20101223Vol IX Technical Hearing pp 1778-2024.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
HEARING BEFORE
CASE NO.
PAC-E-10-07
TECHNICAL HEARING
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 IX - Pages 1778 - 2024
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HEDRICK
COURT REPORTING
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
s't/1f tk ~ ßQ/f~ .siru 19
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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, BUDCE
& BAILEY
by RANDALL C. BUDGE, Esq.
Post Office Box 1391
Pocatello, Idaho 8320 -1391
RACINE, OLSON, NYE, Buie;s
by ERIC L. OLSEN, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
BENJAMIN J. OTTO, Esq.
IDAHO CONSERVATION LEAC JS
710 North Sixth Street
Boise, Idaho 83702
WILLIAMS BRADBURY, PC
by RONALD L. WILLIAMS, !~sq.
1015 West Hays Street
Boise, Idaho 83702
-and-
DAVISON VAN CLEVE, PC
by MELINDA J. DAVISON, ¡'~sq.
333 Southwest Taylor, Suite 400
Portland, Oregon 97204
BRAD M. PURDY, Esq.
Attorney at Law
2019 North Seventeenth Street
Boise, Idaho 83702
7
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For Monsanto:
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12
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For Idaho Irrigation
Pumpers Association (IIPA):
15
16 For Idaho Conservation
League (ICL):
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For PacifiCorp Idaho
Industrial Customers (PI IC) :
For Community Action
Partnership Association
of Idaho (CAPAI):
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
lIPPEARANCES
.1 I N D E X
2
WITNESS EXAMINATION BY PAGE
3
Mark Mickelsen Mr.Olsen (Direct)1778
4 (lIP)Prefiled Surrebuttal 1781
Mr.Woodbury (Cross)1790
5 Mr.Otto (Cross)1791
6 Anthony Yankel Mr.Olsen (Direct)1794
(lIP)Prefiled Direct 1796
7 Mr.Solander (Cross)1841
8 Don Reading Mr.Otto (Direct)1845
( ICL)Pre filed Direct 1847
9 Commissioner Smith 1897
10 Teri Ottens Mr.Purdy (Direct)1900
(CAPAI)Prefiled Direct 1909
11 Mr.Otto (Cross)1925
Mr.Woodbury (Cross)1926
12
Randy Lobb Mr.Woodbury (Direct)1928.13 (Staff)Prefiled Direct 1930
Mr.Hickey (Cross)1961
14 Mr.Woodbury (Redirect)1966
15 Joe Leckie Mr.Woodbury (Direct)1968
(Staff)Prefiled Direct 1973
16 Mr.Solander (Cross)1987
17 Donn English Mr.Woodbury ( Direct)1993
(Staff)Prefiled Direct 1996
18 Mr.Solander (Cross)2011
Commissioner Kempton 2021
19 Mr.Woodbury (Redirect)2024
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HEDRICK COURT REPORTING
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INDEX
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1 EXHIBITS
2
NUMBER
4
For Rocky Mountain Power:
PAGE
3
93 IPUC Production Data Request 277, 3 pgs Marked 1963
1965
1904
5
6 For Staff:
7 133 02/09 The Cost of Transmission for Marked
Wind Energy: A Review of Transmission
Planning Studies, 2 pgs8
9
For CAPAI:
10
701 Contract - Low-Income Weatherization Marked
11
12
13
14
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HEDRICK COURT REPORTING
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EXHIBITS
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1 BOISE, IDAHO, THURSDAY, DECEMBER 2, 2010
2
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4 COMMISSIONER SMITH: Mr. Olsen.
5 MR. OLSEN: Thank you, Madam Chair. We'd like to
6 call to the stand Mark Mickelsen.
7
8 MARK MICKELSEN,
9 produced as a witness at the instance of Idaho Irrigation
10 Pumpers, being first duly sworn, was examined and testified as
11 follows:
12
13 DIRECT EXAMINATION
14
15 BY MR. OLSEN:
16 Q.Good afternoon, Mr. Mickelsen. Could I please
17 have you state your name and spell your last name for the
18 record?
A.Yes. My name is Mark Mickelsen:
20 M-I-C-K-E-L-S-E-N.
21 Q.In what capacity are you appearing in this
22 proceeding today?
23 A.I am president of the Idaho Irrigators Pumper
24 Association (sic). I am also a farmer in Idaho Falls.
25 Q.Okay. Can you please provide your business
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MICKELSEN (Di)lIP
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1 address for the record?
2 A. My address is 9088 North River Road, Idaho Falls,
3 Idaho, 83402.
4 Q.Now, Mr. Mickelsen, are you the same Mark
5 Mickelsen that prefiled some surrebuttal testimony in this case
6 dated November 29, 2010?
7 A.Yes.
8 Q.Do you have any corrections to that testimony
9 that was filed?
10 A.I have one correction: On page 3, line 10,
11 between "program" and "because," I would like to insert the
12 words "early on."
13 COMMISSIONER SMITH: I'm sorry, I can't find
14 it.
15 Q.BY MR. OLSEN: Page 3. Is that line 10 or
16 line II?
17 A.I may have an older copy.
18 Q.I think it's on line 11.
19 COMMISSIONER SMITH: All right. So one more
20 time.
21 THE WITNESS: I guess on page -- or, on line 11,
22 between the words "program" and "because," I would like to
23 insert the words "early on."
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COMMISSIONER SMITH: "Early on." Thank you.
Q.BY MR. OLSEN: Mr. Mickelsen, with that
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MICKELSEN (Di)
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1 correction, if I were to ask you the same questions that are
2 contained in the surrebuttal testimony today, would your
3 answers be the same?
4 A.Yes.
5 Q.Okay.
6 MR. OLSEN: With that, your Honor, I'd like to
7 move to spread upon the record Mr. Mickelsen's surrebuttal
8 testimony, and also identify Exhibit 304 which is attached
9 thereto.
10 COMMISSIONER SMITH: If there's no obj ection, we
11 will spread the prefiled surrebuttal testimony of Mr. Mickelsen
12 upon the record as if it had been read.
13 (The following prefiled surrebuttal
14 testimony of Mr. Mickelsen is spread upon the record.)
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1 Q.PLEASE STATE YOUR NAME, ADDRESS, EMPLOYMNT, AN
2 AFFILIATION WITH THE IDAHO IRIGATION PUMPERS ASSOCIATION, INC.?
3
4 A.My name is Mark Mickelsen, and I am the president of the Idaho Irgation
5 Pumpers Association, Inc. ("LIP A"). I far in the Osgood area of Bonneville County, Idaho.
6 My address is 9088 N. River Road, Idao Falls, Idaho 83402. I curently grow potatoes,
7 wheat, and canota, and my faring operations are principally serVed by Rocky Mountain
8 Power ("RMP").
9
10 Q.WHAT IS THE PUROSE OF YOUR TESTIMONY?
11
12 A.The purose of my testiony is to address the proposed changes to the
13 Irrgation Load Management Progr and the Agrcultual Energy Savers Program contained
14 in the Rebuttal Testimony of Carol L. Hunter.
15
16 Q.WHT INOLVMNT HAS THE IIA HAD IN TH DEVELOPMENT
17 AND IMPLEMENTATION OF RM'S IRGATION LOAD CONTROL PROPGRAMS?
18
19 A.As par of the settlement in PAC-E-02-01, IIA and RMP agreed to develop
20 al optional load management program in consideration for the removal of the long stading
21 interrptible irrgation rate schedule C and its associated load control benefits. This timer-
22 based program started out small, but continued to grow due to continuous refinement by
23 RMP and IIA, as well as IIPA's strong encouragement of its mefubers to paricipate in the
1 Mickelsen, Sur Rebuttal
Irgators1781
. 1 program. Eventually it provided in excess of 40 MW of load reduction to PacifCorp's
2 system durng the summer months. The curent version of this timer based program caii be
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3 found in RMP's Electrc Servce Rate Schedule No. 72.
4 In 2006, lI A worked with RMP in the development of the terms and conditions of a
5 dispatchable load control pilot program. This program was a vast improvement for all
6 involved in that the irrgation pumps were curailed directly by RMP (at its option) via a
7 communications device rather than a timer. The pilot program was successfu, in par, due to
8 IIA's input and marketing efforts amongst its members. As part of the settlement in PAC-
9 E-7 -05, RMP and lI A agreed to an increase in the credit for the dispatchable program based
10 on the level of irrgator paricipation for the 2008 and 2009 irrgation seasons. If irrigator
11 participation reached a certain level then the credit would be adjusted accordingly, as
12 follows:
Participation MW
Less than 150
150 to 175
175 or greater
Credit ($/kW-yrl
$23
$26
$28
Due to IIPA's and RM's marketing efforts, Irgator participation in the dispatchable
program significantly exceeded expectations, and in 2010 achieved and estimated 278 MW
of paricipation in July2 at the sales leveL. This estimated figue does not count those
participants in the timer program.
In the fall of 2009, LIP A and RM had fuer discussions regarding improvements to
the terms of the dispatchable program and the credit amount to be paid. These discussions
resulted in a Letter Agreement between RM and llPA makng changes to the term of the
dispatchable program and extendig the curent pricing and paricipation schedule though
2 1782 Mickelsen, Sur Rebutt
Irgators
. 1 the 2012 irrgation season. A copy of the Letter Agreement is attached hereto as Exhibit 304.
2 Now the dispatchable program alone consistently provides over 250 MW ofload reduction to
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3 PacifiCorp's system per control event. The curent version ofthis dispatchable program can
4 be found in RMP' s Electric Service Schedule 12A.
5
6 Q.DO YOU PARTICIPATE IN RM'S LOAD CONTROL PROGRAS
7 AN WH?
8
A. Yes. I have paricipated in RM's load control programs for the last four
irrigation seasons under the dispatchable program. I did not paricipate in the timer based
program because credit amount received did not exceed my opportity costs of increased
labor expense and reduced crop yields. I continually encourage all eligible irgators to
paricipate in RMP's load control program, and I and other members of the IIA's board
have invested a significant amount of time working with RM and lI A's members to make
the load control programs successfuL. This is based not only for the credit savings, which has
become crucial to many farmers in these uncertain economic times, but also for the benefits
of reducing RMP's overall system costs, the Idaho jurisdictional costs, and the irrgators'
18 class cost of service.
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20
1 Subject to a $2.00 adjustment up or down depending on RMP's final valuation of the benefit.2 Based upon RM's response to Irrigation request 23.
3 1783 Mickelsen, Sur Rebuttal
Irigators
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1 PLEASE SUMMAE RMP'S PROPOSED CHAGES TO THEQ.
2 DISPATCHALE LOAD CONTROL PROGRAM?
3
A. In light of the jurisdictional cost allocation and fuding issues raised in
this case, RM has proposed to reduce the magntude of the progr and ultimately
the costs associated with the dispatchable load control program ("Program") by (1)
restrcting parcipation in the Program to irgation pumps of at least 50 HP, (2)
providing RM flexibility to reject or narow the parcipants in the Program, (3)
increasing the peiialty a paricipant faces in the event the irrgator opts out of
participating in a load control event, (4) reducing the paricipation credit for the 2011
irrgation season from $30 per kW to $25 per kW, (5) having the admiiiistrative costs
of the Progrm remain situs assigned for the 201 1 irrgation season and having RM
and Staff work to address the issues of system cost allocation of the administrative
costs of the Program in the MSP process for 2012. RMP has had recent discussions
15 with II A's board regarding these proposed changes.
16
17 Q.WHT CONCERNS DOES THE lIPA HAVE WITH RMP'S
18 PROPOSED CHANGES TO TH PROGRA?
19
20 Just like the major capital investments that RM is now seeking toA.
21 place into rate base, the irrgation load control programs are a culmination of years of
22 effort, planng, trial and error to bring them to the cost effective and successfu point
23 they are at this time. RMP's proposed changes are aimed at cutting Program costs by
4 1784 Mickelsen, Sur Rebuttal
Irgators
. 1 shrnkng irrgator paricipation and, in the near term, reducing the credit amount paid
2 to paricipants. However, IIA's board believes that even if these are considered to
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3 be short term changes, they will have long term detrental effects because
4 confidence in the program may be lost.
5
6 Q.WHT LONG TERM EFFECTS WOULD BE EXPECTED?
7
8 A.For example, restricting paricipation in the program to 50 hp wil
9 remove 500 control units according to the Company. This may only mean a
10 reduction of 13 MW of paricipation, but to put this in perspective, there were less
11 than 2,000 parcipating sites in 2009. This change would impact over 25% of the
12 paricipating sites. This proposal is being made in spite of the fact that these devices
13 are curently in place and the cost of installation has already been expensed, if not all
14 ready recovered by RMP.
15 Additionally, this proposal is inconsistent with the curent tarff language
16 which states:
17 Once a LCSA is executed, Customers in the program wil be
18 considered program paricipants for subsequent years unless the
19 Customer explicitly communicates the desire to no longer
20 participate in the Load Control Credt Rider program or the program21 is cancelled. (Emphais added)
22 Furermore, giving RM the flexibility to reject curent parcipants at will puts the
23 program in even more jeopardy. How is RMP going to restrict participation? Wil it
24 be on a first-come-fist-served basis? What about all of the customers that are
5 1785 Mickelsen, Sur Rebuttl
Irgators
. 1 presently on the program-are they first in line? What about the changes that
2 irrgators had made to their systems so that they could parcipate in the program?
3 The changes in the opt-out provisions may sound good in isolation, but the
4 fact is that there are extremely few paricipants that opt-out at ths time. Furermore,
5 each time a customer opts-out, he pays the maginal purchase cost for the power he
6 consumes and the system is made whole at the highest purchase power cost. The
7 ominous penalties being proposed can only result in scarng irrgators away from
8 participating in the program.
9 The lIP A is disappointed that RMP is not going to live up to its agreement to
10 keep the pncing of the partcipation credit the same though 2012 as set fort in the
11 Letter Agreement. We mutually came up with a 3-year agreement only a year ago
.12 and now RM wants to unilaterally lower the credit. If the credit fluctuates, what
13 assurance do irgators have that the program wil continue to benefit them in the
14 future and that they should put forth the time and investment to paricipate in the
15 program?
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17 Q.
18 TIM?
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20 A.
WHT AR YOU ASKING THE COMMSSION TO DO AT THIS
The Commission needs to balancê how these changes wil affect the
21 continued long term viability of the irgation load control programs and not
22 jeopardize the prior investmeiits in time and effort that have brought us to this point.
23 Such a determination process is impossible to do in the very compressed rebuttal.
1786 Mickelsen, Sur Rebuttal
Irigators
6
. 1 testimony and subsequent techncal hearng schedule in this case. Thus, the IIPA
2 asks the Commission to bifucate the consideration of the Program changes from this
3 case so that RM, Staff, IIA, and other interested paries can more fuly vet these
4 issues in a expedited maner, without unintentionally affecting the long term viability
5 of the irgation load control program.
6 In the event that the. Commission is inclined to addrss substative changes to
7 the Program in its forthcoming Order, then the LIP A has the following comments on
8 RM's proposed changes to the Program:
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· First, the lI A is not opposed to restrcting futue paricipation in the
Program to pumps having a minimum of 30 HP. This change appears that
it would not have a significant effect on the total amount ofMWs of
Program paricipation and should reduce the equipment expenses.
However, like Idao Power, smaller Irrgators could parcipate if they pay
an installation fee. There is no beiie fit to go back to these customers that
presently have a control device and incur fuer costs to remove these
devices and incuring any accompanying il-wil.
. Second, the lI A supports in the inclusion of the Idaho Power
paricipation selection language so as to give RM flexibility in effciently
admnistering the Program. However, this flexibility should only be
applied to futue installation and any rejection of a customer should have
wrtten justification. It is my understading that even though Idao Power
has this flexibility, it has never exercised it. We do not want to give
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1787 Mickelsen, Sur Rebuttl
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1 language like that in Idaho Power's tarff and have it be used in a
2 completely different way by RMP.
3 . Third, the IIPA is not opposed to chages to the penaltyfor opt-out events
4 under Schedule 72A. LIP A believes that the amount of avoided load
5 should be there when called upon and that the penalty changes should help
6 avoid free-rider concern. . However, the penalty proposed by RM is!
7 excessive. Idaho Power has a fixed opt-out fee of$0.005 per kWh of
8 monthly billing. The lI A believes that this amount is significant, but we
9 would be willing to accept it for use in RMP. Anythig beyond this would
10 seriously jeopardize the program.
11 . Finally, the llA objects to RM's proposal to reduce the credit amount
12 under the Program from $30 per kW to $25 per kW for the 2011 irrgation
13 season. One of the keys to the success of the Program was setting the
14 credit at an amount that would be cost effective, i.e., the benefits exceed
15 their costs under respective regulatory tests, but also encourage sufcient
16 irrgator paricipation notwithstanding the irgators' opportunity costs of
17 increased labor expense and prospects of reduced crop yields. This is why
18 the IIA entered into the Letter Agreement to provide that credit certinty
19 to paricipants and associated paricipation so as to maintan this valuable
20 system demand-side resource. The LIP A believes that RMP should live up
21 to its obligations under the Letter Agreement and that the credit amount
22 should remain at its curent $30 per kW level for the 2011 and 2012
23 irrigation seasons.
8 Mickelsen, Sur Rebuttal
Irigators1788
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2 Q.WHT IS TH IIPA'S POSITION ON THE PROPOSED
3 ELIMINATION OF THE AGRICULTURL ENGERGY SAVERS PROGRAM?
4
5 A.The lI A understands that the Agrcultul Energy Savers Program is
6 not as cost effective as the load control programs, but points out that it still is
7 considered to be cost effective. The LIP A also acknowledges that a significant portion
8 of energy efficiency and load management dollars are spent for the agrcultual sector
9 programs. However, the LIP A believes that this potential imbalance is not the result
10 of any bias, but just a fuction of gettng the more bang for every buck spent on
11 irrigation program as opposed to other programs curently available to the customer
.12 classes. Neverteless, the lI A would defer to the judgment of the Commission as to
13 whether the Agricultual Energy Savers Progr~ is eliminated or not in order to
14 reduce energy effciency and demand side management costs.
15
16 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
17
18 A. Yes.
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9 1789 Mickelsen, Sur Rebutt
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1 (The following proceedings were had in
2 open hearing.)
3 MR. OLSEN: He's now available for
4 cross-examination.
5 COMMISSIONER SMITH: So -- and Exhibit 304 --
6 MR. OLSEN: Yeah.
7 COMMISSIONER SMITH:is identified.
8 Mr. Williams or Ms. Davison, do you have
9 questions?
10 MS. DAVISON: No, Madam Chair.
11 COMMISSIONER SMITH: Mr. Purdy.
12 MR. PURDY: I do not.
13 COMMISSIONER SMITH: Mr. Woodbury.
14 MR. WOODBURY: Just a matter of clarification.
15
16 CROSS-EXAMINATION
17
18 BY MR. WOODBURY:
19 Q.Mr. Mickelsen, were you in the hearing room
20 yesterday?
A.I was not.
Q.I asked a question of Company witness Hunter
23 regarding notice and the proposed changes to the irrigation
24 load control program, and it was surrounding what the
25 membership of your organization was.
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1 Does the Idaho Irrigation Pumpers Association
2 include all participants in the Idaho irrigation load control
3 program?
4 A.I don't think so.
5 Q.Okay. Your membership is open to all irrigators
6 or just those that --
7 A. Our membership is open to all irrigators, that is
8 correct. We send out a newsletter two times a year and ask for
9 donations or dues. Many of the irrigators pay; some do not. I
10 don't know which ones do and which ones do not. A vast
11 maj ori ty of the irrigators do pay into the organization, yes.
12 Q.Thank you. That's the only question.
13 COMMISSIONER SMITH: Mr. Budge, do you have
14 questions?
15 MR. BUDGE: No questions.
16 COMMISSIONER SMITH: Mr. Otto, do you have
17 questions?
18 MR. OTTO: I do have just one or two questions.
19
CROSS-EXAMINATION
22 BY MR. OTTO:
23 Q.On page 7 of your surrebuttal and lines 1 through
24 I guess 4, you suggest that the Commission should bifurcate
25 this consideration of removing the irrigation load control
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1 program. Did you -- were you addressing just the load control
2 program or some other suggestions that were made by the Rocky
3 Mountain Power, Ms. Hunter's testimony specifically?
4 A.Just the load control program.
5 Q.So that wouldn't apply to the agricultural energy
6 services program?
7 A.Not necessarily, no. That is correct.
8 Q.And then I want to turn to page 9, and that's
9 lines -- essentially, the whole answer there, but specifically
10 lines 9 through 11, and you say the end balance is a function
11 of getting more bang for the buck.
12 My understanding of the energy efficient --
13 agricul tural energy efficiency services is it was one of the
14 lower cost-effective programs. Are you aware of that? Do you
15 know that?
16 A.I do not know that.
17 I know what the program is: The Company will pay
18 us money if we turn in receipts to renozzle pivots, to put
19 gaskets in in hand lines or aluminum pipe, those types of
20 things to help with the efficiency of irrigation, which should,
21 in return, lower the energy requirement that we have to
22 irrigate the ground enough to grow a reasonable crop. The
23 effect of the program I think is very difficult to measure.
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25
Q.All right, fair enough. You're not a cost
effecti ve expert and I wouldn't expect you to be. I don't know
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1 who is. But I do -- you are a participant and a grower.
2 Does that program save you money on water, as
3 opposed to including energy?
4 A.It saves us on energy costs. As far as water
5 savings, I don't know of any. We receive a rebate on our
6 energy costs, our payments to Rocky Mountain Power.
7 Q.All right, thank you.
8 MR. OTTO: That's all I have.
9 COMMISSIONER SMITH: Mr. Hickey or
10 Mr. Solander.
11 MR. SOLANDER: No questions, thank you.
12 COMMISSIONER SMITH: Okay. Do we have questions
13 from the Commissioners?
14 COMMISSIONER REDFORD: No.
15 COMMISSIONER KEMPTON: No.
16 COMMISSIONER SMITH: Mr. Mickelsen, thank you for
17 being here.
18 Mr. Olsen, did you have redirect?
MR. OLSEN: No redirect, your Honor.
COMMISSIONER SMITH: Thanks.
MR. OLSEN: Ms. Madam Chair.
COMMISSIONER SMITH: So--
MR. OLSEN: We'd like now -- I think we could
24 release Mr. Mickelsen.
25 COMMISSIONER SMITH: He's free to return to
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1 Idaho Falls and shovel his driveway.
2 THE WITNESS: Thank you.
3 COMMISSIONER SMITH: Thank you.
4 (The witness left the stand.)
5 MR. OLSEN: The Idaho Irrigation Pumpers would
6 like to call to the stand Mr. Anthony Yankel.
7
8 ANTHONY YANKEL,
9 produced as a witness at the instance of Idaho Irrigation
10 Pumpers Association, being first duly sworn, was examined and
11 testified as follows:
12
13 DIRECT EXAMINATION
14
15 BY MR. OLSEN:
16 Q.Good afternoon, Mr. Yankel. Could you please
17 state your name and spell your last name for the record?
18 A.Anthony Yankel: Y-A-N-K-E-L.
Q.And what is your business address, Mr. Yankel?
A.29814 Lake Road, Bay Village, Ohio, 44140.
Q.Mr. Yankel, did you prefile direct testimony in
22 this case dated October 14th of this year?
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A.Yes, I did.
Q.Okay. Do you have any corrections to that
testimony as filed?
