem to bring the unit back online?
11 A.That's right. And the point I'm trying to make
12 is that outages of this long duration are not to be expected on
13 a continuous basis; that they are unusual events; and that,
14 therefore, if we want to do the best possible job of
15 forecasting what power costs will be in the future during the
16 rate-affected period, we would want to wash those out.
17 Q.I think I understand where you are on that and I
18 don't want to belabor it, but just quickly, we can put then the
19 Company's response to the Colstrip outage of identifying the
20 problem, bringing in the expertise you needed to to fix the
21 problem, and then getting on to bringing the resource back
22 online, those steps you don't question as imprudent, you just
23 say that the time it took was too long for purposes of what you
24 think reasonable time should have been?
25 A.Again, I'm not using it in a sense which I think
1769
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FALKENBERG (X)
PIIC
.
.
.
1 you're trying to suggest as some sort of a prudence issue.
2 What I'm saying is while prudence of those kinds of events
3 ought to be examined -- particularly, for example, in the
4 ECAM -- for what we're trying to do, we're trying to forecast
5 power costs, and what we're trying to say is do we expect that
6 on a recurring basis, once every four years, we would have
7 extremely long outages of that nature occurring at that plant,
8 and I don't think that anybody has suggested that we would.
9 Q.Okay. But you would have to agree that 28 days,
10 with all due respect, is somewhat of an arbitrary assumption,
11 isn't it?
12 A.Well, I think it's a little odd you would
13 characterize it as arbitrary when the Company itself proposed
14 it in an Oregon docket and the Company has been using that
15 limi tation in Oregon dockets for at least three or four cases
16 now.
17 Q.But you're attempting to impose that figure of
18 28 days in this case when there are, would you agree, 26
19 coal-fired resources throughout the fleet?
20 A.That sounds -- that's right.
21 Q.And 11 gas-fired resources?
22 A.Yes.
23 Q.For a total of 37 gas and coal-fired resources
24 that have the potential of going into an outage condition?
25 A.That's right.
1770
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FALKENBERG (X)
PIIC
.
.
.
1 Q.And then if you look at that occurring over four
2 years, we're getting into 37 units times 48 months, or
3 somewhere in the area of 1,4-, 1,500 times that of
4 those months, that those events could occur. Right?
5 A.Right. There are actually thousands of outage
6 events that occur during the four-year period that's used to
7 compute the outage rate that's used in the power cost model.
8 And in the ECAM, all of those events are going to be reflected,
9 all of the costs associated with those are going to be
10 examined, I would presume, and considered and included in the
11 true-up that's done.
12 If you take a look at my direct testimony on
13 page 25, what it shows is that outages of durations of 28 days
14 or longer are extremely rare. It's -- I think I computed it's
15 something like 99.8 percent of all events were less than 28
16 days long. So these were events that simply don't happen every
17 day, they don't happen every week or even every year. There's
18 been a couple in the last year, but that doesn't mean that
19 there are going to be any for the next year or two; hopefully
20 not.
21 Q.And your suggestion that these adjustments occur
22 wi thin the process of the ECAM again would subj ect these
23 expenses to the debt -- or, excuse me, to the sharing band of
24 90/10 percent. Correct?
25 A.That's correct, there would be the sharing band,
1771
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FALKENBERG (X)
PIIC
.
.
.
1 so presumably there would be some sharing of cost. And I
2 gather from the documentation I've read that that was what was
3 intended when the ECAM was established, but it wasn't going to
4 be a pure cost-plus type of arrangement.
5 And by the same token, if the Company is very
6 successful and manages to have less outage time than had been
7 built into the GRID model, then they would share some of that.
8 They would keep 10 percent of the benefit.
9 Q.So is it your testimony then that the 28 days
10 that you proposed in this case is not your suggestion, it's the
11 Company's suggestion?
12 A.Well, it was certainly the Company's suggestion
13 in testimony that they filed in a recent Oregon docket, it
14 certainly is what the Company has filed in Oregon cases in a
15 couple years, and it's something which the Oregon Commission
16 has approved in two different cases, and it's something that
17 I'm also recommending for this case.
18 Q.But as you're aware, Mr. Duvall doesn't agree
19 wi th your interpretation of the Company's position in Oregon.
20 Is that a fair statement?
21 A.Well, I'm not sure what Mr. Duvall -- what aspect
22 of that he's talking about. The Company filed testimony that
23 recommended a certain mechanism that was predicated on 28 days.
24 At a later time in the case, I believe the Company in its brief
25 argued against the 28-day limitation that they proposed in
1772
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 FALKENBERG (X)
PIIC
.
.
.
1 their testimony. So, it's unclear exactly what the Company was
2 thinking, but it would appear they didn't feel bound by the
3 recommendations of their own witnesses.
4 Q.Thanks, Mr. Fal kenberg . Let's move on to another
5 adj ustment.
6 You've identified something that is called out as
7 the DC intertie costs as another area that you wish to adjust
8 the Company's case to set base net power costs in this docket.