1794
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
YANKEL (Di)lIP
.
.
.
20
1 A.Yes, I do.
2 Q.Could you point those out for the Commission,
3 please?
4 A.Page 3, line 13, at the end of the line, the
5 number "13 percent" should be "23 percent."
6 I also had sent out or Mr. Olsen had sent out a
7 revised page 24 that was sent out soon after the testimony was
8 filed. I don't know
9 COMMISSIONER SMITH: We got it.
10 THE WITNESS: Okay, good enough then. And that
11 had several numbers that were changed as well.
12 Q.BY MR. OLSEN: Okay, with that correction, if I
13 were to ask you the questions contained in your prefiled
14 testimony today, would your answers be the same?
15 A.Yes, they would.
16 MR. OLSEN: With that, Madam Chair, I'd tender
17 I i d move that the testimony of Mr. Yankel be spread upon the
18 record, and that Exhibits 301, 302, and 303 be identified for
19 the record.
COMMISSIONER SMITH: If there is no obj ection, it
21 is so ordered.
22 (The following prefiled direct testimony
23 of Mr. Yankel is spread upon the record.)
24
25
1795
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
YANKEL (Di)
lIP
.
.
.
1 Q.PLEASE STATE YOUR NAM, ADDRESS, AND EMPLOYMENT.
2
3 A.I am Anthony J. YaneL. I am President of Yanke i and Associates, Inc. My
4 address is 29814 Lake Road, Bay Vilage, Ohio, 44140.
5
6 WOULD YOU BRIEFLY DESCRIE YOUR EDUCATIONALQ.
7 BACKGROUND AND PROFESSIONAL EXPERIENCE?
8
9 I received a Bachelor of Science Degree in Electrical Engineering from CarnegieA.
10 Institute of Technology in 1969 and a Master of Science Degree in Chemical Engineering from
11 the University of Idaho in 1972. From 1969 through 1972, I was employed by the Air
12 Correction Division of Universal Oil Products as a product design engineer. My chief
13 responsibilties were in the areas of design, start-up, and repair of new and existing product lines
14 for coal-fired power plants. From 1973 through 1977, I was employed by the Bureau of Air
15 Quality for the Idaho Department of Health & Welfare, Division of Environment. As Chief
16 Engineer of the Bureau, my responsibilties covered a wide range of investigative functions.
17 From 1978 through June 1979, I was employed as the Director of the Idaho Electrical Consumers
18 Offce. In that capacity, I was responsible for all organizational and technical aspects of
19 advocating a variety of positions before various governental bodies that represented the
20 interests of the consumers in the State ofIdaho. From July 1979 through October 1980, I was a
21 parner in the firm of Yanke i, Eddy, and Associates. Since that time, I have been in business for
22 myself. I am a registered Professional Engineer in the states of Ohio and Idaho. I have
23 presented testimony before the Federal Energy Regulatory Commission (FERC), as well as the
1796 Yankel, DI-l
Irrigators
. 1 State Public Utility Commissions of Idaho, Montana, Ohio, Pennsylvania, Utah, and West
2 Virginia.
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23.
3
Q. ON WHOSE BEHAF AR YOU TESTIFYING?
A. I am testifying on behalf of the Idaho Irrigation Pumpers Association (IIPA).
Q. WHAT is THE PUROSE OF YOUR TESTIMONY IN THIS PROCEEDING?
A. My testimony wil address the Company's jurisdictional revenue requirement as it
is impacted by the level of test year weather normalized Irigation sales used by the Company,
the inappropriate level of losses being assigned to Idaho, and the treatment of the benefits and
costs of the Irrgation Load Control Program as they impact Idaho. I also address the treatment
of the Load Growth Adjustment Rate in PacifiCorp's ECAM proceedings, when the actual usage
falls below that projected in the Company's GRID model in general rate cases, and the data used
by the Company to calculate the cost of service for the Irrigation customers.
Q. PLEASE SUMMZE YOUR TESTIMONY.
A. Aside from this introduction, my testimony is divided into five sections.
* The first section deals with the level of Irrigation sales that the Company used to
develop its 2010 forecasted test year revenues and revenue requirement. Although
PacifiCorp recognizes that the 2009 Irrigation sales were quite low because of "an
1797 Yankel, DI-2
Irrigators
.
.
.
1 unusually wet spring", its weather normalization process does not address precipitation.
2 Using PacifiCorp's weather normalized Irigation sales for the 11 years prior to 2009, it
3 can be projected that in 2010 that the weather normalized Irrigation sales should have
4 been 545,000 MWH (17.7%) higher than used in the Company's fiing. The test year
5 Irrigation revenue as well as the Idaho Jurisdictional revenue would be increased $7
6 milion if a realistic weather normalized Irigation sales figue would have been used.
7 * The second section deals with the assignent of cost responsibilty to the Idaho
8 jurisdiction based upon the energy allocation factor used for Idaho. This energy factor
9 is based upon the same forecast sales data as used to develop the Idaho revenue, but a
10 different (greater) set oflosses is applied to these sales than is calculated in the
11 Company's loss study for Idaho. PacifiCorp uses something referred to as "Border
12 Load" to calculate Idaho's losses for jurisdictional allocation purposes. This Border
13 Load method effectively measures all losses that occur in Idaho. However, only 13%
14 of all of the electricity that enters the Idaho jurisdiction is consumed in Idaho, with the
15 rest of it simply passing through to non-Idaho customers. Idaho customers should not
16 be charged for losses associated with energy that is simply passing through Idaho to
17 serve others.
18 * The third section deals with the benefit that Idaho receives and the costs that it incurs as
19 a result of the Irigation Load Control Program. I generally conclude that although the
20 Program is a major benefit to the system (provides a great savings for all system
21 customers), the Idaho customers are paying significantly more than the benefit that they
22 are receiving. I recommend that in the long term (by the next rate case) that this
23 program be treated more as a system benefit where the curtilments are "sold" to the
1798
Yankel, DI-3
Irigators
.
.
.
1 system at their true value. For purposes ofthis case, a more realistic reduction/credit
2 should be given to Idaho in the Company's jurisdictional allocation model that reflects
3 the actual curtilment that was available during the test year as opposed to the limited
4 (lower) amount that was used in the Company's fiing. Use of actual 2010 curtilment
5 levels as opposed to levels lower that what were even available in 2009 results in a
6 reduction of the revenue requirement by 2.5 milion.
7 * The fourth section deals with the Load Growth Adjustment Rate ("LGAR") that is a
8 part of the Company's ECAM proceeding, but the rate is set in this, a general rate case.
9 The LGAR was originally established to keep the Company from double recovery of
10 growth related power supply costs. An unforeseen problem has arisen with respect to
11 the fact that it was never conceived that load would be decreasing as opposed to
12 increasing between rate cases. Under such circumstances, the LGAR acts as a
13 decoupling mechanism and actually increases rates when load is lost. My testimony
14 recommends that the Commission specify that the LGAR is not a symmetrical
15 adjustment and that it only is used when there is growth between rate cases.
16 * The fifth and last section of my testimony deals with the development of the class cost
17 of service study. I point out that the Company's cost of service study (as was the
18 jurisdictional model) does not have an adequate level of test year sales to the Irrigators.
19 I also point out that the class cost of service study does not reflect the peak load
20 reduction capabilty that is available, or even as used in the jurisdictional study. I do
21 not present specific adjustments to this study, but simply recommend adoption of the
22 Company's proposed increase to the Irrgators that is set at 70% of the jurisdictional
23 average increase.
24
1799 Yankel, DI-4
Irrigators
.
.
.
1 Irrigation Sales Level
2 Q.is THE LEVEL OF TEST YEAR IRIGATION SALES USED BY TH
3 COMPANY APPROPRITE?
4
5 A.No. Although the weather normalized value of 545,290 MWH for Idaho
6 Irrigation sales i is claimed to be based upon test year number of customers, combined with sales
7 per customer, and developed from regression analysis techniques using time trend variables;2 a
8 simple review of the historic data reveals that this level of usage is significantly below what
9 would be considered a normalized test year value for the Irrigation customers. The actual sales
10 levels to the Irrgation customers over the last 10 years were provided in the Company's
11 Response to lIP A Request 87 and are graphically presented in Figure 1 below. Except for the
12 2005 and 2009 actual sales levels, the other recent annual sales to the Irigation customers have
13 been well in excess of the normalized value proposed in this case.
800,000
700,000
600,000
5:500,000Š
!400,000
300,000
200,000
100,000
14
Figure i
'Actuallrrigation Sales
.,.
:.....v.~
I
1998 2002 2006 2010200020042008
i At sales level which for the Irrigators is considered to be at secondar distribution leveL.
Yankel, DI-518 0 0 Irrigators
.
.
.
1 Q.WHY WERE IRGATION SALES SO LOW IN 2009?
2
3 A.The Company gave the following explanation in Mr. Eelkema's testimony at page
4 3, line 3:
5 Idaho's 2009 sales were unusual for at least two reasons. First, 2009 industrial
6 sales were abnormally low. Second, an unusually wet spring resulted in a
7 decrease in irrigation sales. The usage from these two customer classes decreased
8 approximately 20 to 21 percent from 2007 and 2008 levels, reducing Idaho's 2009
9 total sales approximately 12 to 13 percent from 2007 and 2008 levels. (Emphasis
10 added)
11 I fully concur with this explanation.
12
13 Q.is IT APPROPRIATE TO SIMLY RELY UPON ACTUAL HISTORICAL
14 SALES TO JUGE THE VALIDITY OF THE COMPANY'S WEATHER NORMIZED
15 VALUES?
20
21
22
23
24
16
17 A.Looking at actual data is a good starting point, but weather normalized data
18 should be reviewed as welL. The Company provided its historic weather normalized sales per
19 customer data for the previous 12 years in its response to lIP A Request 22e. This historic
weather normalized sales per customer data was combined with the number of Irrigation
customers taken from the Company's Response to IIPA Request 84 and is graphically displayed
on Figure 2 below. There are two things to note: first, on a normalized basis there has been a
gradual, but steady increase in Irrigation sales since 1998; and second, the weather normalized
sales for 2009 is significantly below the trendline of all of the weather normalized data-it does
25 not fit. Remember-this data is on a "weather normalized" basis that should have removed all
2 See generally Eelkema's direct testimony page 5, line 11 through page 6 line 9.
1801
Yankel, DI-6
Irrigators
. 1 impacts of different weather in different years. The Company's weather normalized 2009
2 Irrigation sales are clearly an outlier.
700000
Figure 2
Normalized Irrigation Sales
500000 ..
.-+
..+..600000 "...
..
:: 400000
S
:i 300000
y = 9,480.46x" 18,436,417
R2 = 0.35
200000
100000
.3
4
o
1996
I I
1998 2000 2002 2004 2006 2008 2010
5 Q.WHY DOESN'T THE COMPANY'S WEATHER NORMLIZED DATA FOR
6 2009 FIT THE PATTERN SHOWN IN TH TRENDLIN IN FIGUR 2?
7
8 A.The reason that the weather normalized 2009 Irigation sales data is so low and
9 not fitting the trendline can be simply traced back to Mr. Eelkema's statement that 2009
10 Irrigation sales were so low because of an unusually wet spring. In spite ofthis recognition, the
11 Company does not weather normalize Irrigation sales data for precipitation3 thus, the unusually
12 low sales data in 2009 that was due to an unusually wet spring, was in fact not normalized for the
13 weather anomaly that occurred. In spite of the Company's testimony that the wet spring caused
.3 See Response to lI A Request 22-f.
1802 Yanel, D 1-7
Irrigators
. 1 low Irrigation sales in 2009, its weather normalization procedures did nothing to tae this
2 situation into account.
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
.
3
4 DOES IDAHO POWER WEATHER NORMLIZE ITS IRIGATION SALESQ.
5 DATA FOR PRECIPITATION?
6
A. Yes. In support of its weather normalization adjustments used in Case No. IPC-
E-03-13, Idaho Power supplied to the Commission Staff (in response to its Request No.3) its
supporting documentation for weather normalization. With respect to the regression models that
Idaho Power ran for Irrigation sales, the following description was provided with respect to the
Irrigation models for each of the Company's operating centers:
The weather variables utilzed by the system irrigation weather adjustment
model are constructed as weighted averages of degree day variables from four
service area weather stations: Boise, Twin Falls, Pocatello, and Ontario. That is,
the growing degree day variable (cooling degree days Base 50) is an average of
growing degree days from the four weather stations, each weighted by the share
of total system irrgation pumping horsepower connected in the division
associated with that weather station. The precipitation variable was constructed
and weighted in the same manner. A second precipitation variable was used to
measure the impact of pre-growing season precipitation on the early months of the
growing season (May and June). This variable is zero for all months except May
and June of each year where it is the total of the weighted precipitation for the two
previous months. . . .
Thus, unlike PacifiCorp, Idaho Power's Irigation weather normalization model not only
recognized the impact of precipitation on Irrigation sales, but also recognizes a second
precipitation variable that deals with the early growing season-precisely under the conditions
where PacifiCorp noted abnormal precipitation and abnormally low sales. For this reason, even
though PacifiCorp's weather normalized Irgation sales for 2009-no adjustment was made to
29 normalize for the "unusually wet spring".
1803 Yanke!, DI-8
Irrigators
. 1
2 Q.SHOULD PACIFICORP'S 2009 IRGATION SALES BE INCLUDED
3 AND/OR USED IN THE GRAH AND/OR ANALYSIS ABOVE?
4"
5 A.No. As noted above, a review of the graph in Figure 2 reveals 2009 to be an
6 outlier (even on a weather normalized basis) and the fact that PacifiCorp underwent an
7 "unusually wet spring" without making normalization adjustments for precipitation indicates that
8 this "normalized" value is wrong or simply meaningless.
9
10 Q.WHAT WOULD THIS GRAH LOOK LIKE IF THE MEANINGLESS 2009
11 DATA WERE IGNORED?
12.13 A.The graph in Figure 3 below shows that the annual, normalized sales data is much
14 more uniform with the 2009 data removed.
Fîgure3
Normalized Irr.Sales (no 2009 data)
700,000
600,000
500,000
:i 400,000
s;~300,000
200,000
100,000
~~..~-:....
y= 14,427.40¡(~28,336,907
R2= 0.65
i T I
15
1996 1998 2000 2002 2004 2006 2008 2010.
1804 Yankel, DI-9
Irigators
. 1 By removing one piece of obviously bad "normalized" data, the R-Square for this trendline is
2 almost double that of the previous graph in Figure 2.
3
4 Q.THE NORMLIZED IRGATIONS SALES DATA IN FIGURS 2 AND 3
5 ARE INCREASING. is THIS CONSISTENT WITH EXPECTATIONS?
6
7 A.Yes. First, it must be remembered that this data is PacifiCorp's own data and it
8 reflects only Southeastern Idaho. Second, the data is based upon actual sales data that has been
9 normalized to remove some of the obvious weather anomalies-the data is not based upon
10 assumptions regarding anticipated changes in independent variables. Third, the increased sales
11 data generally fits with the increase number of Irrigation customers that this region has
.12 experienced.
13
14 Q.HOW MANY NEW IRGA TION CUSTOMERS HAS PAClFICORP ADDED
15 IN ITS IDAHO SERVICE TERRTORY OVER THE LAST 10 YEARS?
16
17 A.During the last 10 years there has been an increase in the number of Irrigation
18 customers in PacifiCorp's Idaho service territory of approximately 350 customers or 8%.4
19 Figure 4 below depicts this growth over the last 10 years:
.4 Generally see the Response to IIA "Request 84.
1805
Yankel, DI-l 0
Irrigators
.
1
2
3
4.5
6
7
.
Figure 4
Irrigation Customers
5000 .. Â
4500 .. .. .~",,, y
.. -..y:; O.0898x + 1159.3
R2:: 0.9698
4000
3500
3000
1998 2009 2012200120042006
In spite of this well established relationship of the ever increasing average number of Irigation
customers over the last 10 years, the Company's test year average number of Irrigation
customers is 11 customers less than what was realized in 2009.
Q. WHT DOES THE ABOVE COMPANY WEATHER NORMLIZED
IRRIGATION SALES DATA PREDICT WITH RESPECT TO THE 2009 AND TEST YEAR
8 2010 IRIGATION SALES LOAD?
9
10 Based upon the trend line through the Company's weather normalized irrigationA.
11 sales data in Figure 3, the normalized Irigation sales in 2009 would have been 647,440 MWH
compared to the actual Irrigation sales of500,255 MWH.5 The test year 2010 weather12
13 normalized Irgation sales would be 662,167 MWH compared to the inappropriate level of
14 545,290 MWH used in the filing. Essentially, the Company used a value for Irrigation sales that
5 See response to IIPA Request 18.
1806 Yanel, DI-ll
Irrigators
. 1 was 17.7%6 less than what is predicted-similar to the general conclusion discussed on page 3 of
2 Mr. Eelkema's testimony:
3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
.
... usage from these two customer classes decreased approximately 20 to 21
percent from 2007 and 2008 levels
Q. AR THRE OTHER INSTANCES WHRE TH COMPANY'S TEST YEAR
FORECAST SALES PRODUCE TOO LOW OF A RESULT?
A. I have only briefly looked at the Company's forecast test year sales for the
Residential class. The response to Staff Request 291 listed the actual (weather normalized) sales
for the Residential customers for the first six months of the test year as well as the forecasted
(weather normalized) sales as welL. As can be seen on Exhibit 301, the forecasted sales for all
Residential customers for the first six months of the test year was 365,652 MWH, while the
actual sales (after weather normalization) was 388,066 MWH or 6.13% higher. Because both
figures are based upon "normal" weather, this deviation of6.13% (since the case was put
together) is huge. The fact that both the Company's Irrigation model and its Residential model
are under-predicting sales by such large amounts raises concerns regarding the other sales data
18 used by the Company in this case.
19 Furthermore, even the number of forecasted Residential customers in the Company's test
20 year starts off below the number of Residential customers that were on the system at the end of
21 2009. Exhibit 3027 lists the number of Residential customers for each of the 36 months for 2007
22 through 2009. Out.ofthe 36 months listed on that exhibit, the number of Residential customers
23 increased in 32 of the 36 months. The average decrease that occurred during those other four
6545,290/662,167 = 0.826
1807 Yankel, DI-12
Irrigators
. 1 months was only 48 customers per month. There were 57,156 Residential customers in the
2 jurisdiction on December 2009, one month before the test year. By contrast, the number of
3 Residential customers forecast for January 20108 was 56,725 or 431 less than the actual number
4 of customers the month before. Once again, the Company's forecast of biling units, and thus
5 revenue, is coming up short.
6
7 Q.WHAT ADJUSTMNTS ARE YOU PROPOSING TO BRING THE
8 COMPANY'S TEST YEAR SALES LEVELS MORE IN LINE WITH "NORML" LEVELS?
9
10 A.Although the Residential sales data is clearly understated, I am only
11 recommending an adjustment to the Irrgation sales data. I am not making an adjustment to the
.12 Residential sales because I have not reviewed it to the extent I have the Irrgation data-not
13 because I do not believe that an adjustment is necessary. I recommend that the Irigation sales
14 data be increased by 116,877 MWH-the difference between what the trendline based upon the
15 Company's own weather normalized values over 11 years and the value used by the Company in
16 the development of its test year sales.
17 Although I am proposing to increase Irigation sales by 116,877 MWH, I am not
18 proposing an increase in the biling kW, which is far more stable from year to year (in spite of
19 weather variation) and the Company's forecasted values generally look appropriate. By way of
20 comparison, recent annual biling kW are listed below as well as that used in the Company's test
21 year:
9
.7 Based upon the Company's response to IPUC 20.
8 See the Company's response to IPUC 292.
9 See Response to lIP A Request 26.
1808 Yankel, DI-13
Irrigators
.
.
.
1 Table 1
2
Billng kW
1,299,501
1,365,546
1,354,124
1,325,036
1,324,449
1,346,186
3
2005
2006
2007
2008
2009
test year
4
5
6 WHA T RATE SHOULD BE ASSIGNED TO THESE INCREASEDQ.
7 IRGATION SALES?
8
9 Although Schedule 10 for Irrigation contains three different rate blocks during theA.
10 Irrigation season and a separate rate block during the off-season, historical data demonstrates that
11 the average "energy related" revenue collected each month is quite close (plus or minus) to the
12 off-season energy rate. For that reason, I wil simply use the off-season energy rate to establish
13 the additional revenue that would be collected ifthe test year Irrigation sales were more properly
14 established. I recommend that the 116,877 additional MWH of Irrigation sales be multiplied by
15 6.0315 cents/kWh in order to produce additional revenue of $7,049,436. The Irrigation test year
16 revenue should thus be set at $46,895,173.
17
18 Q.HOW DOES YOUR PROPOSED TEST YEAR IRIGATION REVENUE
19 COMPAR WITH THAT COLLECTED HISTORICALLY?
20
21 The total Irrigation revenue of $46,895, 173 compares quite favorably with thatA.
22 collected over the last several years--nce the impact of recent rate increases is taken into
23 account in order to put the historical revenues on the same basis as today's rates. The table
1809 Yankel, DI-14
Irrigators
. 1 below lists the historic revenues, the level of increases to the Irigation customers, and the
2 effective revenue for each year at today's rates:
Table 2
4.89%
1.73%
Equivalent
Revenue
$40,329,167
$48,223,804
$43,479,712
$37,330,030
2006
2007
2008
2009
Actual
$37,795,154
$45,193,746
$42,740,305
$37,330,030
Rate
Increases
1.70%
PacifiCorp $39,845,737
$46,895,173Proposed
3
4 It should be remembered that the above revenue figures are based upon actual usage and not
5 weather normalized usage. The 2009 Irigation season saw the lowest Irrigation sales for the
6 most recent 12 years reviewed and thus, the revenues for that year would be expected to be
. 7 unusually low. Likewise, normalized 2008 sales were slightly below the trendline and 2007
8 sales were above.
9
10 Q.WHAT WOULD HAVE THE ADJUSTMENT BEEN TO THE IRRGATION
11 SALES IF ALL 12 MONTHS OF HISTORICAL DATA WERE USED, INCLUDING THE
12 IMPROPERLY NORMALIZED 2009 DATA?
13
14
15
16
17
18.
A. Although the 2009 data is clearly too low and significantly under estimates
Irrigation sales, using the trendline from Figure 2 above results in a predicted 2010 usage of
619,308 MWH which is 70,018 MWH above the value used by the Company as test year
Irrigation sales. Valuing these additional sales at 6.0315 cents per kWh, the additional revenue
that should be assigned to the jurisdiction is $4,223,136. Even using this inappropriate data that
1810 Yankel, DI-15
Irigators
. 1 does not take into account the "unusually wet spring" of2009, results in the need for a
2 significant adjustment to the Company's filing.
.
17
18
19
20
21
22
23.
3
4 BECAUSE OF THE PROBLEMS WITH THE COMPANY'S FORECAST,Q.
5 AND BECAUSE WE AR NEARG THE END OF THE YEAR, WOULD IT BE MORE
6 APPROPRITE IN THIS CASE TO SIMPLY SUBSTITUTE ACTUAL 2010 IRIGATION
7 SALES AND REVENUES?
8
9 No. The Company cannot pick and choose where it wishes to normalize andA.
10 where it wishes to use actual data. Furthermore, it is my understanding that the 2010 Irrigation
11 season may have been similar to 2009-an unusually wet spring. Even ifthe Company's entire
12 fiing had been on an actual (as opposed to a normalized) basis, standard ratemaking treatment
13 would dictate that such abnormal weather/sales would need to be normalized. The point is that
14 the data needs to be normalized, but the Company's proposed normalized Irrigation sales are
15 clearly inappropriately too low.
16
Q. HOW SHOULD TH PROPER NORMLIZATION OF THE IRRGATION
LOAD BE TREATED IN THE COMPANY'S OVERALL REVENUE REQUIRMENT?
A. Both the increased Irrigation sales and revenue need to be incorporated into the
Company's jurisdictional allocation models (JAM and RA). The increased test year Irrigation
revenue wil decrease the revenue requirement in this case, but that wil be somewhat offset by
the allocation of increased costs to Idaho because of the increased load. However, before I
1811 Yankel, DI-16
Irrigators
. 1 calculate the impact of these adjustments, I need to address the overall amount of energy that is
2 assigned to Idaho in the jurisdictional allocation modeL.
3
.
.
1812 Yankel, DI-17
Irigators
.
6
7
8
9
10
11.12
13
14
15
16
.
1 Jurisdictional Sales vs. Jurisdictional Allocations
2 Q.DO THE COMPANY'S JUSDICTIONAL SALES AND THS REVENU
3 PROPERLY REFLECT THE ENERGY RELATED COSTS THAT ARE ALLOCATED TO
4 IDAHO ON A JUSDICTIONAL BASIS?
5
A. No. There is a significant difference between the amount of sales, and
thus revenue, attibuted to the Idaho jurisdiction and the amount of energylkWh used
to allocate costs to the Idaho jurisdiction. Specifically, there is 2.66% more
energylkWh responsibilty attributed to Idaho in the jurisdictional allocation model
than what is attributed to Idaho for the calculation of jurisdictional revenues.10 The
net effect is that more costs are being allocated to Idaho than are required to serve the
Idaho load-Idaho is being asked to pay the cost of serving others.
Q. GENERALY SPEAKING, WHAT IS THE CAUSE OF THIS DIFFERENCE
IN TH AMOUNT OF SALES ASSOCIATED WITH THE REVENUE ATTRIUTED TO
IDAHO AND THE AMOUNT OF ENERGY USAGE ATTRIBUTED TO JURSDICTIONAL
17 EXPENSES?
18
lO Exhibit 2, Tab 1, page 1.3 lists the total Idaho normalized General Business test year revenue at
$202,733,163. Exhibit 50 lists the present Idaho revenue at $202,733,000 associated with 3,325,872
MW. Exhibit 49, Tab 5, page 14, line 10, lists test year sales (~sale level) as 3,325,873 MW which is
associated with 3,557,594 MW on line 14 ~ Input. By comparison, Exhibit 2, Tab 10, page 10.14 uses a
load of3,652,385 MW to allocate costs to Idaho or 2.66% more usage (3,652,385 /3,557,594) =
1.0266446) than the revenue that Idaho is given credit for.
1813 Yankel, DI-18
Irrigators
.
.
.
1 The difference results from the use of two different methods of applying losses toA.
2 the jurisdiction. 11 First, the Company has periodically conducted loss studies for each
3 jurisdiction. The values from these loss studies are used in the Company's cost of service study
4 and for other puroses. Exhibit 303 contains six pages-the summary page ofthe loss study for
5 each of the states in which the Company operates.
12 Near the bottom right of each page are
6 listed the "cum(m)ulative sales expansion factors" (loss factors) for each voltage leveL. Under
7 the heading of "Energy" and under the column labeled "e" there is listed cumulative energy (as
8 opposed to demand) losses at each voltage leveL. For example, page 1 of Exhibit 303 lists the
9 following losses by voltage level for Idaho:
Table 3
Expansion Percent
Factors Losses
Trans.1.03605 3.605%
Primary 1.06475 6.475%
Secondary 1.10148 10.148%
10
11 What this data means is that a Transmission customer in Idaho is assigned a percentage loss of
12 3.605% or the Company has to generate 1.03605 MWH for each MWH that the customer
13 consumes. Likewise, the Company must generate 1.10 148 MWH for each MWH that is
14 consumed by a Secondary customer.
15 Table 4 lists the various loss factors that the Company has calculated for each of the
16 states in which it operates:
17
11 Generally see Responses to IIA Requests 130 and 133.
12 Loss studies provided in Response to lIP A Request 45.
1814 Yankel, DI-19
Irrigators
. 1
2
3
4
5
6
7
8.9
10
11
12
13
14
15
16
17
.
Table 4
Idaho Utah Oregon Wash.Wyoming Calif.
Trans.3.605%3.605%3.605%3.605%3.605%3.605%
Primary 6.475%5.763%5.771%6.039%5.594%5.946%
Secondary 10.148%8.757%9.180%8.822%8.136%9.848%
There are two things of interest regarding Table 4: 1) all Transmission losses are considered to
be equal (transmission, like generation, is a system function and transmission losses should be
equally shared by all jurisdictions); and 2) Idaho has the distinction of having the highest
percentage losses on the distribution system (primary and secondary) of any of the states.
Q. WHAT is THE SECOND METHOD OF ASSIGNING LOSSES TO THE
VARIOUS JUISDICTIONS THAT RESULTS IN AN EXCESSIVE AMOUNT OF
RESPONSIBILITY BEING ASSIGNED TO IDAHO?
A. The assignment of jurisdictional cost responsibility starts with the same test year
sales figures as used to establish the jurisdictional test year revenue, but the losses assigned to
Idaho are based on a 5-year relationship between what is referenced as the "Border Load" to the
jurisdictional sales. The Border Load is simply calculated each hour by measuring the amount of
energy coming into the state, plus the amount generated in the state, less the amount leaving the
state. The losses are then calculated by comparing these Border Loads with the monthly or
18 annual sales that took place in the state.
19 This has the appearance of being quite straight forward and even highly accurate. A
20 review of the monthly losses calculated for each státe demonstrates the fallacy of that perception.
1815 Yankel, DI-20
Irrigators
. 1 Simply looking at the Idaho monthly losses in Table 5 below, there are four months (March,
2 June, August, and November) when the losses were negative and three months (July, September,
3 and October) with losses greater than 20%.
2009
January
February
March
April
May
June
July
August
September
October
November
December.Simple Average
4
Table 5
Utah
6.5%
7.7%
3.6%
8.7%
6.7%
9.5%
1.3%
8.7%
1.9%
7.4%
15.2%
2.5%
Idaho
1.3%
13.3%
-0.4%
8.2%
11.2%
-7.8%
43.1%
-10.9%
27.7%
22.1%
-0.3%
5.7%
6.64%9.41%
5 Q.IS TH VARIATION IN LOSSES SHOWN IN TABLE 5 BECAUSE THE
6 DATA is PRESENTED ON A MONTHLY BASIS THAT COULD REFLECT LARGE
7 CHANGES IN SOME LOADS FROM MONTH TO MONTH?
8
9 A.No. First, ifthat were the case, Utah's and Idaho's percentages would generally
i 0 track each other-they do not. Second, IIP A Request 4 sought information regarding hourly
11 load data by customer class to compare with the Border Load data. By assigning the loss factors
12 derived from the Company's loss studies to each class' hourly loads; it is possible to review how
13 the Border Load fluctuates with the actual hourly sales loads. By way of example, the following
14 hourly data from Friday September 4, 2009 demonstrates how variable the relationship between.15 the hourly Idaho loads and the Idaho Border Loads can be:
1816 Yankel, DI-21
Irrigators
.1
Table 6
Idaho Border
Hour Monsanto NuWest Distribution Sales load Delta Percentage
16 22,716 12,241 281,823 316,780 415,713 98,934 31%
17 96,986 12,260 291,616 400,862 356,268 -44,594 -11%
18 104,001 12,171 281,756 397,928 422,909 24,980 6%
19 102,665 12,173 284,224 399,062 428,988 29,926 7%
2
3
4
5
6
7.8
9
10
11
12
13
14
15
16
17
.
Although the variation from month to month or hour to hour in the losses calculated on the basis
of Border Load is an obvious concern, the main concern at this point is the inappropriately high
level of losses that is being assigned to Idaho in this case.
Q. UPON WHAT BASIS CAN IT BE DETERMINED THAT USING BORDER
LOAD DATA ASSIGNS AN INAPPROPRITE AMOUNT OF LOSSES TO IDAHO?
A. There are a couple of different ways to demonstrate this. As seen from the Table
4 above, Idaho has been calculated to have the highest percentage losses of any state with respect
to primary and secondary distribution. (Appropriately, all states have the same transmission loss
factor as transmission is a system function.) However, this does not mean that Idaho should have
the highest overall percentage of losses. By comparison to the other states, Idaho has a very high
percentage (45%) of its sales at the Transmission level where the percentage of loss is much
lower. Based upon the Company's loss study, combined with the test year loads, Idaho's losses
should only be 6.98%.13 However, the Company's use of its Border Load data assigns 9.82%
13 Company Exhibit 49, tab 5, page 14 lists total sales (at sales level) at 3,325,873 MW and at input level
at 3,557,873 MW for an overall level of losses of 6.9756%.
1817 Yankel, DI-22
Irrigators
. 1 losses to Idaho.
14 By comparison, the Company's loss study indicates that if all ofIdaho's load
2 (including Monsanto) were at the secondary level, the overall losses should only be 10.148%--
7
8
9
10
11.12
13
14
15
16
17
18
19
.
3 almost the same as what is calculated by the Border Load.
4
5 Q.HOW ELSE CAN IT BE SHOWN HOW INAPPROPRIATE THE LOSSES
6 ASSIGNED TO IDAHO AR?
A. From Table 5 it can be calculated that (relatively speaking) the losses assigned to
Idaho in 2009 under the Border Load method would be approximately 42% more than those
assigned to Utah.
15 As pointed out above, based upon the Company's loss study and the actual
test year usage in Idaho, the losses for Idaho would be 6.98%. Doing a similar analysis on the
test year usage data fied in the most recent general rate case in Utah, it can be calculated that the
overall Utah losses would be 8.08%.16 Even though the Distribution losses in Utah are
calculated to be at a lower percentage than those in Idaho, Utah has only 8% of its sales at the
Transmission level where losses are the least, while Idaho sales are 45% at the Transmission
leveL. Thus, when combining the sales in Idaho with recognition of the voltage level at which
those sales take place, it becomes apparent that the overall losses attributed to Idaho should be
less than those attributed to Utah. However, the Border Load data suggests that the percentage
of losses in Idaho should be 42% greater than that found in Utah. The Border Loads are clearly
20 measuring something inappropriate.
14 Compared to the sales level of3,325,873 MW, Company Exhibit 2, page 10.14 assigns 3,652,385
MW at input to Idaho for an overall level oflosses of 9.8173%.159.4116% / 6.6399% = 1.417
16 In Utah Docket 09-035-23 on Exhibit (CCP-3), Tab 5, page 16 the total test year sales level at input is
listed as 23,161,564 MW and on page 17 the total test year sales at sales level is listed at 21,430,490
MWH.
1818 Yankel, DI-23
Irrigators
.
.
.
1
=~i;
~
1: rn
2 Q.
~
fZ;,:.i':', c:
WHAT is WRONG WITH THE BORDER LOADS THAEJS cäJSING AN
0"./,."
3 INAPPROPRIATE AMOUNT OF COSTS TO BE ALLOCATED TO IDAHO?
4
5 A.Although the Border Load calculation has some degree of accuracy, the fact is
6 that it is an inappropriate measure of the losses that should be assigned to Idaho. The Border
7 Loads determine all losses that occur in Idaho, but all losses that occur should not necessarily be
8 assigned to Idaho. Specifically, any losses that occur on the Transmission system are system
9 losses and not Idaho losses in that they wil have little, if anything, to do with Idaho load.
10 For example, in 2009 there were 12,715,000 MWH that entered the Idaho jurisdiction and
11 9,495,000 MWH that left Gust went though) the jursdiction.) The difference (Border Load) of
12 3,220,000 either went to Idaho sales customers or losses. Idaho sales were only 2,950,000 MWH
13 which is only 23% of what entered Idaho. Based upon the Border Load calculation, ths leaves
14 270,000 MWH for losses that occured in Idaho, but not necessarly for Idaho. Those losses not
15 only related to the 2,950,000 MWH of sales in Idaho, but the 9,495,000 MWH of energy that
16 simply passed though Idaho on its way to non-jurisdictional customers.
17 The Company's loss studies appropriately assign to all states the same level/percentage of
18 Transmission loss-the Border Load method simply assigns to Idaho any losses that happen to
19 occur on the Transmission system in Idaho to Idaho.
20
21 Q.HOW SHOULD LOAD AN LOSSES BE ASSIGNED TO IDAHO IN THE
22 mRlSDICTIONAL ALLOCATION MODEL?
) See Response to LIP A Request 132.
1819
Revised Yanel, DI-24
Irgators
. 1
2 A.Load should be assigned to Idaho using the same load/sales as used to set the test
3 year revenue requirement. Losses should be based upon the same losses that were calculated in
4 the Company's loss study and applied to the test year sales in Idaho.
5 Based upon the Company's filing there was 3,325,873 MWH sold in Idaho at the sales
6 level and this equates to 3,557,594 MWH at input. Previously, I recommended that 116,877
7 MWH at the sales level be added to reflect a more properly normalized Irrigation usage. Using
8 Company's 10.148% losses that are assigned to Idaho secondary sales, the losses associated with
9 this correction would add an additional 11,861 MWH.18 Thus, the total energy that should be
10 used to assign costs to the Idaho jurisdiction should be 3,686,332 MWH.19 This energy figure is
11 virtually the same as that used in the Company's fiing, which did not inc1udean appropriate
.12 level of normalized Irgation usage (3,652,385 MWH). Thus, I recommend increasing test year
13 energy by 33,947 MWH or 0.929% in order to reflect normalized Irrgation sales, but removing
14 excess losses assigned to Idaho.2o
15 As the Company indicated in its testimony, it developed a test year set of monthly
16 coincident peaks and then adjusted those peaks in order to match the changes it made in test year
17 sales. In the same manner as was- ùsed by the Company, I recommend an increase in the
18 Company fied jurisdictional coincident peaks for Idaho by this same amount (0.929%).
19
20 Q.WHAT IS THE NET IMPACT OF THE CHANGE IN THE NORMLIZED
21 TEST YEAR SALES TO THE IRRIGATORS COMBIND WITH THE REDUCTION IN THE
.18116,877 x 0.10148 = 11,861.
193,557,594 + 116,877 + 11,861 = 3,686,332.
203,686,332/3,652,385 = 1.0092944.
1820 Yankel, DI-25
Irrigators
. 1 EXCESSIV LOSSES THAT WERE ASSIGNED TO IDAHO BECAUSE OF TH USE OF
2 BORDER LOAD DATA?
3
4 A.As pointed out above, the more appropriate normalization of test year Irrigation
5 usage/revenues results in an increase in Irgation and jurisdictional revenues of $7 milion. The
6 removal ofthe excess losses associated with the use of Border Load data almost entirely removes
7 the impact (Idaho energy and demand allocators) of the increase in the normalized Irgation
8 data. The net impact is an increase of jurisdictional energy and demand allocation values by
9 0.929%. Using the company's JAM and RA models with these new inputs results in the
10 Company's proposed rate increase of $27,697,872 being reduced by $5,394,641.
11.
.
1821 Yankel, DI-26
Irrigators
.
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
.
1 Irrigation Load Control Program
2 HAS THE COMPANY'S IRGATION LOAD CONTROL PROGRA BEENQ.
3 SUCCESSFUL?
4
A. Yes, it has been very successfuL. As a matter of fact, given the size of the
jurisdiction, it is probably the largest load control program in the countr. The Company's 2009
report on the Irrigation Load Control Programs contains a number of interesting facts:
* There was a total of258 MW (at sales level) of participation during the peak
month of July 2009. Of this amount, 4 MW was on the Schedule Forward
Program (Schedule 72) and 254 MW was on the Company Dispatch Option
Program (Schedule 72A).21
* Only an average of 12.6 MW opted out of the curtilments during July 2009.22
* The benefit of the program is established to be $81.56/kW-yr at the sale level.23
* The all-in program costs (administration, field and equipment costs, and
participation credits was established to be $41.34 per k W of participation. 24
* The Company Dispatch Option Program (Schedule 72A) customers (that make
up 98.5% of the participating load) are paid a credit (which is included in the all-
in program costs) of$30 per kW.
2\ Schedule 72 & 72A Idaho Load Control Progr (2009 Credit Rider Initiative Final Report), at 11.
22Id at 8.
23Id at 10. This is based upon only using a loss factor of 10.39%, which is the peak demand factor used
for the Utah secondar system, not the 11.642% that the Company uses for Idaho.24Id at 16.
1822 Yankel, DI-27
Irrigators
.1 Q.WAS THE PARTICIPATION IN THE IDAHO IRRGATION LOAD
2 CONTROL PROGRAM DURING THE TEST YEAR SIMILAR TO THAT LISTED IN THE
3 2009 REPORT?
4
5 A.A report for the 2010 Irrigation season has not been produced as of this writing.
6 According to preliminary reports,is the amount of participation grew in 2010 (the test year). The
7 participation level (at sales) is believed to now be:
Table 7
2010
June
July
Aug.
Avoided
MW
261
282
278
At Input
Avoided
MW
291
315
310
8
. 9 Weather conditions in 2010 were similar to those of2009, so it is expected that the need for
.
10 curtailments was below "normal" during 2010.
11
12 Q.AR THE IRGATORS PAID THE FULL BENEFIT THAT IS REALIZED
13 BY THE SYSTEM FROM THIS PROGRA?
14
15
16
17
A.No, far from it. As pointed out above, the system benefit is calculated to be at
least $81.56 per kW ofIrrigation demand that participates in the program. The Dispatch Option
customers are paid only $30 per kW as a credit. Another $11.34 per kW of cost is incured in the
25 See Response to IlA Request 23-A.
1823 Yankel, DI-28
Irrigators
. 1 operation of the program. This leaves $40.22 per kW26 of benefit that is left to be shared by all
2 customers on the system.
4
5
6
7
8
9
10
11
12.13
14
.
3
Q. IS TH BENEFIT OF THE IDAHO IRGATION LOAD MANAGEMENT
PROGRA PROPERLY CREDITED TO IDAHO AND THUS TH IDAHO IRGATORS?
A. No. It is a well recognized fact that all of the Company's customers, not just the
Idaho customers or the Idaho Irrgators, equally share in the benefit ofthe program. In fact, the
customers in Oregon, Utah, and the other states get even more than what would seem to be the
"system benefit" of $40.22 per kW that is above the cost of the program. This is because the
Irrigation Load Management Program is treated as a situs cost and not a system cost.
Generally speaking, the Company's jurisdictional cost allocation model has Idaho pay for
all costs associated with the Program (administrative and credit payments), but reduces the test
year coincident peak load to Idaho in recognition ofthe Irrigation Load Management Program as
15 follows:
Table 8
2010
June
July
Aug.
Jurisdictional
Credited MW
184
189
182
16
17 Running these reductions through the Company's jurisdictional allocation models results in a net
18 reduction in revenue requirement of approximately $7.5 millon dollars. This is approximately
19 the same as the $7.3 milion of participation credits for which the Idaho jurisdiction is made
26 $81.56 less $30.00 less $11.4 = $40.22
1824 Yankel, DI-29
Irrigators
. 1 responsible for in the Company's situs assignment of these costs to Idaho.27 Essentially, Idaho is
2 made "even" with respect to the participation credits that are paid to the Irrigators.
3 However, Idaho is also situs assigned all ofthe other costs ofthe program as welL.
4 PacifiCorp Schedule 191 (Customer Effciency Service Rate) has built into it $4,300,000 per
5 year of forecasted Irigation Load Control administrative costs. These are costs that are not
6 being spread in any fashion to the other system customers.
7
8 Q.WHAT IS THE NET RESULT OF THIS SITUS TREATMENT WITH
9 RESPECT TO THE REST OF THE SYSTEM CUSTOMERS?
10
11 A.Based upon the benefit of $8 1.56/kW, and the credit that is given to Idaho in the
.12 jurisdictional allocation model, all of the system customers essentially pay for the participation
13 credit of$30/kW, but they pay none ofthe administrative costs of the program. Essentially all of
14 the non-Idaho system customers are receiving a benefit of $5 1.56/kW,28 while Idaho is picking
15 up all of the administrative costs and its share of the participation credit costs.
16
17 Q.ASIDE FROM THE INQUITABLE SITUS TREATMENT OF THE IDAHO
18 IRRGATION LOAD CONTROL PROGRA COSTS, AR THERE PROBLEMS WITH THE
19 MANNR IN WHICH THESE COSTS AN BENEFITS AR ALLOCATED?
20
21 A.Yes. The benefit to Idaho, as passed through the jurisdictional model, is based
22 upon data that does not fully compensate Idaho for the reductions that are being offered. The
.27 See Company Exhibit 2, page 4.5
28 $81.6 less$30.00 = $51.56
1825 Yankel, DI-30
Irrigators
.1 curilment reductions used by the Company (as listed in Table 8 above) are based upon two
2 inappropriate assumptions. First, the starng point for the development of these figues is too
3 10w. The Company used a staing point of 229 MW of curilment for each of the thee sumer
4 months in the test year. In 2009, ths value was exceeded durng all thee sumer month. As
5 can be seen from Table 7 above, the anticipated parcipation level for each sumer month of the
6 test year is 30-50 MW higher than this staing value. The second problem is that these levels
7 of "potential" curailment are at the sales level and not at the input level-they need to be
8 increased by 11.642%--the demand 10ss factor used for seconda distrbution in Idaho. The
9 appropriate level of potential curtilment is listed below on Table 9 as well as the same
10 coincident factor values used by the Company to come up with the ultimate reduction that should
11 be applied to the jursdictional allocation model:
2010
June
July
Aug.
Irrigation
Avoided MVI
261
282
278
Table 9
At Input
AvoidedMW
291
315
310
Coincident
Factors
80.20%
82.50%
79.40%
Curtailment
Adjustment
234
260
246
.
12
13 Q.WHAT IM ACT IS THERE TO THE COMPAN'S REVENU
14 REQUIRMENT OF USING ACTUAL 2010 POTENTIAL CURTAILMENT LOADS AND
15 LOSS FACTORS TO REFLECT LOAD AT INUT?
16
17 A.By only reflecting 2010 potential curilment load and incorporating 10ss factors,
18 the Company's revenue requirement in Idao was decreased by $2,524,000.
19
.
1826
Yankel, DI-31
Irgators
.1 Q.WH HAD THE COMPAN LIMITED ITS POTENTIAL CURTAILMENT
2 OF IRGATION LOAD TO ONLY 229 MW?
3
4 A.The reasons that the curilment levels used were limited to 229 MW can be
5 gleaned from the 2009 Idaho Irrgation Load Curilment Report at page 18 where under
6 "Dispatch considerations" it was stated in par:
.
7 . Idaho Engineerig Area Plang is concerned that too much load is either
8 removed from or added to the system in too narow of a tie-fre (causing
9 voltage imbalances).
10 . Upon initiation of a dispatch event voltage spikes above toleraces of existing
11 substation and/or circuit protective equipment and systems.
12 . Upon the conclusion of the dispatch event and loads are once agai retued to
13 their 'normal' position voltage drops below tolerances of existig substation
14 and/or circuit protective equipment and systems.