9 Isn't that true?
10 A.That's right.
11 Q.And to try to make some sense out of what is the
12 DC intertie cost, is ita fair summary from your perspective to
13 say that the Company pays $5 million to have the right to 200
14 megawatts of power that could come onto the system from Nevada,
15 to help identify geographically where the intertie is?
16 A.Right. It comes from the Nevada/Oregon border,
17 brings power to the west main area of PacifiCorp, and I believe
18 the cost is about 4.7 million.
19 Q.Fair enough. I appreciate your being exact on
20 that. But the purpose of the Company's incurrence of this cost
21 is to have the right to that 200 megawatts. Doesn't mean that
22 they will necessarily have to exercise that right every year,
23 but you would have to at least agree, Mr. Falkenberg, that the
24 system has a resource out there that when the conditions
25 require, it is available to benefit its ratepayers. Fair
1773
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
FALKENBERG (X)
PIIC
.
.
.
20
1 summary?
2 A.Well, I don't know that there is any resource out
3 there, because the transmission line that brings __
4 transmission line isn't creating power. It enables the Company
5 to bring some in. And it's not necessarily the case that any
6 is actually going to be out there.
7 What the Company has stated is that the resources
8 that are out there tend to be among the most expensive and
9 least used that are available, and so it's generally the last
10 thing that's used and it's not expected to be utilized on a
11 normalized basis. So the test year seems to be lacking in any
12 resources or any significant resources that rely on that
13 interconnect.
14 Q.Could you agree with me that the right to bring
15 resources in at that intertie is in the nature of an insurance
16 policy?
17 A.Well, an insurance policy is a little bit of a
18 reach. It seems that, you know, you have an insurance policy
19 for something you think might happen.
Q.Well, if I -- as I do -- have an insurance policy
21 on my life so that my wife is avoided the need of -- probably
22 not the best example, but I've got23 (Laughter. )
24
25
Q.BY MR. HICKEY: I'm going to move to the car,
Mr. Falkenberg. But that insurance policy lets me know that if
1774
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 FALKENBERG (X)
PIIC
.
.
.
1 I total my car, I have some resource that on that contingent
2 event is going to be available to allow me the ability to have
3 a drivable vehicle again.
4 Isn't that analogous to what the Company is
5 trying to do to have something in place so if the contingent
6 event happens, that there are desirably-priced power resources
7 in the area that could interconnect to that DC intertie, that
8 those could be brought onto the system for the benefit of the
9 ratepayers?
10 A.Well, car insurance may actually be sort of an
11 on-point example, because if you're paying, say, $30,000 a year
12 and your car is worth 20,000, it doesn't seem like a very good
13 policy.
14 So in this particular case, it's not as if the
15 resources that are potentially out there are very attractive.
16 They're so unattractive that the Company hasn't actually
17 arranged for anything, from what we can tell. So it seems, to
18 me, that an insurance policy has to be something that passes
19 some sort of a cost/benefi t test, and that you have to see that
20 it actually produces some value.
21 Q.Well, we'll continue to disagree on whether it
22 passes the test, but can we agree that you have been very much
23 involved in PacifiCorp cases since the 1990s?
24
25
A.Yes, I'm afraid so.
Q.Well, I wouldn't say -- but with that background,
1775
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 FALKENBERG (X)
PIIC
.
.
.25
1 there have been 16 or more years where you had access to
2 information about the DC intertie costs, and am I right, this
3 is the first year that you've raised this issue in?
4 A.You know, it's my impression that that used to be
5 a pretty valuable resource. It seems, to me, that the market
6 was somewhat different back in the day, I guess, in the last
7 century when I started working on this stuff. And it is
8 something we learned in discovery and where we tried to match
9 all of the different costs that were included in transmission
10 wi th what they're actually being used for, and the intent was
11 to figure out which of these costs were used and useful
12 resources; and through that discovery, which has sometimes
13 taken place over a couple of years, we did discover that there
14 wasn't really any transactions that seemed to match that
15 particular cost.
16 Q.Okay.
17 MR. HICKEY: If I could have just a minute?
18 We have no further questions of Mr. Falkenberg.
19 Thank you, sir.
20 COMMISSIONER SMITH: Thank you.
21 Do you have any redirect, Ms. Davison?
22 MS. DAVISON: No, thank you, Madam Chair.
23 COMMISSIONER SMITH: Thank you for your help,
24 Mr. Falkenberg.
If there's no obj ection, we will excuse him.
1776
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 FALKENBERG (X)
PIIC
.
.
18
19
20
21
22
23
24
. 25
1 MS. DAVISON: Thank you.
2 (The witness was excused.)
3 COMMISSIONER SMITH: Does that conclude your
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
5 MS. DAVISON: Yes, it does, Madam Chair. Thank
4 case?
6 you.
7 COMMISSIONER SMITH: We thank you.
8
9
10
11
12
13
14
15
16
17
1777
FALKENBERG (X)
PIIC