15 . Curently there is simply insuffcient time delay in either substation and/or system
16 circuitr to accommodate the dramatic voltage changes. (Emphasis added)
17 These statements were followed up on page 18 ofthe 2009 Report with the following
18 "Recommendations":
19 . Plenar discussions with RM Area Planng (Idaho) has determined that a more
20 intellgent stepping into and out-of dispatch events wil correct the voltage
21 spikes/sages curently occurg.
22 . Changes to the dispatch protocol may be an effective strategy to delay additional
23 capital investment in infrastrcture assets.
24 . Changing the dispatch protocol will requie analysis of the RM engineerig
25 database to determe geospatial load locations as well as coordination with
26 growers.
27 . A changed dispatch protocol wi1 require the available dispatch windows to be
28 lengthened.
29 . The aforementioned changes have been preliminarly discussed with Idaho
30 growers and with members of the Idaho Irgators Pumpers' Association (IIPA).
31 . The LIP A is supportve of the requisite chages.
32 . Ths requirement will also necessitate a taff modification.
33 . As soon as analysis can be concluded and a dispatch strategy designed the
34 Company will provide details that will be (1) reviewed with the LIP A and (2) put
35 forward the appropriate taff changes to Schedule 72A for Commssion
36 consideration. (Emphasis added).
1827
Yankel, DI-32
Irrgators
.1 There are three points that can be gathered from the above discussion that was in the Company's
2 2009 Idaho Irgation Load Curilment Report: 1) Some, if not all of the problems could be
3 addressed with distrbution equipment upgrdes; 2) The spacing out of the curailments was
4 believed to be an inexpensive solution to the problem; and 3) The Company planed to make
5 changes in its dispatchig of curilments durg 2010.
6 As pointed out earlier in this testimony, Idaho has the highest Distrbution loss factors of
7 any of the states in which PacifiCorp operates. Additional expenditues to modernze the Idaho.....
8 Distrbution equipment may be a good idea and is not necessarly somethig to be avoided.
9 From my review of the Company's 2009 load research data associated with the Irgators
10 it would appear tht the curtilments of the Irgation customers had already been spread out to
11 some extent. We have not heard the results of the fuer spreading out of these curilments.12 durng 2010 and do not expect to hear until the 2010 Report is filed.
13 The Company fied ths general rate case with the 229 MW limitation on curailments
14 before the 2010 Irgation season even began and before it had tred its new dispatching protocol.
15 Furermore, the Company added additional curilable load in 2010, which presumably the
16 Company felt that it could accommodate.
17 Based upon all of the above, there is no reason in this general rate case to limit the credit
18 calculated for the Idaho jursdiction to a potential curailment of just 229 MW.
19
20 Q.IN THE LONG TERM, WHT DO YOU PROPOSE BE DONE IN ORDER TO
21 EQUITABLY ALLOCATE SYSTEM COSTS AND SYSTEM BENEFITS OF THE IDAHO
22 IRRGATION LOAD CONTROL PROGRAM?
23.
1828
Yanel, DI-33
Irgators
.1 A.Not all load management programs are equal. It makes sense to have the same
2 treatment for all programs, but that treatment should not be as archaic as the present method
3 where most of the benefits of a program are essentially spread to the system, while all the costs
4 are absorbed by the host jursdiction. If a jursdiction is going to absorb all of the costs of a
5 direct load control program, then that jursdiction should also be assigned all of the benefits of
6 that progra. In ths maner, if the progra has benefit beyond its cost, then the net benefit
7 would be realized by the host jursdiction. If the program has little or no net benefit, then the
8 host jursdiction wil bear the consequences.
9 This allocation of benefits could simply be done by "selling" reductions to the system at
10 the avoided cost-presently calculated to be $81.56/kW -year at the sales leveL. In the case of the
11 Idaho Irgation Load Control Progra, Idaho would be responsible for the approximate.12 $41.34/kW of all-in costs, and there would be no "reduction" in coincident demand calculated as
13 a result of the progrm-the allocations would impute a value for any curilments that took
14 place durng the monthy system coincident peak. The difference between the $81 "sale price"
15 and the $41 cost would go to reduce Idaho's revenue requirement.
16
17 Q.CAN YOU GIVE A SIMLIFIED EXALE OF HOW THIS WOULD
18 WORK?
19
20 A.Yes. Assuming that there are 300 MW of Irrgation load signed up for Schedule
21 72A's dispatchable 10ad control program, ths could be "sold" to PacifiCorp for $81.56/kW or a
22 total of $24,500,000 (300,000 kW ties $81.56). Ths would be treated as a purchase power
23 cost and allocated to all jursdictions on a demand basis. Idaho would be responsible for.
1829
Yanke!, DI-34
Irgators
.1 approximately 5.22% of this cost, based upon the System Capacity allocation factor. Idaho
2 would thus pay approximtely $1.3 milion associated with ths "purchase". Idaho would also
3 absorb the $9.0 milion associated with the credit paid to the Irgators (300,000 kW time
4 $301kW). Idao would also pay the administrtive cost of the program which it is now paying of
5 $4.3 milion though Schedule 191. Idao would pay $14.6 million (1.3 + 9.0 + 4.3 = 14.6), but
6 would be given a credit of 24.5 milion as a credit against its jursdictional revenue requirement.
7 Thus, instead of the progra costing Idaho approximately $4.3 milion per year, it would benefit
8 by $9.9 million and all of the other jursdictions would simply be kept neutral.
9
10 Q.WOULD UTAH'S COOL KEEPER AND IRGATION LOAD CONTROL
11 PROGRAMS BE TREATED IN THE SAME MAR?.12
13 A.Yes. However, care would need to be taen to inure that the costs of the
14 progras are calculated in a manner similar to that being done for the Idaho Irrgation Load
15 Control Program. Such an analysis for Utah's programs has not been done, so the Company's
16 present treatment in Uta (Situs treatment of costs and assignment of demand reduction) should
17 contiue until such time as either the Uta Jursdiction or the Company wish to put fort the
18 information upon which to make such a chage. If the Uta Cool Keeper program is not cost
19 effective, Utah may desire to keep the present treatment.
20
.
1830
Yanel, DI-35
Irgators
.1
2
The Load Growth Adjustment Rate in the
Energy Cost Adjustment Mechanism
3 Q.PLEASE DESCRffE THE ENERGY COST ADmSTMENT MECHAISM
4 AND LOAD GROWTH ADJUSTMENT RATE AS THEY RELATE TO THIS CASE.
5
6 A.The Energy Cost Adjustment Mechasm ("ECAM") is designed to recover on an
7 actual basis the sum of all components of net power supply costs as defined in a general rate case
8 such as this. The mechanism does not address fixed-cost recovery such as the fixed costs of
9 investment in rate base. Basically, the ECAM only considers the varable power supply costs
10 that are modeled in GRID and compares them with the actual costs incured.
11 In addition to comparng actual net power costs to those modeled by GRID in a general.12 rate case, the ECAM includes some additional components such as the Load Growth Adjustment
13 Rate ("LGAR"). The theory behind the LGAR is that the Company should not be allowed to
14 collect growt-related power supply costs through an ECAM surcharge and also collect base
15 revenues from the new load to recover those same power supply costs.
16
17 Q.WHT PROBLEMS AR BEING ENCOUNERED WÍTH RESPECT TO THE
18 LGAR?
19
20 A.PacifiCorp has had an ECAM and thus an LGAR for only a short period of tie.
21 However, the Commission has had a great deal of experience with an ECAM tye mechanism
22 and an LGAR as they relate to Idaho Power. Unfortately, due to the recent economic
23 recession and possible other causes, the LGAR for both companes has not worked as intended..
1831
Yankel, DI-36
Irgators
.1 The LGAR was intended to off-set the double recovery of growth related costs in both base rates
2 and the ECAM. Although the mechanism works well as intended for growth, it produces
3 unintended consequences under conditions of load decline-somethng that it was never
4 designed to address. In the case of load decline, the LGAR adjustment does not reflect costs that
5 were incurred by Company but, it represents costs tht were never incured. If allowed to
6 operate durg ties of 10ad 10ss, as well as load growt, ths adjustment would give the
7 Company revenue to cover costs that were never incured. Such a result is unquestionably unjust
8 and uneasonable. Essentially, under these conditions, the LGAR operates as a decoupling
9 mechanism that was never approved by the Commission.
10
11 Q.PLEASE EXPLAI FURTHER..12
13 A.The entie concept of the ECAM was to recover variations in actul power
14 supply expenses that differ from test year calculations-the emphasis here should be on
15 actul power supply expenses. The ECAM itself was meant to be "symetrcal" in tht it
16 was designed to give the Company more money/revenue when its power supply expenses
17 went up (compared to test year) and less money/revenue when its power supply expenses
18 went down (compared to test year). However, this symetr was only in relationship to
19 the power supply expenses themselves, not to the LGAR.
20 It is appropriate in a pass-though mechansm such as the ECAM, tht the
21 consumers pay more when expenses go up, but it makes no sense to raise rates when
22 usage, and thus costs, go down. When rates go up as usage goes down, a decoupling
23 mechanism is in effect-not a pass-though. The Commission has not authorized a.
1832
Yanel, DI-37
Irgators
.1 decoupling mechanism. It is appropriate that the load growt adjustment offsets to some
2 extent the amount of money that the Company gets in its ECAM to reflect the increased
3 base revenue that PacifiCorp gets associated with additional load. However, it makes no
4 sense to increase the revenue that PacifiCorp gets in the ECAM because of loss of load
5 when expenses are reduced.
6
7 Q.WHT IS THE REASON FOR THE LGAR IN PACIFICORP'S ECAM?
8
9 A.Very simply, it is to prevent the double recovery of a single cost. It
10 prevents the Company from collecting growt related power supply expenses though the
11 ECAM tht are also being collected in base revenue from new/increased 10ad to cover the.12 same power supply expenses. The concern here is in the case where the growth has not
13 occured, the cost of growth has not occured, and there have been no additional power
14 supply expenses that were incured. Why should the LGAR increase the ECAM revenue
15 for growt, and costs of growt, that never occured? Clearly the collection of an
16 expense that never occured is against all priciples of fairness, let alone the
17 Commission's statutory responsibility.
18
19 Q.SHOULD THE LGAR BE SYMTRICAL?
20
21 A.Although the ECAM was designed to be symetrcal, the LGAR should
22 not. It is appropriate that the ECAM increase or decrease as the Company's power
23 supply expenses increase or decrease. However, when the power supply expenses.
1833
Yanel, DI-38
Irgators
.
10
11
12.13
14
15
16
17
18
19
20
21
.
1 decrease because the load has dropped, the LGAR should never be increased to make up
2 for expenses that were never incured. The LGAR was never meant to be symetrcal
3 and it does not make sense that it should be symetrcal. Because of the sustained
4 growth that PacifiCorp and Idaho Power have experienced over the last 20-30 years, the
5 idea of a 10ad decrease was far from everyone's mind when the LGAR was created.
6 Even the name of the LGAR (Load Growt Adjustment Rate) demonstrates that this is a
7 one-way adjustment related to growt. Ifit had been conceived of as a symmetrcal
8 adjustment, it would have been more properly called an "Adjustment Rate for Load
9 Changes".
There are numerous places in Commssion Orders as well as in testimony
presented before the Commission that demonstrate that the intent of the LGAR was to
address the issue of increased power supply expenses due to growt and the offsetting
additional revenue that comes with new 10ad. There has never been mentioned in a
Commission Order of the intent of the LGAR (in PacifiCorp's or Idaho Power's cases) to
reflect any type of adjustment for a reduction in system load, let alone to be an
adjustment to increase the Company's revenues when 10ads decreased.
More specifically, the LGAR was designed to insure that there was no double
recovery of the additional power supply expenses tht result due to growth. There are no
"additional" power supply expenses associated with a reduction in load-simply, less
coal is bured, there is less power purchased, or there are more sales for resale that brigs
in additional revenue.
1834
Yanel, DI-39
Irgators
.1 The design of the LGARARG29 to insure that there was no double recovery of
2 additional power supply expenses as a result of load growt was sumarzed by Staff
3 witness Hessing in Idaho Power Case No. IPC-E-06-830:
.
4 Q. Please discuss Idaho Power Company's intial PCA fiing.
5 A. Idaho Power Company fied for a PCA in 1992 and it was
6 approved and implemented in 1993 with some modifications. Idaho
7 Power's 1992 filing was made to address the problem of fluctuating water
8 conditions that caused widely varing power supply costs. When water
9 conditions were poor, power supply costs were higher than what was
10 authorized for recovery in rates. A general rate case provided no relief
11 from high power supply costs associated with below normal water
12 conditions since water conditions and power supply costs are normalized
13 in a general rate case.
14 Staff observed that in the Company's originl PCA proposal,
15 variations from the normalized costs of power supply were due to water
16 conditions and power supply cost increases caused by 10ad growt. Staff
17 believed that load growt costs could be significant and tht 10ad growt
18 costs were not the kind of costs that the PCA should recover. Staff
19 proposed a load growth adjustment mechanism in the PCA that removed
20 actual power supply costs associated with load growt by multiplyig the
21 amount of 10ad growt by the marginal cost of power supply and
22 subtractig the result from actual power supply costs. Staff approximated
23 the marginal cost of power supply as 16.84 $/M which was the average
24 of the varable costs of Valmy and Boardman the company's two highest
25 operatig costs at that tie. In that case Staff also argued tht without the
26 adjustment the Company would double recover the normalized cost of
27 power supply because it was included in base rates and in actual booked
28 power supply costs that accumulated in the PCA tre up mechansm.
29 (Emphasis Added)
30 The testimony of Staff in Case No. IPC-E-06-8 that the LGARÆARG was designed to
31 prevent double recovery of power supply expenses did not stad on its own, but was fully
32 supported by the Company testiony in that same case. Idao Power witness Said made
33 numerous references to the fact that the LGARÆARG was designed to prevent the
.29 In PacifiCorp ECAM cases this "growth adjustment" is known as an LGAR, while in Idaho Power PCA
cases the "growt adjustment" is known as an Expense Adjustment Rate for Growth ("EARG").30 See Hessing's direct testimony in Case No. IPC-E-06-8 page 4, begining on line 9.
1835
Yankel, DI-40
Irgators
.
.16
17
18
19
20
21
22
23
24
25
26
27
28
.
1 double recovery of growth related power supply expenses in his Rebuttl testimony in
2 that same case:3!
3 Adoption of an adjustment mechansm based on expenses levels created
4 the potential for double collection of power supply expenses from
5 customers. Idaho Power believes that the intent of the 10ad growt
6 adjustment rate was to eliminate the possibility of double collection of
7 power supply expenses.
8 Q. Do the other witnesses in ths case agree that eliminating the
9 possibility of double collection of power supply expenses from customers
10 has been a historical intent of the load groWt adjustment rate?11 A. Yes. ...
12 Later in his testiony in that same case, Idaho Power witness Said summarizes his
13 testiony and rnakes an even stronger case for the Company's position/eliefthat the
14 LGARÆARG is only for puroses of preventing the Company from double recoverig
15 growt related power supply expenses:
32
Q. Please sumare your rebuttl testimony.
A. All pares agree tht a principal purose of the PCA load growt
adjustment rate is to elimate the potential for double recovery of power
supply expenses. Idao Power believes ths should be the so Ie puose of
the load growth adjustment. (Emphasis added)
Mr. Said made it very clear what Idao Power felt was the "sole purpose" of the
LGARÆARG. However, because of a quik in the calculation, that became evident as a
result of a severe global economic crisis, both PacifiCorp and Idaho Power have now
used the LGAR and the EARG to collect revenue for expenses that never occured.
Given the steady growth that has taen place over the last 20-30 years, there had
been virtally no consideration of what happens when growt is negative. Like Idaho
Power witness Mr. Said testified, the sole purose of the growth adjustment was to insure
31 See Said's Rebuttl testimony in Case No. IPC-E-06-8 page 3, begining on line 6.
32 See Said's Rebuttal testimony in Case No. IPC-E-06-8 page 27, begiing on line 11.
Yanel, DI-4l18 3 6 ligmorn
.1 that there was no double recovery of power supply expenses when there was positive
2 growth (as occured every year in the past). However, even though there was little or no
3 consideration of the possibility of what the LGAR calculation would produce if there was
4 a decrease in load, the thought that the LGAR could ever produce a negative result was
5 rejected by the Commission Staff. In Case IPC-E-07-8, Staff witness Hessing made such
6 a declaration that was never challenged by any par in that case, including Idaho Power.
7 Staff witness Hessing stated on page 18 line 14 of his direct testiony that: "It is not
8 reasonable to apply a negative EARG in the PCA."
9
10 Q.WHT ARE YOU RECOMMENDING IN THIS CASE REGARDING
11 THELGAR?.12
13 A.I am not addressing the level or dollar amount of the LGAR. I am only
14 addressing the use of the LGAR in situtions where 10ad is declinig-such situations
15 that are just the opposite of the LGAR's intended purose. In both the recent PacifiCorp
16 ECAM case and an Idaho Power PCA case, negative growt has been encountered and
17 for lack of diection or for whatever reason, the LGAR has been allowed to effectively
18 operate as a decoupling mechanism and increase rates in the face of reduced sales. I
19 recommend that in ths case when the Commission sets the LGAR rate, that the
20 Commssion state very clearly that the LGAR is only to be applied in cases where there
21 has been growth on the system compared to sales levels used in the general rate case to
22 develop the net power costs that wil be included in rates.
23.
1837
Yanel, DI-42
Irgators
.
11.12
13
14
15
16
17
18
.
1 Class Cost of Service
2 Q.WHT DOES THE COMPAN'S COST OF SERVICE STUDY
3 INDICATE ABOUT THE RATE OF RETUR BEING SUPPLIED BY THE
4 IRGATORS?
5
6 The Company's cost of service study calcuÍates that the Irrgators areA.
7 providing a rate of retu that is 20% greater th the system average.33 Based upon ths,
8 the Company is proposing that the Irgators only get 70% of the average rate increase
9 that wil be adopted.
34
10
Q. IS THE COMPANY'S COST OF SERVICE STUY WITH RESPECT TO THE
IRRGATORS BASED UPON APPROPRITE INORM nON?
A. No, the Company's cost of servce study suffers from two major flaws with
respect to the Irgators: 1) as pointed out above, the normalized sales levels used are grossly
inadequate and understate the amount of Irigation sales and thus revenues; and 2) the
Company's method of developing sales over a 5-year average results in effectively giving
Irgators virally no recogntion in the cost of service study for any curilment associated with
19 the load management program.
20
21 PLEASE DESCRIE THE SHORTCOMING WITH RESPECT TO THEQ.
22 IRGA nON SALES LEVELS FURTHER.
33 See generally Company Exhibit 49, Tabs 4 and 4.1
1838
Yankel, DI-43
Irgators
.1
2 A.As pointed out above with respect to the jursdictional revenue requirement, the
3 test year "weather normalized" Irgation sales were signficantly below the normalized values
4 that have been seen over the last ten years, as well as falling short of the slightly increasing trend
5 in normalized Irgation sales over tie. Adjusting the test year sales to a more realistic level
6 would increase Irgation revenues by $7 million, while only increasing energy/varable related
7 costs and not fixed demand or customer related costs. As such, an increase in sales would result
8 in a significant increase in Irgation revenue that would be larger than the associated increase in
9 expenses. Thus, these increaed sales would increase the Irrgation rate of retu, well in excess
10 of what the Company calculated.
11
I.12 Q.PLEASE DESCRIBE FURTHER THE SHORTCOMIG WITH RESPECT TO
13 THE LACK OF RECOGNITION OF THE IMPACT OF THE CURTAILMENT OF
14 IRGATION LOAD THAT is TAKG PLACE.
15
16 A.Earlier I pointed out that the Company's jursdictional model did not give
17 full credit to the Idaho jursdiction for the level of curilment that took place with respect
18 to the Irgation Load Control Progra. However, the Company at least reduced the
19 Idaho sumer jursdictional peak by 184, 189, and 182 MW each. Unlike these
20 reductions (that were inadequate), there was no such recognition of any curilment of the
21 Irgation load in the Company's class cost of service study. This is in spite of the fact
.34 See Griffith direct testimony at page 2
1839
Yankel, DI-44
Irgators
.1 that the same 5-year average Irgation load was used for both the class cost of service
2 study and the jursdictional modeL.
3
4 Q.ARE YOU PROPOSING AN SPECIFIC CHANGES TO THE
5 COMPANY'S COST OF SERVICE STUDY TO CORRCT THESE
6 SHORTCOMIGS?
7
8 A.Not at ths tie. I provide these observations in order to inform the
9 Commission that the rate of return calculated by the Company for the Irrgation class is
10 severely understated and that the actual rate of retu for the Irgators is much higher
11 than calculated by the Company..12
13
14
15
16
Because I am not proposing specific adjustments at ths time to the Company's
cost-of-service study, I am acceptig (for now) the Company proposal to limit the rate
increase to the Irgators to the 70% of system average as proposed by the Company.
Assuming no other par advocates for an increase greater than 70% of the system
average for the Irgation customer, I will not propose any fuer adjustments in this
17 case.
18
19 Q.DOES THIS CONCLUDE YOUR DIRCT TESTIMONY?
20
21 A.Yes.
.
1840
Yankel, DI-45
Irgators
.
.
.
18
19
20
1 had in
2
(The following proceedings wer~open hearing.) I
MR. OLSEN: Mr. Yankel is now tenderek3
4 cross-examination.
5 COMMISSIONER SMITH: Thank you.
6 Mr. Williams.
7 MR. WILLIAMS: No questions.
8 COMMISSIONER SMITH: Mr. Purdy.
9 MR. PURDY: No questions.
10 COMMISSIONER SMITH: Mr. Woodbury.
11 MR. WOODBURY: No questions.
12 COMMISSIONER SMITH: Mr. Otto.
13 MR. OTTO: I have no questions.
14 COMMISSIONER SMITH: Mr. Budge.
15 MR. BUDGE: No questions.
16 COMMISSIONER SMITH: Mr. Solander.
17 MR. SOLANDER: Thank you.
CROSS-EXAMINATION
21 BY MR. SOLANDER:
22
23
24
25
Q.Good afternoon, Mr. Yankel.
for
Q.What happens if you have two '~ri ~hl p~ that are
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
A.Good afternoon.
highly correlated in a regression analysis?
1841
YANKEL (X)
lIP
.
.
20
21
22
23
24.25
1 A.You 're going to have to give me a little more
ibackground.There's a lot of things that could happen.
Q.Okay.If you have two highly-correlated
2
3
4 variables, would you typically include both of theml when you're
running a regression analysis? I
IA. Chances are, you wouldn't. I mean, Yfu would
Icheck for autocorrelation between the two variabiest yes.
Q. And you would agree that that's what fr. Eelkema
Ihas done by excluding precipitation from the weathet
i
i
normalization? He's included temperature in its Plfce.
A. No, I'm not in agreement with that. l mean, he
did say that he did not include precipitation. I
Again, as I testified, Idaho Power hal two
precipi tation variables. I don i t believe temperatule and
I
IDid you include any data in your test:imony
Ithe record that would show the two are not correlatad?
5
6
7
8
9
10
11
12
13
14
15 precipi tation are necessarily that tied together.
16 Q.or in
17
18 A.Not specifically, no.
19 dispute the evidence thit the
-- introduced, demonstr~ting that
i
Q. So you didn't
Company -- that Dr. Eelkema
I didn't see any evidence that he had lintroduced
I
Do you have any data that you could u~e as a
basis to disagree with Dr. Eelkema' s conclusion tha~
I
temperature and precipitation are correlated?
A.
to that effect.
Q.
1842
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
YANKEL (X)lIP
.
.
.
19
1 Itemperature and precipitation are strongly correlated?
i
INo, I have none that I've produced, n~.
MR. SOLANDER: That's all the qUestiols I have.
I
I
COMMISSIONER SMITH: Do we have questlons from
2 A.
3
4 Thank you.
5
6 the Commissioners?
7 COMMISSIONER REDFORD:No.
COMMISSIONER KEMPTON:No.
COMMISSIONER SMITH:Tony,I'm sorry.How have
you been?
THE WITNESS:Fine.
COMMISSIONER SMITH:Good.Okay,we got a
question.
8
9
10
11
12
13
14 Mr. Olsen, any redirect?
15 MR. OLSEN: No, none, your Honor, Madim Chair.
iCOMMISSIONER SMITH: Does that concluge your
!
COMMISSIONER SMITH: Okay. And Mr. Y~nkel may be
16
17 case?
18 MR. OLSEN:That does.
20 excused if there's no objection.
21 (The witness left the stand.)
22 COMMISSIONER SMITH: Speeding right alpng.
-I23 Mr. Otto, is Dr. Reading around?
24
25
i
MR. OTTO: Madam Chair, Dr. Reading assured me he
is on his way 20 minutes ago, and he should be here
1843
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
YANKEL (X)lIP
.
.
. 25
1
i
tt
i
I
iWe fnow
momentarily.
2 COMMISSIONER SMITH:Well, we'll go
3 Mr. Purdy.
4 MR. OTTO:I apologize.
5 COMMISSIONER SMITH:No problem.
6 Dr. Reading: We know what you're up against.
7 (Laughter. )
8 MR. PURDY: Madam Chair.
9 COMMISSIONER SMITH: Mr. Purdy.
10 MR. PURDY: May I ask the Chair's ind~lgence for
Ia very short recess before we put Ms. Ottens on the I stand?
ICOMMISSIONER SMITH: You may have seven minutes.
MR. PURDY: All right, thank you.
COMMISSIONER SMITH: We'll be at rece~s for seven
11
12
13
14
15 minutes.16 (Recess.)
17 COMMISSIONER SMITH: Well, in the unbiidled
I18 optimism that Commissioner Redford will be here, we IWill go
19 båck on the record now. I
20 Mr. Otto, would you like to call your Iwitness?
21 MR. OTTO: Thank you, Madam Chairman. I would
22 like to call Dr. Don Reading on behalf of the Idaho
23 Conservation League.
24
1844
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
YANKEL (X)lIP
.
.
.
DON READING,
produced as a witness at the instance of Idaho Conservation
ILeague, being first duly sworn, was examined and tettified as
4 follows:
1
2
3
5
6 DIRECT EXAMINATION
7
8
Thanks lor braving
BY MR. OTTO:
9 Q. Good afternoon, Dr. Reading.
10 the inclement weather.
11 A.Yes.
12 Q.Would you please state your name and four
I
Associatel.
!
13 affiliation?
14 A.Don C. Reading, Ben Johnson
15 Q.Could you go ahead and spell your last name for
16 the record?
17 A.R-E-A-D-I-N-G.
18 Q. Thank you. And your -- are you the same
. IDon Reading that filed testimony in this case -- ditect19
20 testimony on October 14th of this year?
21 A.Yes, I am.
22 Q.Thank you. And did that direct testi~ony contain
23 any exhibits? I believe there was one.
24 A. Yes.
25 Q.Were there more?
1845 ¡
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
1EADING
(Di)
ICL83701
.
.
19
20
21
22
23
24.25
1 I
Iqueftions that
A.No.
2 Q.And if I were to ask you the same
3 iare contained in this direct testimony today, would! your
I ,Yeah, I have two typographical corrections.
ICorrect. Thank you. Could you let us know those
I
Yes. The first, on page 13, line 9, lhe word
And then the other, page 20, line 1, Tyour"
4 answers remain the same?
5 A.
6 Q.
7 changes?
8 A.
9 "patter" should be changed to "pattern."
10
11
I
IWi th those changes -- there are no otfuer changes.
I
COMMISSIONER SMITH: Could you do the I second one
THE WITNESS: Yes. Page 20, line 1, 'ryou" should
I
I
COMMISSIONER SMITH: Thank you. I
MR. OTTO: Thanks. And with those twJ changes, I
I
would ask that Dr. Reading's prefiled direct testim~ny be
!
ICOMMISSIONER SMITH: If there's no objlection, it
I
I
(The following prefiled direct Itestimony
I
i
I
should replace "you."
12
13
14 again, please?
15
16 be changed to "your. "
17
18
spread upon the record as if read.
is so ordered.
of Dr. Reading is spread upon the record.)
1846
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID
~EADING
I
(Di)
ICL83701
. 1 Q. Plea state your name, addres, and afftion.
2 A.My name is Don Reading. I ~ Vice Prident and Consltig Ecomist for
3 Ben Johnon Associates, 6070 Hill Roa Boise Idao. My ree is atched as
4 Exhibit No. SO i.
S
6
7 Q. On whose behalf are you testifyg in this Diec Testimony?
8
9 A.The Idao Conseation Legue (JCL) has asked me to examine Rocky MoW1~
10 Power's (R,.the Company) prpose reidenal rate strct, the potetial of the cost
of the Compay's Irgation Pea Rewar progr out of the DSM taff and into
mtebase, and the pndence of the Copay's coal plant polluton contrl.
ii
. 12
13
14
is Q. Do you have any Exhibits?
16
.
l" ~ ~. ..~" ,:
17 A.Yes. Exhbit No. SOL is my reume.
18
19
20 Q. Pleas summar your testimony?
21
(.
.Reág. Di 1
Idao Coneration Legue; . '0. '. .; .~"
\--.'- ~
1847
.
9
10
11.12
13
14
15
16
17
18
19
20
21
22
.
1 A.i will ad th prmar topics. Fir we ar proposing a differt reidential
2 rate design frm th prpose by the Compay. Fqr Schede 1, we propo a
3 th-tier inver block rate with equa prces for each sen, but with larger bloc
4 in the wite th in the suer. For Scheule 36 time-f-us cumer, we prpose
5 to reove the sena differ in regntion of the sml contribution to swer
6 peak loa atbutle to the reidential cla. For both Schede 1 and Schede 36 we
7 propose a smer fied cuomer chae in order to sed a stng prce sign though the
8 ener che.
Secnd, we p~po the Commssion, Compay, and other paes should purue
alloc the irgation load contrl pr Schedes 72 and 72 A, as a system wide
resour. While ths propo likely re a chae to the Resed Prtool for
inteurctona co alloctions, we believe it is a reble and pnent prpo.
Thir we rase.some conce with the Company's prpose spedi on
pollution contrl equipment. Whle reucig pollution is an importt goal, we ar
concered the Compay is mide the spific investments in this cae before
reiving fi apval they will comply with exitig federl reuiments. Morever,
we ar conceed tht the Company contiues to inves hmidr of milions of dollar in
their col plants in the face of incringly strgent, and costly. polluton reuients.
To addss these conce we reuest the Commission ord the Company to provide a
more robus anlysis of fu compliance cost before mag fuer polluton contrl
investents in their co genertion flee.
Readig. Di 2Idao Consation Legu
1848
. 1 REENT RATE DESIGN
2
. 12
13
.
3 Q. Let's turn to the fIrt secon of your testimony. Could you plea expla
4 Rocky Mountai Power's current reidential rate desig and their propos .
5 changes?
6
7 A.t
RM cumy offer two reidential rates, Schedule i and Schedule 36.
8 Schedule 1 is the default rate and consist ofa monthy minimum chae o(SIO.64 for
single-phase peanent reidents. This monthly minimum incr for th pha and9
10 seaonal homes. The prmar fea of the cut Schedule i is a seon flat rate pe
ii kWh in the suer, frm May to Octber, of iO.4093~ and in the wite, frm
Novembe thugh April, of8.0150~.
14
RM prposes to change Schedule 1 to a senal inver tierd ener rate with
a fied monthy seice chage ofSI2.00. They propose a fi block up to 800 kWh
biled at a rateqf8.9526~ pe kWh in the suer and 6.5519~.in the wite. The
f.
15
16 second block incqides all consumpton above 800 kWh and is biled at i2.08~~ in the
f17 sumer and 8.8451 t in the witer..i ~ .
.r
18 Schedule 36 is a volunta tie-of-us rate consistig of a fied monthly sece
19 chare of S13.63 and seonal ener raes for on pea and off pe conption. In
20 suner,May thûg Octber, on pe prces ar 11 .3497t and off pe ar 3.873,0~ pe
kWh. In wite, November thugh Aprl, on peak prce ar 9.6950~ and offpe ar
3.5447~ pe kWh. The suer peak time exteds frm 8:00 A.Mto 1 l:oo~.M. on
21
22
Readig. Di 3
Idao ~oneratOl1 Legue
1': -. ~ .
1849
.
.
.
1 weekdays only. Winte pe time exteds wm 7:00 A.M. to 10:00 P.M. weekdays.
2 The seasna off pe rate applies to nights, weeends and holidays.
3 RM prpose to incr the fied monthy sece chare to $16.00. They
t.
4 prpo to incr the kWh ra in the suer to 13.09Ø and 4.4682t and in the
5 witer to 1 L.1850Ø and 4.0894t.
6
7
8 9. It SOUDds .lie RM is propoiag aDd eDtiely Dew rate desig for Schedule 1.
9 I p~uld you brießy explaia the impact of this change?
10
"
11 A.Fir let me explai the soure of this new proposal. This inver tier rate
12 proposed by the Company grw out of the Stipulation signed by the pares, and approved
13 by the Comiio~ in RM's la gener rate case, PAC-E-08-07. In tht cae, the
14 pares explained:
,'..
~ ,~
15
16
17
18
19
20
21
22
23
24
25
26
27
Roky Mowitain Power agrs tht it will include an inver tier rate
design prol or option for reidentil cuomer in its next fied
gener rate ca for the Commision's considertion. Tier rates wer
reently approved by the Common for Idao Power residetial
customer It doe not follow, however, Sta conteds, tht tierd rates
shuld automaticaly be requiredofRM. Ther ar some signficat
differs beee Idao Power and RM, Sta notes, tht mae fuer
evaluation of a tier rate design necssar.
For ince, RM aly ha a reidential tie-f-us rate and Idao
reprets only 6% ofPaifiCorp s cumer ba. A tier rate design
will not have th impact on a systm basis for RM tht it will have for
Idao Power, given tht Idao Power's cumer ret about 95% of
Readig. Di 4
Idao Consertion Legue
1850
.1
2
3
4
5
6
7
8
9
10
11
12.13
14
.
Idao Power's cutomer bas. i
l
'ff,i.i,
RM's proposal is likely to impact reidential ener ~ption. . Cutly
Schedule 1, beuse it chges for ener at a seonal flat ra,anly signals to reidential
cusmer th energy is more expeive in the sumer than in the wite. Flat ra do
not provide signals to encourge ener consation among sens. By chagig to
an invertd tier rate, conser will reive entily new prce signals. Th new
signal will encourge ener coeration by incring rate baSed on overal
conSlpton.
As I will explai in fuer deil below, we believe that a tier rate design is
more reasnable and effecive than the cut flat rate. However, to better reflec
reidetial us patt and their impact on RM's Idao sece te, and ii order to
achieve our goal thug this rate design, we prpose changes to RM'sprosa.
15
16 Q. What rate design goals are you trg to promote in this ease?
17
18 A.For the purses of this cae, I wat to emphasize asec of rate desig tht
19 provide reidential cutomer with incetives to consere ener. I believe this is a
20 prop goal for RM's reidential rate design for two reasns. Firs eleccity ra
21 contitJ to rise as marl ener price incre and utilities inves in re~ldig and
1 Orer No. 30783,PAC-E-08-07, at 7-8 (Augut 16,2009) (inteal citations omitt.
Reag. Oi 5Idao Constion Legu
1851
.1 upgrding inct. One method to help mitigate these rising ra is to prvide
2 cutomer wi the incetives and tols to re thei ener consption an therby
3 reuce their overll bill. Secnd, rising conspton in all clases is drving riing
4 costs for RM. Incetivig ener cons ca tepe this drve and prolong the
5 nee for costy invesents in baloa and peg reur. I am al cognt of
6 the generl goas of rate design equity, stbilty, and an opportty to reover approved
7 expees. To an ecomist, prce signls ar an effecve way to achieve thes goals.
8
9
10 Q. Before we dive into the wee could you desribe the elecc power load
11 I pattrns Ofr both in Idaho and systm wide?
. 12
.
13 A.Bas on RM's filing in this cas, RM's reidential cumer, both Schedule 1
14 and Schedule 36, show mafesy differt loa patt th either the Company's load
15 patter in Idao or the syste as a whole. On a system wide bais, the Compay is
16 close to a dua peg system but with a slightly higher us in the suer. The Idao
17 sece tentory al displays a du pe but a more pronounce sumer pe
18 Cha 1 below dilays th asts ofRM's load profile: sytem wide, the
j
Idao juricton, and tl Idao reidential class. As you can see, Idao's reidential19
20 clas conses the larest sh of its power dug the witer month. Basd on RM
21 witness Paice's Cos of Serice rets, in Idao the reidenaa clas constitu betwee
22 33% and 37% of wie pe loa, but only 12% - 20010 of sumere pe 10ad,1
Readig. Oi 6Idao Consation Legu
1852
. 1 Meawhile, irgation loads dnve the suerme pe contrbutig 43% in Jwie, 36.2
2 % in July, and 33.3% in Augu 2
3 Chart 1
/i
Syst.. and Idaho MWH209
6,000,000
5,000,000:I
14,000,000
E 3,000,000II
¡ 2,000,000'I
1,000,000
500,000
400,000 :I
300,000 I
200,000 JI
100,000
4
5
i~ Ii a.l§"S !t~1j ~ ~~ L ~ ~ .~ ~ ~ ~ ~ 0 Z Q
"Idaho Residential -Systm ..Idaho Tota
.6
7 Q. Doe this residenti usagepattm that is divergnt frni the Conip~,nY'8
8 overall load shape presnt a unique challenge in desiging residential rate?
9
10 A.Yes. Le me begi with rate design theory. Usuly a gien cusiòer class
11 follows the sy load pater to a fair deg. Higher consuption levels oft
corrlat with grte 'costs to the utility incu du the high us seaon. Ths
support. a .rate design consistg of higer cumer rates thi ar in line with the utlity's
12
13
14 higher cost. Aligng cumer rates and utility costs satifies the cost causer pays
2 Direct Testimony a/Compan Witns Craig C. Paice, Exhibit 49, Tab 5, pae 6,
(May, 2010) (showing monthly coincident pe at generon level)..Readi. Di 7
Idao Conseration Lee
1853
.
.
.
1 priciple and se the corrt price sign. Chg higher rate durg high utility
2 cost peod te to lower-cumer consption which in tu reuce cost to the
3 utility. Re co to th utlity cycles ba into beefits for all cuomer on the
4 syste.
5 Ther ar th pr fa to conside when deign an effecve and
6 resonable reidential rate deign for RM's Idao tetory. FiI reidential us does
7 not align with the higIi co suer month. Ch 1 abve shows th redetial use
8 . pe dug the witer, whle Idao and RM's sys pe du the sumer. To be
9 wee, 590.4 of reidential anua conspton ocur durg the winter sea.
10 Compag the month pe in each seon for Idao reveals tht reidenal load in
11 Janua is 205% higher th in June. Meawhile, on a jurctona bais, Janua load
12 is only 73.5% of June load 3 l
'\. ....
. ,
13 Secd, Idao's reideti cla relatve to RM's syste is tiy. For exaple
in July the ste's reideal cla kWh consption is only 0.84% of the Company's14
15 tota system, anjus 10.6% ofRM's Idao tetory. Ths mea th focing on
16 reidential us in th suer by chag higher rate wil not impa the Compay's
17 sy co to any meable degr.
18 Th most reidential customer have only a modest abilty to reuc sumer
19 deman Becus their suer consuption is relatively low, Idao reidential
20 cumer have less "head rom" thug which to rece their use. On the other
3 See Direct Testimony of Compa Wits Craig C. Paice, Exhbit 49 Tab 5, page 6
(My 2010)(showig coincidet pe at genertion level).
Reg. Di 8Idao Consaton Legu
'i '.';i'1854.l
.
. 12
13
.
1 had, dug the wite, reidential coption is higher and the potetial for reuce
2 usge is grate.
3 Thes th factors work togeter to reveal that a renable and effecve
4 reidential rate design should foc on witee conseation, in of focing on
5 recing sumerme system peak. Residential us is alrey low in the sumer, they
6 ar a tiny clas compar to overl demand, and they appea to have litte discronar
7 usge to reuce. Becus of this, focusing on residential suer time consption will
8 not signficantly impact other utility cuomer by reducing over sys cost. '.
,
9. Focusing on witerme conseration is mor likely to impac reidential ~te tie
10 peak therby reucing utility ful cost, result in lasng ener conseration and is
more eqtable beuse it regns the time and ty of use which folk ar able to11
consee.
14
15 Q.Dr. Readig, thiiigs can get prett cold in the Upper Valley in RM's servce
16 territory where natural gas is not an availble alternative. Don't thes households
17 nee to co~sumehiger levels of eledc power just to stay warm?
18
19 A.
20
That is tne, up to a point When one exes the data you ca fid a su of
customer with high levels of conspton ~g the wite months. The av~
21 reidential monthly use in the witer is 975 kWh. But, in the witer of2009" 250
custoer us more th 5,00 kWh per month which amounts to 5% of reidential
Reag. Di 9
Idao Consa'ton ~gue, ..
22
,'l" ,~". .
r', ,
i
1855
. r
.1
2
i
4
5
6
7
8
9
10
11.12
13
14
.
consumption. Anjus 3.60/0, or 1,481 cuomer, us more th 3,00 kWh pe
month which is 16% of wite reidenti consption. Thes extmely high us .~
cuson,ers ar drvig up cost for the utility and other ratepayer. Morever, since this
consption is vay higher th the avere, thes cuomer have some "head rom" .
or abilty to red to prce sign thug coation.
The rate deign I prpo below accunts for witee heatig up to a point,
whle still aiing a stg price signal at th high us, high co subset. Also, though
weatherzation asisce and similar DSM progr, RM ca provide conumers the
tols to consere ener whle rein in a wan comfortble home.
Q. What about residentil usage durig the summer seasn, aren't home air
conditinen causing aU these rate increa?
15 A.Af exaing the data I do not believe ther is a high peneton of ai
16 conditioning use for the reideti clas in RM's Idao serice tetory. As Char 1,
17 on page 7 above shows, RM's Idao residential clas pe in the witer and trugh in
18 the sumer. For RM's Idao reidential class the averge monthy us in the suer
19 is 681 kWh. This number closely align with estites of basic ener us, includig
20 lightig, appliance, and wate heatig frm the U.S. De~t QfHousing and UrbI.
21
iDevelopment Houing Choice Voucher Prgram Guide Book of approximately 750
Reag. Di 10
Idao Conservation Legu
1856
.
. 12
13
14
.
1 kWh.4
2 Like the wite sean, the data reveas a subset of ver high user li the suer.
3 Dug th sumer of 2009, 3.6 %, or 1,490 cutomer, had monthy consumption
4 grte than 1,800 kWh, which equa 14% of the sumer kWh reidential coption~
5 Just lS I explaied above, this subse of high use cuomer is drvig up cots for the
6 utlity and ratepyer. Since their consption is vasy higher than the avere, they
7 likely have the abilty to reond to a strng prce signal thugh conseation.
8
9
10 Schedule i
11
Q-c Do you support the Company's propol to shift to a tiered resldelÌ~~l ra~
desig with a fixed customer charge rather than a minimum bll?
15 A.I suppo the theory, but I disagr with how the Compay propose to aply it.
16
17
18 ,Q. Could'you explain the theory behind the Company's proposl and. brieRy state
19 your disagreement?
..'
1857
.
3
4
5
6
7
8
9
10
11.12
13
14
~5
16
17
.
1
2 A.Fir let me tà one st bak to disc generl rate design theory. In theory,
the simple rate deign would coist of tw pa. A fied chare set to rever costs
diy attbutable to cutomer tht do not var with usge. Ths is then coupled with
an energ chae set to rever the cost to the utlity for prvidig eah kilowat-hour of
ener. By prcing each pa at the utlities cost of serice, the conser would pay
their sh and the utility would reup its approved invesents. Unfortly, the
world is not this simple - as the Compay's prsa regn.
RM prpo a fied chae of$12. The theory behind ths, acrdg to
Compay witness Grffth, is th amount wi "assur tht each cusmer pays its fai
sh of the co and will allow the Compay a bett opportty to recover the fied
cots of seg cusmer.us Without gettg into the speifics of the cost components, I
disag beuse ths relatively high fied chare will constu a higher porton of the
tota bil for a low usge cons compa to a high usge consumer. Th seds a
signal tht peze low usge cusomer and doe nothg to incetiviz individual
conseration. Mr. Grth regns ths when he explain the Compay is only
request abut one haf of their cacuation of fixed costs "in order to mi the
18 impact to smal usge cumer.,,
19 Morever, RM's theory to isolate fied and volumetrc costs may hide their
20 abilty to sed price signs aimed at ener consation. Becaus RM's overll rate
5 Direct Testimony o/Company Witness Willam R. Grifth at 5, (May, 2010).
6 ld., at 6.
Readg. Di 12
Idao Consation Legue
1858
:. ii
.n. f
. 1 are low, a high fied. chae may not leave suffcient amounts to sed strng prce signals
2 thug the ener component. To send a signal for ener coervation, rate desisn.
3 should emphasiz the ener component.
4 For the ener porton, the Company proposes a seaonal, two-tier rate with a
5 higher chare for high use. The theory behind this is to reflec the higher cost to the
6 utility of meetig energy demand durg ce times of the yea and day. The seaona
7 component sign that co ar higher in the sumer. The tiered rate signs that
8 higher levels of consuption cost more. Whle it is undoubtedy tre tht energy cost
9 var, I disagr with how RM's proposa addrses the unque consumption pa of
10 Idao reidential consumer and with the effectveness of the signal it seds beus the
11 fixed rate is se so high.
. 12
13
14 Q.Given the nniquerelationship between the residential cias in Idahot~ RM
i 5 servce terrtory and the. Companyts cost strctre, what nite design a.eyoa
16 proposing?
17
18 A.We propose a the tier ra so that prce signals can be set to the lares us .
19 ~
cutomer. The Commission, in IlC-E-08- 1 0, recently approved a thtier strct
20 explaiing:
21
22
We fid tht a tier-rate scheme is an effective tool to (1) promote ener
effciency with Idao Power's incringly capacity-constred sys;..
.Readi. Di 13Idao ConseratoIl Lee
1859
.1
2
. 3
4
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
.
an (2) enle cost savigs.7
We ar adoctig a thtier rate for Rocky Mounta's reidential cuoiars
l
for these sae rens. Jus like Idao Power, RM faces a dul peakin sysem witl.
capacity constr an marl ener cost fa above embeded cost. We ag
with Stawitnes Labur's teon~ in tht ca explaiing tht tiere rate ar.most
effecve at recin coption when individuls fid themlves clos to a bre
point betwee blocks.8 Th tier rate allow for more preis bre points th
. .
accmplish th thgs: (1) prvide a baic level of use at a reonable prce, (2) send
a moderte signal for a medum level of use, and (3) aims a stng sign at a sml subset
of ver high user. Finly, we agr with the Commission tht in these tough economic
ties, and due to the heighed fruency of rate issues in the pres, the public is willing
and able to underd ths rate stctu. I have be inormed tht ICL stads rey to
asist RM an the PUC in helping conser underd tls proposed rate design.
Q. The Commision reendy approved a two-tier strctre for A vita, why are
you proposing a threetier structre for Rocky Mountain Power?
20 A.A thtier stct bett align with the load profies, genertion portolio, and
7 Orer No. 30722, IP-E-8-10, at 40, (Janua 30, 2009).
8 See IPC-E-08-10. Direct Testimony of Staff Witness Brian Lansry at 12 (Ocobe 24,2008). I~
Readig. Di 14
Idao Conseration Legue
1860
. 1 maal cost ofRM. Avistaha employed a two-tier rate stct in Idaofor over
2 a decde. In 2008, A vist reested an incre in the rate of the second block. The
. 12
13
.
3 Sta oppose ths incre explaig that since A vist has a high system load factor, and
4 doe not rely on costy peg reur ther is litte cost ba ren to sed a stng
5 prce signal.9 RM face a differt scaro with a relatively low system load far
6 and a grter depdence on high cost peg resources. Moreover, Avist's
7 reidential rate design is not a closed ca. As par of the Stipulation in the most recet
8 A vist rate cae, the pares aged to covene a workshop to fuer discu reidential
rate design issues.109
10 As I desbed above, basd on RM's system profile, reidential prfile, and
11 genertion mix a the-tier rate strctu is reonable and will be an effectve way to
promote coation and addrs raayer needs .
14
15 Q. Based on-your analysis above ofRM's seasonal load pattern and average
i16 eonsumptionfor the residential eIas, do propose equal blocks for summer land
17 winter seasns?
1
18
19 A.No. Becus the avere us is rougly 300 kWh higher in wite than in
20 sumer, a reasnable and effecve wite block should be higher than the suer block.
¡
9 SeeAVU-E.9-Ql, Direct Testimony of Staf Witness Brian Lansbury at 5-6, (My29,2009). -
10, Orer No. 32070, A VU-E-IQ-I at 6, (Septebe 21,2010).
Rea. Di 15
Idao Conseation Legue
1861
11,'t
'.
.
.
.
I Ou goal is to prvide a baic level ofus tht includes some amount of heg and
2 coling while seg a stng si to those causing the high cost to the sytem. I
3 woud like to highight th th ar the sae goals identified by the Commion when
4 they approved Ida Power's thtier rate stn in 2008.11
5
6
7 Q. In Idaho Power's lat general rate eas the Staff propo, but the Commiion
8 did not adopt, a higer break point beeen the second and thir blocks in the
9 witer. Do you ree why that was?
io
ii A.Unforttely Orer No. 37022 does not explain why the Commission did not
12 adopt the higher wite block. My understadig of the Staffs proposa wa tht a
13 larer secnd block would accunt for the fact tht while residential consumption peaked
14 in the wite, the system did not Staff witness Labur also explained the larer
15 send bloc would account for some amount of electrc space heatig. 12 For purses
16 of the prt ca, I want to emphaiz that, like Idao Power, RM's reidetial us
17 pea in witer. Morver, I propo a larer fi block in the wite, which allows for
18 some level of spce heag consumption at the lower rate.
19
20
1 I Orer No. 3702, IPC-E-8-10, at 40 - 41, (Janua 30, 2009).
12 IPC-E-8-10, Diret Testiony of Staff Witness Brian Lansbury at 14 - 15, (Octber
24,2008).
Readig. Di 16
Idao Consation Legue
1862
. 1
. 12
13
.
Q.What are block points you are reommeDding?
2
3 A.The fi tier exteds to slightly above the averge use in the given sean; 100
4 kWh in the wite and 700 kWh in the sumer. The higher fit tier in the wite
5 allows for elecc space heag cumer who have no other choice, unike RM's
6 proposed block of 800 kWh. By setg the fit block slightly above averge use in
7 each seaon, the signal for Conseration is aimed at cutomer who ar more likely to
8 have discronar coption. These bre points would send a prce signal to
roughly 33% of sumer and 28% of witer customers who repret approxiately 60%9
10 of the reidential load in each seaon.
ii The brea POint betwee the second and third tier is taeted at the highes 3.5%
us. For wite, this includes cusmer Consuming more than 3,00 k~ pe month
who acount for 16% oftbe wite Consuption. In summer, the bre point is 1,800
14 kWh which enCompas 14% of the sumer Consuption. Table 1, on page 22 below,
IS sumarze thes blocks.
16
17
18 Q. Why did yon chooe to set the upper tier break point to capture the highest
19 3.S% of users?
20
21 A.This br point resents a Compromise beee the varous goals we ar tr
22 to achieve of equity, stbilty, providig an opportity to reup approved'invesents
Readig. Di 17Idao Consatioa. Le~
1863
.
.
.
i and incentivig coation. Ou propose thir tier is aimed squaly at a small
2 subset of ver high us. Bec ths reresents a relatively smal numbe of
3 cuomer it shoud limt impa to other cusomer and limit RM's exposur to fied
4 co rever ri while havi a meable impact on overl systm cost.
5
6
7 Q.What rate are you propoing for each tier?
8
9 A.Le me begin by sayig tht without knowig the exact revenue reuiment we
i 0 ar not able to provide preise moneta values for the rates. The spefic numbe
11 below ar ba on RM's ful revenue reuest Obviously ther will be some chages
12 thugh the ra ca pro. Beus of ths, I will emphasiz the differtials
13 beee ti, not the level of the rates.
14 We ar prpoing the sae rates in eah tier for both summer and wite. Equa
i 5 sena rate stes a balce betwee the fact that residential 1000 ha litte impact on
16 sumer tie pe, when cost ar highest but a slightly higher contrbuton to
17 witerte pe when mal cost ar a bit lower. It also provides a level of
18 I simplity for conser by only varg the block siz by seson.
19 The spfic rate ar 8.SØ pe kWh in tier 1, 10.0Ø cents in tier 2, and 12.5Ø cets
20 in tier 3. Ths eqte to a rate differtial of 18% betwee tier 1 and 2, and 25%
21 betwee tier 2 and 3:. Betee the fi and third tiers, the differntial is 47%. Th
seds a stg sign to the highes tier. Table 1, on page 22 below, suarzes the
ì Reag. Di 18Idao Consaton Legue
22
1864
. 1
. 12
13
.
rates.
2 For compartive purse, A vist's approved differntial betwee tier 1 and 2 is
3 11.8%. For Idao Power the Commission recently approves differtials of 14%
4 beee tier 1 and 2, 24% between tier 2 and 3, and 41,4% betwee tiers 1 and 3.
5 Table 1, on pae 22 below, suares the rate design for Avist Idao Powe, RM's
6 prposal, and ICL's proposal.
7
8
9 Q. Idaho Power's thretier rate design provides for equal size blocks ~ut dierent
10 sesonal rates. Why do you propose the opposite for.RM?
11
A. My proposa is based on the unique relationship beten RM's Idao reidetial
customer class and the jurctonal and system load shapes. Unlike Idao Power, wher
14 the residenti clas is a ver large porton of the system load in RM's Idao tetory
reidential clas costtutes only 10.6% of anua Idao load and 0.84% of the syste's
July pea RM;sreidential us is stngly wite peng. Becus they contribut
15
16
17 litte to total sytem cost, ther is litte cost ba justification for seaona ra.. The
18 cost based jusfication to reduce tota coumption reais. In order to allow for a
19
20
21 costs.
22
Reaing. Di 19Idaho Consation Lee
1865
.
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
.
1 Q.What is you remmendatin for the customer charge?
2
3 A.The Compay prpo to relace the curt minimmn bil rate, with a fied
cutomer che of$12.00 per mont RM says it could justify a monthy cumer
ch of$29.86 ba on the fied cuomer cots frm its cost of sece stdy. These
co iÍclude, Distbuon-Met, Distrbution-Serice, Distbuton-P&C,
Ditrbuton-Traformer, and Retal co.13 The Company goes on to debe the
re of their suey òf Idao elecc utilities tht found the highes cusmer chae
was $36.00 for Fall River Electrc Coop, with Norter Lights at $25.00, and Cleaate
Elecc Coo at $18.00. They coclud, in ord to justify their prposed $12.00 rate,
th it would be the four lowes in the stte.14 Wht they fail to mention is tht their
exaples ar all public, not investor owned utilities. A more renable compason
would be to Ida's other two IOUs. This compason reveals, RM's $12.00 proposal
would be more th double Avista's chare of $5.00 and th ties higher th ldao
I Power's chae of$4.00.
As discus above the Compay sttes they ar not as for wht they feel is
the fuly jusfied amount, "in orde to min impact on small usge cumer. "IS
We agr with this goa beus a $12.00 chare would constitute a relatively high
porton of the montly bil for low usge customers compard to high us cutomers.
Fixed chaes at ths level do not sed signls to customer that promote conseration.
13 Direct Testimony of Compa Witness Wiliam R. Grifth, at 5.
14 ld, at 6.
15ld
Readig. 'Oi 20Idao Consation Legu
1866
. 1 In fact they send the opsite signal that bils do not decline along with coumption.
. 12
13
.
2 For Schedule 1 cuomer we propose a customer charge ofS5.oo bas on the
3 Company's cost of met and servce. Using these two items yields a cuomer rate of
4 $4.54 tht we rounded up to $5.00.16 Ths amount aligns with the other Idao IOU's
5 and allows the overl rate design to foc on signaling ener conseraton;
6
7
8 Q. Since the utity has a rit to the opportnity to recover approved costs
9 doesn't Hmitig the fixed costs mean some of this amount must be con~ted through
10 varible energ rates?
ii
A. It is tre that to some extent rate design is a zeo sum game beee fied and
ener cost. However, the prcise natu of what is a fied cost and varable co is a
14 subject of debate. Morver, by includng fied cost in volumetc saes, the utility ha
15 an incentive to kee thes cost low. If fixed cost ar retued thugh a serce
chare, this incetive is weaer. Ou proposed the-tier rate design allows a reonble16
17 oppoit to rever fied cots. While the tail block is priced higher th maral
18 ra, and therfore conta. a higher porton of fixed costs, our propose rate design
19 aims this block at a smal porton of total customer. Also, since the reidential clas is
20 such a small porton ofRM's jursdictonal sales, any impact to fixed cost rever
caused by our propose ra will be minor.21
16 Id, at Exhbit 53 at 1.
. Reag. Di 21
Idao Conseration Lee.
1867
.
.
.
1 I believe it is more renable and fa to kee the sece chare relative low.
2 Ths sends the prpe signs to low use conser, and leaves sucient amowits to
3 sed strng pnce sign thug ener rate.
4 TABLE 1
5
Avita Idaho Power RM ICL proposed
2010 2008*propose
839 kWh (anual)
Average 850 kWh 1065 kWh 839 kWh
951 kWh (wite)
use (anua)(anua)(anua)
681 kWh (suer)
Sumer Winter
1st 800 kWh
1st 60 kWh 1st 800 kWh 1st 700 kWh ioOOkWh
Block siz tid 200 kWh
2ii ::600 kWh 2nd ::800 kWh 2ii 1800 kWh 3000 kWh
3M ::2000 kWh
3M ::1800 kWh ::3000 kWh
Diferentil . .Sumer Winter
18%
between 11.78%14%11%35%
25%
blocks 24%15%
Diferenti 1 st 3.6%
between Equal 2ii 6.2%36.6%Equal
seasons 3rd 14.6%
Servce
$5.00 $4.00 $12.00 $5.00
Charge
I · Raos tr Ida Powe's 200S General Rate Cas Orer No. 30722, IPC-E-oS- i 0 (Janua .30, 20~).Reg. Di 22
Idao Conseration Legue
1868
.
. 12
13
.
1 Schedule 36 Time or Use Rates
2
3 Q. You mentioned .in the beginning of your testimony that Rocky Móunta offers
4 two residential rate designs. Could you desribe Schedule 361
5
6 A.Yes. Schedule 36 is a volunta tie-of-us rate consistng of a fied sece
7 chae and a seanaiy differtiate on pe and off peak energy chare. Sumer
8 rates ar 9% higher on peak and 17% higher off peak than winte rates. The difI~tial
9 between on and off pea rates is 173% in the witer and i 93% in the suer.
10
ii
Q. What kid of price sigal doe this rate schedule send?
14 A.The theo behid time of use rates is to signal consumers that ener vades in
15 cost depding on the time of day and yea. RM's Schede 36 provide t\o signs in
16 one rate: (1) a wea signal that sumer months are more cosy than witer month and
17 (2) a very strong signal tht dayte (on-peak) is more costly than nightte (off-p).
. ';:'::.--
18 However, within each tie peod, all consumption is biled at the same rate. Bec~e
19 this rate design sends a signal based on the tig of consumption intead of the amoun~
20 it tends to caus load shiftg rather than ener consation.
21
22
Reag. Di 23
Idao Consaton Legue, ... .'..-';"'",
1869
.
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
20
21
.
1 Q. Could you explain a bit more about the dierence between load Ilig and
2 energ consrvation and how rate design can incent thes actins?
3
4 A.Time of us ras prvide a strng sign for load shftg. A simple exaple of
load shiftg is when a conser deides to ro their dishwasher at night in of
durg the day. Time ofus ra signal this acton beaus ener is expeive durg
the dayte. To avoid ths high cost, the consmer should shift their loa to nightte.
This sign only wor if the coer is awar of the higher price and ca identify load
they ar able to sh in tie, either to nighttme or to another sen. The conser
mus also make a decion about shftg each loa eah tie they want to. use the energy.
Tier rate séd a stg signl for ener consation. A simple exaple of
energy coneration is when the consumer decides to purhase a new, more effcient
dishwaser. Tier ra sed this sign beus energy becomes more expensive
bas on overl consption, regaèss of time. Ths sign work when consumer
ar awar of their tota ener load and their options for reucing their conspton.
By doin so, the conser loc in a permently lower level of consumption tht does
not depd on tie or requi fuer deision-makg.
Thes actons may both be desirble outcomeS depedig on one's policy goal
and the constrts in the electrcal syste. Load shiftg ca reuce cots to the utility
by reucing pe fuel nee and preventig the need for adtional pe gention plant.
Ener consation also res cost to the utility by reucing the need for adtional
22 generation plat of all ty.
Reag. Di 24Idao Consation Lee
1870
. 1
.12
13
14
15
16
17
18
19
20
21
.
When choosing betwee time of us and tier rates it is importt to coider the
2 chaercs of the rateayer. Times ofus rates ar effective for raeper who have
3 many options for shftg.load and who have a relatively large contrbution to sysem
4 pe. Tierd rate. ar more effectve when the ratepayer ha many options for
5 reucing load and their contrbution to system pe is relatively smalL.
6
7
8 Q. How doe sigalig for. load shiftg or energy conservation impact residential
9 customen?
10
11 A.Time of use and tier ra each provide a signal but likely will caus sornewat
differt rets. Under tie of use rates, because the consumer ca shift their
consumption in tie, they ar less likely to purue chages in entrconsptiontht
ar more durble. One problem is tht, while residential. customer might have a vaet
of options for shiftg load on a daily bais, they have relatively few options on a
~.
seaonal basis. Heating, lighti, and water heatig consume the fuajority'of reidential
energy. Heating is weather depdat makg is ver ha to voluntaly shft load frm
cold weather to tepete. Likewse, lightig load depds on sulight and is ver
diffcut to shft Finlly, wate heatig is tyically a yea round desir. Unlike
commerial or indusal user who ca, depdig on their proucton pr, shift
practice to rend to sena rate signals, many reidential consuer, depdig on
22 their penal.cirumstace, caot
Reaing. Di 25.Idao Consation Lee
1871
.
.
.
i Unde tier rate conser avoid higher utlity bils by reucin thir overll
2 ener consption. This rate deign incents conser to fid the lea cost and least
3 effort way to save en and re their ener bills. More importtly, reidential
4 consumers tyicaly have far more options for ener consation th they do for load
5 shng. Parcularly with the incre in RM's DSM progr, along with feder
6 and state ta incetives, reidenal consers have the tols to inlate their homes,
7 pur new appliances, and inll more effcient wate heater. Consumption ba
8 signls also allow invidua to purue the ener consation options tht work for
9 their lifestle. Ind of neeg meaur that ca shift in time, their only metrc is
i 0 overl ener savigs.
11
12
13 Q. How do load shif and energ conservation sigals inOuence the utity?
14
15 A.Fro the utlity perstive, load shftg tends to avoid the nee for peg
16 plants, but ha a sml effec on the need for basload genertion. The utility is stll
17 reui to see th load shifted onto off peak hour. Because ener conseation
18 reuc overl consption, the utility wil avoid both peakg and baload resoures.
19 By reucing overl ener consption the utility is more likely to avoid building new
20 generon of al ty, thby keing cost low for all rateayer.
21
22
Redig. Di 26
Idao Consation Legue
1872
. 1
9
10
ii.12
13
14
15
.
,.
Q. Sounds Hke you do not support time-f..use rateS. Is that accurate?
2
3 A.We suprt tie-f-us rates beus they ca provide importt and etTecve
4 prce signals. As I sad before, both time-of-use and tierd rates incent desirle
5 actions. The disticton is betwee the ty of policy outcome tht is desire. ICL's
6 policy goal is to promote ener coeration in the residential class beus they have a
1 relatively low contrbution to RM's system pe and more options to consere energy
8 th to shift load.
In fact, we suport havin both tier and time-of-use rate schedules. Schedule
36 is cutly a volwita schedule. If the Commission approves the chane to tier
rates for Schedule 1, then conser will be able to choose which rate design fits with
their individua sitution. Going forward, once RM's residential customer beme
comfortble with tier rate it may be possible to combine the two ~heules. A
combination of tie-f-us rate, with tier blocks within each time peod ca send
ver prese and etTectiveprice signals aied at both shiftng loads and recing
16 consuption.
17
18
19. Q. ... What rates are you proposing for Schedule 361
20
21 A.11e sae caveats regading the precise level of the ener rate aply to thes
22 remmended rate as for Schedule i. Followig the sae logic disced above for
Reag. Oi 21
Idao Conseration Lee
1873
.
.
.
1 Schedule 1 cumer we prse equal suer and winte rates. Becus th
2 reidential cla cotribute a small porton to sumer time pe ther is litte cost based
3 jusfication for high suer time rate. The on-pe rate ar set at 12.4t pe kWh
4 apprxiately equa to the uppe tier for Schedule 1 cusomer. The off-pe rate is set
5 to match the rate differtial of 176% betwee wite off and on pe in RM's cut
6 taff This equate to an offpe rate of 4.5t per kWh. Table 2, on page 29 below,
7 su RM's curt an prse tie-f-use rate and ICL's prposal.
8
9
10 Q. What is aM proposed servce charge and what level do you propose?
11
i.: ..::.i.:
12 A. The Compay is proposing an incree in the cusme chae frm S13.63 pe
13 month ráteto $16.00 pe month. We propose a cutomer chae ofS8.40, which is
about half the Compay's propose rate and about 400Æi of the curnt rate. We are14
15 propose a lower cutomer chae for the sae rational deribed above - fied rate do
16 not encourge conseration beaus when a customer reuces consption their bil does
17
I not re proportonaly.
18 II
19 II
20 II
21 /I
22 /I
Redig. Di 28Idao Constion Legue
1874
. 1 Table 2
RMCurrent RM Propoal ICLPrposl
Servce Charge $13.63 $16.00 . .$8.40
On Peak ii.3497ft 13.0940ft 12.4ft
Summer
193%193%173%
Off Peak 3.8730ft 4.4682ft 4.5ft
Summer
On Peak.Winter 9.6950ft 1 i.1850ft 12.4ft
173%173%173%Off Peak Winter 3.5447ft 4.0894ft 4.5ft
2 Note: RM's seaonal differtial is 17% on pe and 9% offpea
3
. 4
5 Q.Dr~ Reàding could you please summari ICL's residential rate~ clesig
6 proposal in thiS case?
7
8 Á.ICL proposes to modfy the tierd inverd block rate by using th tier in
9 of two. Th tier allows for a more preise and strng prce signal aiea at the 3.5%
'Al' .~,;
10 of coumer who cotute 14% in the summer and 16% in the wite of the tota clas
1 1 consuption. A two-tier strct would not allow for this prise, foced sign.
12 We propose equal ra beeen sumer and winte becuse the reidential clas
13 has a minal contrbuton to sumerme syste pe. In~d, we ~
14 consumption baed rate signs becus RM's Idao residential clas ha a small
, Readig. Di 29
Idao Consation Legue.
1875
. i. contrbution to sy'load, but a lare varation beee averge us in each sen.
2 By varng the block rate beee sens, 60% of the reidential load in each seaon
3 reives a cosuption ba price sign.
4 We propo a smaller fied chåe for both Schedle 1 and Schede 36 in order
5 to sed the prope signs to low us cusomer. This smaler fied chaged alo alows
6 for stonger signal in the energy portOn of the rate, fuer incentivig energ
7 consation.
8
9
10 Relationslý beN". ùieome and power consumption
11
, ....~l.i ". "
. 12
13
Q. You propo a rate desig that imposes greater cots on households that use
higher levels of electr power. Do you have àny ùiformation about the
affordabUity of chargg higer users more fo;eo;rgy?14
15
16 A.Ther is a lack of reliable stdies on the relationsp beee income and elecc
17 conspton. Some stes ar focused on less develope countres and others foc
18 on the relatonp betwee income and over all ener use. One rect stdy of
19 Califoria consumer indicates higher income housholds' consers use more elecc
20 power th lower income housholds.
21
22
.Readg. Oi 30Idao Consation Legu
1876
. 1 Q. Could you be more specific about what the study said about the relatioDShip
5
6
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
.
2 between elecc consumption and income?
3
4 A.The stdy's sttistica model examined four differt houshold inme rages,
along with a wide varety of other demogrphic data. The model's strct wa aimed
at the expeon that a higher income household would us more eleccity, while
regng tht these higher income households would also spd more money on
ener-effcient appliances. The four income rages used in the study wer; Low-income
$0 to les th $20,000; Low-mid-income $20,000 to $44,999; Mid-income $45,00 to
$79,00; and High-income grter than $80,000. The stdy concludes:
1ñe intetions ar a low-mid income housold consues 9.2 pet
mor eleccity than a low-income household; a middle-income household
conses 23.1 pent more eleccity pe peon than a low-income
houshold; a high-income household consues 33.8 percent more
eleccity pe peon than a low-income household. i
The cation here is, of cour, tht the above results ar basd on averges and
that some lowe income familes, due to a numbe of factors, may in fac coune more
~~~:'~:
power th some higher income failes. These results should not be intè as a
reon to abadon or lesen low-income ener assistace progr. They do, however,
indicate in gener, housholds that use higher amounts of electc power ar ~. able
17 National Ener Technology Laboratory, An Investigation into California ~
Residentil Electricity Consumption at 19, (July 29,2009) DOEITL2001l371
(available onine at:
htt://w.netl.doe.gov/energy-analyses/pubs/CA_US_elec _consumption_FINAL _July2
9-2009.pd.
Reaing. Di 31Idao Constionl-e
1877
.
. 12
13
.
1 to aford to pay a higher prce.
2
3
4 Q. Did the Caliornia study provide any informatin about power consumption
5 in Idaho?
6 r'\
7 A.Yes. The sty prete the data usin two mea tht indicated the
8 intesity of power consption with st. The two meas wer eleccity
9 consption pe pen (ECP), and electrcity intensity meaur by the power us per
10 real gros domesc prouct (GDP) with the stte over the 1990 to 200 tie peod.
II Among all state Idao raed fift highest in the countr for ECP (16,974 kWh pe
pen). Idao ra thd highest in the countr in eleccity intety (0.714 kWh
pe real dollar of GOP). is Whle many factors could be found to explai Idao's high
14 intenity of elecc usge, thes facts do indicate there is significat potetial in Idao to
15 reuce the stte's electrc consption though conservation progrs.
16
17
18 Q. In prir rate ea for Avi, Idaho Power, and Rocky Mountain the
19 Commision has approved speial fundig for low-income weatherition and
20 education progams Do you believe these are important progams?
21
18 ¡d. at 4 and 8.
Reding. Di 32Idao Constion Legu
1878
. 1 A. Yes. We believe the low-income weatherition progrs ru by the CAPAI
2 agencies ar an importt tool to asist peple in respondig to rising ener cost. Th
3 is parcuarly tre beus these agencies peorm pr and post weatherzaon
4 evaluations. Also, becus these prgrs have income-bas qucaon, we
5 believe they dit reour to those who nee them. Becuse we prpose a ra design
6 foced on reducing overl energy consuption, we believe rayer should be given
7 the tools to respond to these signals. Moreover, these progrs ca rece the amomt
8 ofuncoIIecble cuomer bils, which can reduce overl syst costs.
9
10
11 IRGIATION LOAD CONTOL PROGRA
12
. 13 Q. Could you desbe Schedules 72 and 72 A, RM's Irration Load Contrl
14 Progam?
15
16 A.Underschedules 72 and 72A Irgation cusomers may elec to allow R¥ to
17 cul their electrc wate pumps durng peak sumer hour, therby reucing over
18 system load Schedu1e 72 is a planed cuilment option, while 72A allows RMto
19 remotely dispatch pumps durg high load hour. Accordin to RM's 200 Deand
20 Side Management Anual Rep for Idao, and Company witnes Hedan's di
.Reag. Di 33Idao Conson Lee
1879
.
.
.
1 temony in th ca; ths prog ha 258.2 MW under contrct 19 To ince
2 parcipation in this prgr. pacipants reive a crt pe eah kilowatt durg
3 culment peod.
4 RM pays for ths pro thug a bifuted fudig scheme. The
5 adinisttive exp to implement and mae the progr ar pad out of the
6 Cumer Effciency Serice Rate. Schedule 191. For simplicity sae, I will refer to
7 this schedule as the DSM taff. Dug 200, RM incud $3,816,417 in expes.
8 The incentive payments ar rolled into gener rates paid by all Idao rayers. In
9 2009, RM paid out $7,324,477 in crts, for a tota prgr cost of$1 1,140,895.1
10
11
12 Q. Do you beDeve the inatioD load cODtrol progm is a cos effective way t?
maDage peak loads?13
14
15 A.It app tht it is. While RM spnt over $11 milion, the Compay.s 2009
16 DSM Reprt caculate tht the Compay avoided $20,149,384 in ener cost.20 The
17 cost efftivenes ofDSM progr ca be evaluated using five tes origily
18 developed by the Caiforna Public Utilities Commission and explained in the California
19 Stanard Practice Manul. Another usfu document explaig the inputs to these
20 tes and how to interet the rets is Understaning Cost Effectiveness of Energ
I 19 RM 2009 Deman Sid Manement Annual Report - Idaho at 11.1 (Marh 15,
2010); Direct Testimony of Compa Witness Brian K. Hedan, atS, 11 (Aug 6, 2010)
20 Id., at Appdi 1 at pae 22.
Reg. Di 34
Idao Consation Legue
1880
. 1 Effcienc Program: Best Practices, Technica Method, and Emergg Issues for Policy
. 12
13
.
2 Maks, a pruct of the National Action Plan for Ener Effciency.21 The Stanote
3 both of these docents in the Memoradum of Undedig for Prdecy
4 Deteaton of DSM , Expenditu it entered with the th Idao invesr owned
5 utilties, includg RM, on Janua 25, 2009.
6 For purses of the RM Irgation Lod Contrl Pr th of the te
7 apply:
8 1. The Tota Resomce Cost Test ("TC") weigh the tota cost incu by the
9 utility and the pacipats, agaist the beefits, in ters of avoided cost of ener, to
fid the net benefit to the syst as a whole.22 According to RM's 200 DSM rert
this pro reed a cost benefit ratio of 5.208 and is by far the most cost effecve
prgr in the Company's DSM portolio.23
2. The Utility Cost Test ("UTC") meaur the adsttive an~.incetive
cost incur by the utility agai the beefits meaurd as the avoided cost of
10
11
14
15 deliver the ener. A ratio grte than one indicates the total cost of the prgr
ar les th it would be for the utility to deliver the same power.24 Accrdg to the
Company's 200 DSM rert the prgr reed a cost beefit ratio of 1.813.25
16
17
21 National Acton Plan for Ener Effciency, Understanding Cot Effectiveiìessof
Ener Effciency Programs: Best Practices, Technical Methods, andEmeringls.suesfor
Policy Makrs. Energ And Environmenta Ecnomics, Inçand RegJIatoryAsIsce
Prject, (Noveibe 2008) (available at: htt://ww.epa.gov/eeonphin). . '22 Id., at 6-5 - 6-6." ,,'
23 2009 DSM RepOrlat 1 I, Appedi I at 22 - 23.
24 Understanding Cost Effectiveness at 6-2 - 6-3.
25 2009 DSM Report at 1 I, Appdix 1 at 22 - 23.
Redig. Di 35
Idao C,onsationLegue ;. ..".
1881
.1
2
3
4
5
6
7
8
9
10
11.12
13
14
15
16
17
18
.
3. The Rate Payer Impact Meaur ("RJ) is the most stgent of the te and
reveas whet the prgf reultS liioWé utility rate for all rayer.26 The RI
test is simiar to the UTC but includes any lost revenue caus by reuce ener sales.
However, beus ths progr shift load rath th recing conption it does not
necssarly reuce ener saes. . Accrdg to the 200 DSM rert the progr was
the only one in RM's enti portolio to pas this te with a ratio of 1.813.27
Each of thes te looks at the cost and beefits frm a differt peve,
l
therfore it is importt to compar. the resuts. The TRC exaines the pr frm
the perve ofRM's overl system and reveas it highy cot effecve. Th is
larely due to the $7.S .milion in incentive payments th ar not include as a cost
beus th amowit is collec frm rateayer. Becus this cost is trfer frm
one ratepayer to another, it does not impar costs to the syste.28 To exaine whether
the prgr is cos effective for varous steholder, the RI looks frm the petive
of all ratepyer and inclu the incentive payments as a cost. Meawhile, the UTe
taes the utilities pepeve and.looks at the progr as a supply side reur. Her
the tota cost of the avoided ener, both adintive and incetive paymen, must be
lower th the cost to supply tht ener. By includig the incetive payments as a
cost the RI and UTC enur the incentive levels ar suffcient to att pacipants
19 while still prvidig a beefit to other ratepayers.
26 Undertaning Cost Effctieness. at 6- - 6-5.
27 2009 DSM Report at i 1, App 1 at 22 - 23.
28 See Undertaning Cost Effctienes, at 6-6 ("It does not include bil savigs and
incetive payments, as thy yield an intrreiona trfer of ze (befits to cusmer
and cost to the utility th cacel eah ot out on a regional level)j.
Rea. Di .36
Idao Consaton Legue
1882
. 1
.12
13
14
15
16
17
18
19
20
.
In sum the TRC shows the admistrtive cost of the load-shiftg pr is tà
2 below the cost to sere that load. The RI shows that all rateyer std to ga
3 becaus the progr as a whole should reuce overl utility rates. The UTC shows
4 that, as a reour, the progr is the most cost effective way to see irgation loads.
5
6
7 Q. You mentioned that the current funding scheme is bifurcated wi the
8 administratie cost coming from the DSM tariff, Schedule 191, and the incentie
9 payments coming from general rates. Do you think this is a reasnable funding
10 scheme?
11
A. While I do th th scheme is reonable, I also believe it is time for the
Commission, the Company, and other staeholder to consider changig it. Two prar
reasons lead me to this conclusion. Firt, the progr administtive co for 200
wer $3,816,416. This amounts to 76% of the tota DSM taffreenue.29 When RM
retly reues to incr thistatT their forecat wa for these expe to grw to
. .$4.3 milion in 2010.30 Becuse this progr consumes the lion's shar ofRM's DSM
progr budget, it may leave inufcient fudig for other cost .effecve ener
consation meas. Also the DSM taff does not retu sucient money to cover
RM's enti pofolio ofDSM measur, resulting in a back balance the Company
29 2009 DSM Report at 31 (Table 22 showig the Schedule 191 balancing åcwit
actvity with a total rate recover of $5,0 1 0,485.78 in 200).
30 Orer No. 32023, PAC-E-I0-o3, at 2 (June 30, 2010).
Readig. Di 37Idao Conseati,()n Le
1883
.
5
6
7
8
9
10
11.12
13
14
15
16
17
18
19
.
i for to be $3.5 millon by April of2010.31 Moving the irgaon loa cotrl
2 progr adinisttive expees .out of the DSM budget would allow for a faste
3 reuction of this back balance while fìiigup money for oter ener conseration
4 progrs.il.
Secnd, this load contrl progr closely rebles a suly side reure
beause it is a qutifiable and dispatchable reour. In the pa the irgation
customer have ared th prgr shoûid be considere a syst wide resour, an
the costs should be collec frm ratepayer thugout RM's systm. The irgation
load contrl prgr more closely resembles Monsto's curent crt th more
trdition DSM progr. In addition, RM 'classifies irgation load contrl a Class 1
DSM prgr (along with their ai conditioner and commial cuilment progr).
Class 1 pros are staked together with trditiona genertion reures in the
Company'sIR cacity load and resource balance analysis.32 By contr incetives
for home ination and rate design like thos we propose in ths cae ar conside
load reucon prgr.33 At 258 MW óf meale, prctble, and ditchable
load mider contrct ths progr reresents alost half ofRM's tota Class 1 DSM and
ha fa more in coinon with a genertion resource than other DSM mea.34 Like
other gention rees, the irgation load control prgr should be a sytem wide
reur for both planin purse as well as ratemag pur.
I 31 Application, PAC.E.I0-3~ at 5 (Febru 2, 2010).
32 PacifCorp 2008 Updte Integrated Rece Pla at 29-30, 33, Table 3.9 (March 15,
2010).
33 Id., at 28.
34 Id, at 33, Table 3.9 (showig 458 MW of Class 1 DSM in the 2010 reur stck)
Rcg..Di 38Idao Constion Legue
1884
. 1 We undertad ths poition conficts with the existing Revise Procl for
2 inter-jursdctonal alloctions. Becuse of this, we encourge the paes to contiue to
3 evauate this option. We also remmend the Commission dict the Company to
4 pure movi ths progrs from an Idao only reoure to a syte wide reur and
5 adjustig the Revised Prtocol accrdgly.
6
7
8 POLLlJON CONTOL EXPENDITS FOR COAL PLA
9
10 Q.According to Company witnes McDougal's testiony regarding ø.e
11.12
13
14
15
Revenue Requirement in this cae, PacifiCorp wil spend approximately $475
milon on pollution control equipment at their exiting coal generatig plats
durig the test year. What reaons has the Company gien to justi.thes
expenditures?
16 A.Dug the 2010 test yea the Company ha intaled or plan to in, pollution
17 cotrl eqpment at Dave Johnston Unit 3, Huntigtn Unit 1, and Jim Bridger Unit 1.35
18 RM decided to install this pollution control equipment due to incringly stgent
19 feder polluton contrl laws. Accrdg to Company witnes Teply:
20 Thes investments wer identified as par of the Company's respoe.to
,-t'
.
1885
.1
2
3
4
5
6
7
8
9
10
11
12
13
14
16
17
18.19
20
21
22
23
24
25
26
27
28
29
30
31
32
.
envirnmentat reations tht gover the plants' opetions. Th th 1977
amendments to the Clea Air Act. Congs set a nationa goal for visibilty to
reedy impent frm manmae emisions in deignted nation pa and
wildees ar; th goal reulte in development of the Reonl Ha Rules,
adopte in 2005 by th Envinmenta Prteon Agecy. The fi phase of
th roles trgger Bes Available Retrfit Technlog ("BART") reviews for all
coa-fi genertion falities bult betwee 1962 and 1977 tht emit at least 250
tons of viibilty-impag pollution pe yea. The units provided with the
pollution contrl eqpment investments disc above ar subjec to BART
reviews. BART reviews of th unts have be complet and submitt to the
reve state depents of envinmenta quality for fi dispition.36
Becus th is a rage of control equipment, th Compay could inl to mee
their polluon cotrl obligations Mr. Teply goe on to expla th fars RM
15 consider in choosing a spific investment.
The Compay taes sever faors into considertion wh mag pollution
contl equipment investments includg: evaluation of stte an feer
envirnmental reatory.reuiments and asiate coplia deines;
review of emerg envionrental reguations and rolemg; and anyses of
alte complian option. . . . 'Ie BART anlys reviewed available refit
emison contl tehnologies and thir asiated peonne and cost metcs;
Each of the tehnologies was reviwed againt its abilty to meet a f¡reptive
BART emission limt bas on tehnlogy and fuel chaercs. 7 ...
In re to the Compay's decsion to intall ths pollution contrl equipment
durg the te yea cotempla in th cas Mr. Teply expla:
(The Compay is instling the pollution contrl equipment at ths tie prily
to ensur copliance with Regional.lle Rules, but al in re to a more '
strgent Natona Ambient Ai Qulty Stada and a vanety of existing and
emergg emission reucton requirjnents.38
In sum, the Copay plas to spend over $457,0,00 durg th 2010 test yea
36 Direct Testimony Compa Witness Chad A. Teply at 7.
37 Id, at 9.
38 Id, at 10.
Redig. Di 40
Ida Consation Legue
1886
to comply with, in their word, "a varety of existing and emergg emiion reucton
reuirments." However, one of my pn concerns is that the much of the speifc
tehnology the company plans to instal is bas on "a prptive BART emssion
limit." While I am no expert in speific pollution contrl equipment, I am coceed
that the Company sems to be makng these invesents before they have a final decion
on whether the equipment is suffcient to meet federa pollution contrl stda.
Q. The Clean Air Act requires the Company to have a valid perit in hand prior
to installng pollution control equipment. Doe Mr. Teply disuss this in his
testimony?
A. Yes, but I have some conce regarng his explantion. Mr. Teply explai
that for the Dave Johnn 3 and Jim Bridger i projec the Wyomig Dearent of
Envionmenta Quaity issued peits approvig the equipment chosen by the Company.
Howeer, he goe on to explai these state issued peit "wil be inco into the.
Wyoming State Implementation Plan for Regional Haz," which "is subjec to U.S.
Envinmenta Prtecon Agency ("E.P.A.") review and approval.,,9 Likewse, the
Uta DEQ issed a stte peit for the Huntigton Unit i prject, which is subjec to the
20 sae E.P.A review and approval pro.4O
2 i Whle lam not a lawyer, I undertad this statement to mea that the Company
39 Id, at 8.
40Id
.Reading. Di 4 iIdao Constion Legue
1887
.
12
. 13
.
18
19
'20
21
22
23
1 intalled this contrl eqpment before the fi deision on whether it is sucient to
2 coply with feder laws. We ar conceêd tht if the U.S. EPA do not apove th
3 State Implementation Plan, and reui more stgent contrls, the rougly
4 $475,000,00 inves in thes inufcient contrls will be incient and RM will
5 nee more expeive equipment next yea. In short it doe not se like a pnident
6 investment to spd over $475,00,00 before revig reatory approval that thes
7 contrls ar suffcient to comply with fed laws.
8
9
10 I Q. Due to concerns over cliate change and envinmental and health eoncern~
11 many obseren are predictig more stringent reglations in the future on bot" the
state and federal leveL RM says theb- pollution control investments lre made wit"
,
a "review of emergg envionmenta reulations and rulemakig." Doe ~ ~9
~;.q ~ ,"
14 on to discuss more about the impact on current poDution control projects and
. .... ..~
is potentil future stcter environmental regulations?
16
'.;'
17 A.Yes, but agai hi repons raise some conces. When ased whether the
Company's decision to intaii the pollution contrl equipment at iss in the cae would
chage if the U.S. adopte some form of can dioxide reguations, Mr. Teply
reponded:
No. The Company is cutly engaged in assing its exig genertion
resoures, its plaed supply and demd-side reur and its IO-yea capita
budget rearg the impact of can dioxide emissions retrctions. Whle
Reading. Di 42Idao Consation Legue
1888
.1
2
3
4
5
6
7
8
9
10
11
12
. ::
.
planed investments in other units may change, the Compay's plan regar
these investments would not chage due to cabon-emission restcton. The unts ..
have depeciation lives forrateaking purses tht provide sucient reai
time to depreiate the investments in the pollution controls.41
I do not dispute that the Company's 2010 polluton cotrl invesents on the
existing plants may have depreciation lives - "for ratemak puroses" - tht would fit
within the existing plant lives. MY conce is tht as futu strcter regua sons beme
law, the cut projects may not be sucient to meet the new reuients. Th
would mean another crtical decision point for the Compay. A decision would nee to
be made, based on the costs and benefits of given plant at that point in time~ whet the
most prudent path would be to make the reuired additional polluton contrl
13 expenditus or close the plant.
Whle not par of the testimony in this case, I also reviewed the Compay's most
reent Securties and Exchange Commission Form lo-k. In th form publicly trded
16 companies disclose, among other things, the business risks they face; Regag
17 pollution controls the Company explain:
18
19
20
21
22
23
24
25
The impact of peding federl, regional, stte and intertion~ accrd,
legislation or reguation relate to climate change, includig new laws,
regulations or rues limiti GHG (gr hous ga) emissions could hàve a.
mateal advere impact on us. We have significat coal-fi genertig
facilties that will be subjec to more dit impact and grte fiancial and
regulatory risks.42
41 Id., at 10.
42 PacifCorp Form IO-K at 20, (Marh 1,2010)
Readig. Di 43
Idao Conseration Legue
1889
.
10
'11.12
13
14
15
16
17
18
.
1 Q.Closing an exitig functoning coal plant sems Dke a radical suggestion.
2 Why did you say it may be the most prudent path for a uti to take?
3
4 A.The decision would deped on numerus facrs, in adtion to the cost of
5 meetig the new envinmental reirents, the age and outp chastcs of the
6 generating facilties, the cost of relacent power, exp incr in co and
7 trporttion cost, et. Basically it would boil down to a cost beefit anlysis not only
8 of meetig the existg reatory reuiment bu al some kid of probabilstic risk
9 assessment of potetial futue chages.
Oter jursdictions ar cutly evaluating whether to inves in cotrl eqpment
or retir existing col plants. In the Nortwes, we ar failar with Portand Genl
Electrc's decision to close its Boadman facilty in Orgon. Also, Du and Prgrs
Ener ar closing exig co plants in Nort Carlin as is Xcel in Colordo. In
both Nort Calin and Colorao the decision to close coal plants was drven by clea
ai legilation in each state. Even if the closing of the facility is not most co effective
path a more pnident path may be to invest in pollution contrl equipment tht exceed
existing regulations when a prbabilstc risk asent would indicate it would be less
expeive to spd now to go beyond the cut reuirements.
19 II
20 II
21 Q.What are you askig this Commision do in relation to poUution control
22 expenditures on exitig coal facUities?
Reg. Di 44Idao Coation Legue
1890
..1
2
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4
5
6
7
8
9
10
11.12
13
14
15
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17
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20 A.
A. Due to the lare expeditu R. is requestig for polluton cotrl eqent,
and the potential impac ths has on cutomer rate, both now and in the futu, we ar
asking the Commission to order the Company to jusfy any futu polluton expditu
in two ways. Fir R. should analyz not jus the effecvenes of the contrl
equipment, but whether it wil comply with existng feder pollution contrl laws.
Here, R. holds state issued peits for the eqpment, but the E.P.A has ye to decide
whether it is suffcient to meet feder requireents. Secd RM should undere a
risk asessment of meeting realistic asumptions for futu strct envinmenta
reuiments. Her, despite investi hundr of millons of dollar in thes plants
RM has not explaied the probabilty of mcter rements in the futu and wheter
I ths contrl equipment has the potetial to satisfy those reuiments.
We ar asking the Commission to infonn the Compay that they wil not allow
these pollution control expeditu to be past on to rateayer without a forw-lookig
anlysis. Environmental policy and reguation, for goo or ilL, is a movig taet, and
anyting less than includig that in an asessment of the effecveness of any expeditu
to meet tht moving taet is a disserice to both sharholder and rateyer.
18
19. Q.Doe this complete your di testmony as of Octobe 14,2010 ..
Yes it doe.
Reag. Di 45Idao Conseraton Lee
1891
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 Q.BY MR. OTTO: Thank you. I'd like to ask just a
4 couple questions about some responses to your direct testimony
5 that were contained in the rebuttal filings of Rocky Mountain
6 Power.
7 A.Okay.
8 Q.And we're going to begin, Mr. Teply on page 11
9 attempted to correct you regarding the Boardman coal plant
10 where you had stated that they decided to close that and he
11 says, well, no decision has been made to retire. Do you have a
12 response? Would you like to respond to that?
13 A.Yeah, I should have said not necessarily "closed"
14 but" stopped burning coal."
15 And my understanding, the latest company Portland
16 General Electric IRP -- and it's been accepted in a proposed
17 Order by the Oregon Commission -- is they have certain
18 pollution control installations they are going to do to cut
19 emissions, but by 2020 they will stop burning coal. That sort
20 of misses -- that technical detail sort of misses what I was
21 trying to say in that particular section, and that was that
22 utili ties around the country aren't looking seriously,
23 especially their older coal-burning plants, and estimating what
24 it will cost under existing air quality pollution controls to
25 upgrade the plant to meet those standards, and in some cases
1892
HEDRICK COURT REPORTING
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READING (Di)
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1 they're finding it most cost effective to either convert the
2 plant or shut it down.
3 Q.Thank you for that. Now, Mr. McDougal in his
4 testimony, pages 51, lines 18 through 20, it's talking about
5 irrigation load control program and how you made a proposal
6 that the Company and Staff and others should sit down and
7 consider moving that program into a system resource. He calls
8 that cost effective and prudent.
9 Would you like to respond to that?
10 A.Yeah, my concern there is I guess it's the gray
11 hair, a long time around the hearing room: Lots of times
12 commi tments are made in the hearing room about what will occur
13 in the future and then it doesn't occur for a variety of
14 reasons. And so I would like to, you know, re-emphasize that I
15 think that i s important for the Idaho jurisdiction and agree
16 wi th the quotes the Company made.
17 And I guess I would add should the Commission
18 agree with that particular position, that they would put in
19 their Order some fairly stern words about "We expect it will
20 occur and report to us," or whatever the Commission would feel
21 comfortable with so it doesn i t get lost in the shuffle of all
22 of the other kinds of things that go on.
23 Q.I'm going to skip -- I i m going to ask you just
24 11m just going to ask you two questions about Mr. Griffith's
25 testimony.
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READING (Di)
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1 A.Okay.
2 Q.And one of those is on page 8 of his testimony,
3 lines 10 and 9. He talked about the survey that the Company
4 completed on the residential customers and says, you know,
5 54 percent of customers would prefer a flat rate.
6 Would you like to respond to that?
7 A.Yeah, flat rates are -- I have two responses:
8 Flat rates are interesting. Everybody would like
9 flat rates. Let's see, I would like inexpensive Coors Light to
10 have a flat rate to Belgium import beer that I prefer. I
11 understand that the higher grades of beer cost more to produce,
12 and, therefore, you should charge more. I can name a whole
13 list of things that we would all prefer a flat rate and consume
14 more expensive goods.
15 Q.I have one last question for you: On page 9 of
16 Mr. Griffith's testimony, lines 10 and 11, he describes Staff
17 and ICL' s rate design proposal as changing twice a year.
18 Would you like to respond?
19 A.Yes. One of the things that I noticed in
20 Mr. Griffith's rebuttal testimony is sort of the argument about
21 what's more confusing to customers of -- there are kind of two
22 things: One, confusing to customers. And I think the rate
23 design that we proposed is less confusing -- potentially less
24 confusing -- and it's all, We've got to keep on and take baby
25 steps.
1894
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1 Well, there's a maj or change going to occur, I
2 assume, unless the Commission rejects all of the proposals, and
3 that is moving from a minimum bill and a flat rate to some kind
4 of a tiered rate. That's a maj or adj ustment that they will
5 have to understand.
6 Mr. Griffith criticized me as saying, well, under
7 my proposal, everybody pays the same rate in the summer and the
8 winter up to 700 kWh.
9 Well, that, to me, seems very simple to explain
10 and say that's up to 700 kWh a month in the summer and you get
11 a third more in the winter at the same price. So, in my mind,
12 that's -- to me, it's a fairly straightforward and simpler
13 explanation.
14 The underlying -- the underlying premise that
15 seems to keep you want to say people missing the point -- I
16 don't know that they miss the point or don't care to
17 acknowledge it -- is that the service terri tory over in
18 Southeast Idaho is very unique. Back when I was on the
19 Commission and it was the old Utah Power and Light service
20 territory -- and the reason is is it's pretty rural, it doesn't
21 have any maj or cities like most other, no dense areas, it has a
22 very high irrigation load as a percent, and has a very high
23 industrial load. So it's a different kind of service territory
24 than we're used to dealing with.
25 And when I looked at the residential rates and
1895
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21
22
23
1 saw their patterns of use, I said, Well, this is a unique
2 service terri tory with a very unique residential class relative
3 to the other customers. So it deserved unique treatment in
4 determining what the rate structures are that fit that service
5 territory. And because residential is so small , it doesn't
6 really have an impact on PacifiCorp' s cost structure.
7 MR. OTTO: Thank you very much. I think we've
8 pretty much summed things up, so I'm going to offer Mr. Reading
9 for cross-examination.
10 COMMISSIONER SMITH: Thank you.
11 Mr. Olsen, do you have questions?
12 MR. OLSEN: No questions, Madam Chair.
13 COMMISSIONER SMITH: Ms. Davison or Mr. Williams?
14 MR. WILLIAMS: No.
15 COMMISSIONER SMITH: Mr. Purdy.
16 MR. PURDY: I have none.
17 COMMISSIONER SMITH: Mr. Woodbury.
18 MR. WOODBURY: No questions, Madam Chair.
19 COMMISSIONER SMITH: Mr. Budge.
MR. BUDGE: No questions.
COMMISSIONER SMITH: Mr. Solander, Mr. Hickey.
MR. HICKEY: No thanks.
COMMISSIONER SMITH: How about from the
24 Commission?
25 COMMISSIONER REDFORD: No.
1896
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20
1 COMMISSIONER KEMPTON: No.
2
3 EXAMINATION
4
5 BY COMMISSIONER SMITH:
6 Q.Well, Dr. Reading, looking at page 22 of your
7 testimony and your Table 1 where you're comparing Avista,
8 Idaho Power, Rocky Mountain proposal, and the ICL proposed rate
9 structure
10 A.Yes.
11 Q.-- I just wanted you to maybe help me think
12 through this, because you have three tiers as the Commission
13 implemented for Idaho Power.
14 A.Correct.
15 Q.But, I don't know, based on our experience,
16 especially in the winter months, it's causing me to wonder if
17 three tiers ought to be two tiers simply because for space
18 heating customers, that's a pretty heavy hit. So do you have
19 any philosophical musings on that topic?
A.Yes. And being a resident of Southeast Idaho,
21 living in Pocatello, you're kind of in the banana belt of
22 Southeast Idaho --
23
24
25
Q.And it's Idaho Power.
A.Well, no, I'm talking about weather.
Q.Weather?
1897
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1 A.Right. So I lived there and that's why I say the
2 banana belt, given to what it is in the Upper Valley.
3 Understanding that electric usage in the winter
4 is very high, also there is again relatively unique, there is
5 not the al ternati ve gas up in that area that many other places
6 have, so when I looked at the particular rates I ran onto the
7 one that probably hit me the hardest, and that was I looked at
8 the average used by particular block and there are 250
9 customers in Rocky Mountain's service territory in Southeast
10 Idaho that consume more than 5,000 kWh per month. And if you
11 back down -- I've got the statistics in here -- you've got like
12 three and a half percent of the customers using 15-something
13 percent of the total usage.
14 So I tried to target those particular customers
15 and -- let's see. Without getting too far afield, having lived
16 in that area and taught college in that area, one wonders how
17 can anybody use 5,000 kWh per month. And you could certainly
18 see some very expensive electric heat homes, et cetera.
19 Wi thout any proof, I would say there's probably a lot of grow
20 lights going on up there.21 (Laughter.)
22 Q.Well, and here I thought you were going to say
23 that what we found in some of Idaho Power's territories, people
24 have hooked up their shops, sheds, barns, and other
25 outbuildings to the residential meters, so when the tiered
1898
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1 rates went in, those things came to the surface pretty fast.
2 A.Yes, and I'm sure there's some of that.
3 While not necessarily unique, look at the we
4 talked about California. Humboldt County, California, the
5 prosecutor there is a pro-marijuana; so the cops, even if they
6 pick somebody up, they can't do anything about it. And it
7 started to blow circuits in the electric utility. They had to
8 run extra lines in, and those people don't care. They just
9 continue to consume.
10 So whether it's barns or whether it's grow lights
11 or whether it's a very expensive home, the three tiers were
12 aimed at that particular very upper class of customers in the
13 winter without trying to harm the ordinary electric heat
14 residential user.
15 Q.Maybe we should put some of them into the
16 irrigation load control or ag efficiency program?
17 A.Right. Well, that would make sense. Or have
18 a -- well, we all live in Idaho, and that is maybe we should
19 have an ag exemption for barns that are heated.
20 Q.Excellent. Excellent.
21 A.Yeah. It always passes the Legislature.
22 COMMISSIONER SMITH: I think we've had enough
23 fun, Mr. Otto. I hope you don't have redirect.
24 MR. OTTO: I do not have any redirect.
25 COMMISSIONER SMITH: That's excellent. I
1899
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READING (Com)
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1 couldn't see how you could.
2 MR. OTTO: With that, I would ask that
3 Mr. Reading be excused.
4 COMMISSIONER SMITH: If there's no obj ection, we
5 wiii excuse Dr. Reading.
6 You're excused.
7 THE WITNESS: Thank you.
8 (The witness left the stand.)
9 COMMISSIONER SMITH: Does that conclude your
10 case, Mr. Otto?
11 MR. OTTO: It does conclude my case.
12 COMMISSIONER SMITH: Mr. Purdy.
13 MR. PURDY: Than k you, Madam Cha i r . Communi t y
14 Action Partnership Association of Idaho calls Teri Ottens.
15
16 TERI OTTENS,
17 produced as a witness at the instance of Community Action
18 Partnership Association of Idaho, being first duly sworn, was
19 examined and testified as follows:
20
21 DIRECT EXAMINATION
22
23 BY MR. PURDY:
24 Would you please state and spell your name forQ.
25 the record?
1900
HEDRICK COURT REPORTING
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OTTENS (Di)
CAPAI
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1 A.Teri Ottens: T-E-R-I, O-T-T-E-N-S.
2 Q.And are you the Teri Ottens who prefiled direct
3 testimony in this case on October 14th of this year?
4 A.I am.
5 Q.And do you have any corrections or clarifications
6 to your testimony, Ms. Ottens?
7 A.I do.
8 Q.Go ahead and point those out if you would,
9 please.
10 A.The first correction is on page 2. That would be
11 line 19. I transposed some figures. The "75 percent" at the
12 end of that line should, indeed, be "25 percent. ii
13 COMMISSIONER SMITH: Okay. Could you do that
14 again? I can't find it.
15 THE WITNESS: Yes. Page 2, line 19.
16 COMMISSIONER SMITH: Oh, I see my problem. Thank
17 you. Should be what?
18 THE WITNESS: Should be "25" percent, not "75."
19 COMMISSIONER SMITH: Okay. Thank you.
20 THE WITNESS: On page 7, line 6, I indicate that
21 the AARA funding would be complete by March 2012.
22 While that i s technically correct for the Idaho
23 CAPs, that is due to an additional grant that was received for
.24 almost $7 million for weatherization measures that were
25 nontradi tional which extended their AARA funding a year, but
1901
HEDRICK COURT REPORTING
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1 the traditional weatherization funding is, indeed, expired on
2 March of 2011.
3 Q.BY MR. PURDY: And, Ms. Ottens, Commission Staff
4 witness Beverly Barker expressed some I think confusion or
5 uncertainty about your testimony and the per capita comparison
6 numbers you use for LIWA funding between various utilities. Do
7 you have anything in terms of clarification on that?
8 A.Yes, I do. On several pages -- and I'd be glad
9 to go through them -- I refer to a figure of 664, yet in my
10 conclusion that figure is 408. The 664 came from dividing the
11 electric companies into the full weatherization funding that
12 Avista provides. Upon realizing my mistake, I withdraw the
13 weatherization funding that goes to gas customers only and then
14 divided the number of electric company customers into the
15 amount of weatherization funding that goes strictly to electric
16 heated homes only, which resulted in the 408, and I neglected
17 to change my testimony in several places. And I could go
18 through those. Would you like me to go through those sections
19 of the --
20 COMMISSIONER SMITH: I think that might be
21 beneficial.
22 THE WITNESS: Okay. So on page 16 -- page 2,
23 line 16 --
24 Q.BY MR. PURDY: If you would just give us a chance
25 to keep up with you. Thank you.
1902
HEDRICK COURT REPORTING
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OTTENS (Di)
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1 A.Yes. The" 664" in the middle of that line should
2 be" 4 0 8 . "
3 On page 4, line 17, again, "408" not "664."
4 And, again, on page 5, line 8.
5 And I believe that correction will address
6 Ms. Coughlin's confusion during her testimony when she
7 testified that we were trying to compare apples and oranges
8 wi th gas and electric. We have removed the gas funding from
9 our 408 figure, meaning that we have compared the electric
10 weatherization with electric customers and we compared that to
11 the Rocky Mountain electric weatherization for electric
12 customers; and, indeed, in their contract with the
13 weatherization agencies over there, it is very specific that
14 the money that Rocky Mountain Power spends on weatherization
15 can only go to those homes that are primarily funded by
16 electric heat.
17 Ms. Ottens, were you here yesterday during theQ.
18 testimony of Ms. Coughlin?
19 A.I was.
20 Q.And, specifically, did you hear my
21 cross-examination of Ms. Coughlin regarding the contract that
22 is executed between Rocky Mountain Power and the community
23 action agencies?
24 A.I did.
25 Q.All right.
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1 MR. PURDY: Madam Chair, may I approach the
2 witness--
3 COMMISSIONER SMITH: You may.
4 MR. PURDY: -- and hand out an exhibit?
5 COMMISSIONER SMITH: This would be Exhibit 701.
6 MR. PURDY: Yes, it would.
7 COMMISSIONER SMITH: Oh, there it is.
8 MR. PURDY: Sorry, I don't have an assistant.
9 (Community Action Partnership Association
10 of Idaho Exhibit No. 701 was marked for identification.)
11 Q.BY MR. PURDY: Ms. Ottens, I've handed you
12 Community Action Exhibit No. 701.
13 A.Yes.
14 Q.Would you please identify that for us?
15 A.It is the contract with the EICAP agency, the
16 community action agency in the Idaho Falls area that provides
17 weatherization. The contract is between them and Rocky
18 Mountain Power, or in this case Utah Power. It was executed in
19 2006.
Q.Now, there are two community action agencies in
21 Rocky Mountain Power's service territory in Idaho. Is that
22 right?
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A.Yes.
Q.The other one is commonly referred to as
SEICAA?
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1 A.Yes.
2 Q.Do you know if SEICAA has a similar contract?
3 A.It's my understanding that they have the exact
4 same contract as EICAP.
5 Q.Thank you. And, Ms. Ottens, are you familiar
6 wi th the negotiations that take place and the considerations
7 that are made in putting these kinds of contracts together?
8 A.Yes. About five years ago, I was the executive
9 director of the Community Action Partnership Association. I
10 was involved in contract -- not direct contract negotiations,
11 but contract negotiations with the -- in discussing the
12 contracts with the agencies and trying to put the contracts all
13 on parity throughout the state with their utili ties.
14 Q.And do the community action agencies throughout
15 the state have similar contracts with both Avista and
16 Idaho Power?
17 A.Yeah, very similar.
18 Q.All right. If you would turn your attention to
19 Section Roman numeral III of Exhibit 701 and read the second
20 full sentence therein, please?
21 A.All maj or measures and supplemental measures one
22 through six detailed below are applicable in dwellings where
23 electrici ty is the primary source of heating energy.
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Q.All right. So, what does that have to do with
any -- in terms of clarification as to whether it's a fair
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1 comparison to take Rocky Mountain Power's LIWA funding and
2 stack it up against Idaho Power's or Avista' s?
3 A.Well, as I testified, the 408 removed the gas
4 weatherization funds and gas customers from Avista' s our
5 analysis of Avista' sLIWA funding. Idaho Power does not
6 have -- does not, like Rocky Mountain Power, does not offer
7 gas -- any gas utilities. And this just clarifies this line
8 just clarifies that Rocky Mountain Power also does not offer
9 gas, and that all weatherization funding from Rocky Mountain
10 Power has to go to primarily electric-heated homes.
11 Q.And, finally, if you'd look at subparagraph
12 capi tal A there, could you read the first sentence in that
13 paragraph?
14 A.Yeah: To the extent that the US Department of
15 Energy-approved audit determines that a maj or measure is cost
16 effecti ve, savings to investment ratio is 1.0 or greater, and
17 such major measure qualifies for installation, it may be
18 installed or financial assistance will not be offered for any
19 other measures.
Q.Do you know if similar language pertaining to the
21 Department of Energy is found in the Idaho Power and Avista
22 contracts with the community action agencies?
23 A.Yeah. Over the last years in an effort, again,
24 to try and reach parity between these Agreements, all the
25 utili ties and the CAPAI agencies agree that the DOE measures
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2 be used for funding purposes.
3 Q.All right. And, finally
4 COMMISSIONER SMITH: Mr. Purdy, I just want to
5 clarify that when she read that sentence, I think she said it
6 "may," but the document actually says "must."
7 THE WITNESS: Oh, I'm sorry.
8 MR. PURDY: Thank you, Madam Chair.
9 Q.BY MR. PURDY: All right. Does that in any way
10 affect your statement?
11 A.No, it does not.
12 Q.And then, finally, Ms. Ottens, I asked
13 Ms. Coughlin some questions yesterday about LIWA funding
14 pre-2007. If my memory is correct, her awareness of that level
15 of funding was a little uncertain.
16 Do you have a memory of the funding levels for
17 Rocky Mountain Power's LIWA program?
18 A.Yes. Up until 19- -- or, excuse me, 2004, it was
19 35,000 a year; in 2007 oh, excuse me. Yes, between 2004 and
20 2007, it was 100,000; and in 2007, it was raised to 150,000.
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Q.All right. Finally, Ms. Barker has I'm sorry,
Staff witness Beverly Barker threw out a proposal I'm
23 paraphrasing here, hopefully accurately -- that there be
24 considered some type of a collaborative effort between.25 interested parties to determine what would be an appropriate
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1 formula in the future for determining LIWA funding.
2 Did you do you recall that testimony of hers?
3 A.Yes, I do.
4 Q.What is your opinion of that testimony?
5 A.We are certainly open -- the CAPAI agencies are
6 always open -- to working with Utili ties on coming up with
7 a way to -- that all of us can work together and that there can
8 be parity. I would hope though since we i ve -- we agreed in our
9 last rate case to wait two years before we would ask for any
10 kind of weatherization increase and it's been two years since
11 then waiting on the evaluation, that it won't be delayed any
12 further.
13 Q.All right.
14 MR. PURDY: Thank you for your indulgence, Madam
15 Chair and parties. With those corrections and clarifications,
16 I ask that the testimony of Teri Ottens be spread upon the
17 record as if read.
18 COMMISSIONER SMITH: So ordered, seeing no
19 objection.
20 (The following pre filed direct testimony
21 of Ms. Ottens is spread upon the record.)
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I. INTRODUCTION
Please identifY for whom you are testifYing.
I am testifYing as an expert on behalf of the Communty Action Parership Association
ofIdaho on issues pertinent to low-income customers, including how utility rates and
service afect the lives of the poor. I am not an expert in utility ratemakng and do not
purort to possess the attendant skils of that paricular profession. CAP AI is a statewide
agency representing the six Communty Action Parership Agencies, the CCOA and the
Communty Council of Idao, Inc. These agencies receive federal, state, local and
private dollars to aid the almost 25% of
Idaho residents who are in the 150% of povert
or below income levels"
II. SUMMAY OF ISSUES AND POSITIONS
Would you please outline the issues you intend to raise in your testimony and your
positions on those issues?
I) CAPAI proposes that Rocky Mountain Power's (RM) fuding for its Low-Income
Weatherization Program (LIWA) be increased in to reflect a per customer level equal to
that of AVISTA which is $6.64. For example, ifRM's average number of
residential
customers for the test year is 56,7 i 5 residential customers in Idaho, its total LIW A
fuding should be $376,588.00.
2. CAP AI proposes that RMP's curent LIW A progr design that requires 75% of
each dollar ofLIWA funding come from a non-utility source such as U.S. Deparment of
Energy LIHEAP fuds. CAP AI proposes removing this "matching" requirement and that
communty action agencies responsible for installng LIW A measures in qualifYing
homes be given the latitude and flexibility to allocate their fuding sources in the maner
that best matches existing resources with need. To accomplish this, CAPAI proposes
total elimination of the 75/25 split described abovd: 9 0 9
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3. Regarding RM's proposal to replace its curent monthly minimum with a two-
tiered, inverted block rate with the first block consumption level set at 800 kWh, it is
CAPAI's position that the first block consumption level should be set at 875 kWh in light
of the fact that RM itself states that the "average" residential consumption level is 839
kWh and that some low-income residential customers might exceed 800 kWh.
4. CAPAI opposes RM's proposal to establish a basic monthly "fixed" charge of
$12.00.
III. DISCUSSION
A. LIW A FUNDING
Please ilustrate the "needs" of low-income customers in Idaho?
Accordig to the Idaho Deparent of Commerce, 12.6% of the State's population, when
using the 2006 Census data, falls withn federal povert guidelines and an additional
12.4% fall with the state guidelines set at 150% of povert levels. The 2006 Census
reveals that those living in povert are categorized as 8.7% elderly, 15.1% children, 9.8%
all other famlies, 28.5% single mothers and 26.4% all others.
How does ths tranlate to energy "affordabilityT'
According to the U.S. Deparent of Energy, the "affordability burden" for total home
energy is set nationwide at 6% of gross household income and the burden for home
heating is set at 2% of gross household income. In Idaho, there was a gap in the
200812009 heating season of over $75 million between what Idahoans can aford to pay
(based on federal standards) for energy and what was actully paid. Curently, the
LIHEAP program sends approximately $25.6 milion (for energy assistance,
weatherization and adnistration) to Idaho.
Regarding RMP's level of low-income weatherization assistance (LIW A) funding, is
there a backlog on homes that need and are eligibJe9weatheriation in Idaho?
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1 A.Yes. Ths figure is a moving target since each year more homes reach the age and
2 deterioration level to be eligible, and especially in ths economic downtu, we have an
3 increasing number of Idaho's population who meet either the age or income requirements
4 to be considered for the weatherization program. Despite this, all of our agencies agree
5 that they have identified at least a five year backlog in the number of homes identified for
6 the program versus those they have been able to weatherize, despite the increases in
7 AR (American Recovery and Reinvestment Act) fuding.
8 Q:Would you please elaborate on CAP Ai's proposal to increase LIW A fuding?
9 A:Yes, historically, RMP fuded its LIWA program at only $35,500.00 until 2004 when it
10 was increased to $100,000.00 until 2006, and then to its current level of$150,00O.OO.
11 Q:How does ths funding level compare to Idaho Power and AVISTA's Idaho low-income
.12 customers?
13 A:Idaho Power has fuded its program at $1.2 milion since the early par of ths centuy.
14 AVISTA recently increased its fuding to $700,000.00 (Case No. AVU-E-IO-Ol).
15 Q:How do these population and fuding numbers of RM, Idaho Power and A VISTA
16 compare?
17 A:On a per capita basis, A VISTA fuds at $6.64 per residential customer, Idaho Power
18 fuds at $3.05 and RM (based on an estimated 2009 residential class number of 56,715)
19 fuds at $2.64.
20 Q:What are the respective populations of Idaho Power and AVISTA's Idaho residential
21 customers?
22 A:Idaho Power has 393,890 residential customers. AVISTA has 105,487 electric
23 customers..4 Q:Are you proposing that the three mai electrc public utilities offer the same per capita
25 LIW A fuding?1911
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Yes. There exists as much disparty between LIW A need and existing resources in
RMP's servce terrtory as in Idaho Power's and AVISTA's. It strikes me as
fudamentaly fair to all thee of the utilities, who serve the vast majority of public
utility-served cusomers in this state, and fair to their ratepayers that their funding levels
of ths valuable DSM resource be relatively equa.
What then is your specific proposal for RM in this case?
I propose that RM's LIWA fuding level be increased from its existing level of
$150,000.00 to $6.64 per residential customer, based on an anua average of thoughout
the test year.
Is there a reason that you propose that RM's fuding level match A VISTA's and not
Idaho Power's?
Yes. AVISTA's fuding level was just recently increased in Case No. AVU-E-IO-Ol.
Idaho Power's LIW A fuding, on the other hand, has not been addressed since May 4,
2004 to its curent level, nearly seven year ago (Case No. IPC-E-03-13, Order No.
29595). CAP AI intends to seek an increase in Idaho Power's LIW A fuding level in the
near futue.
Are there reasons why the Commission should consider LIW A as a desirble objective in
general terms?
Yes. As the Commssion has noted on numerous occasions, effciently ru low-income
weatheriation programs, like any cost-effective DSM program, constitute a valuable
resource with system-wide benefits. With respect to a low-income based DSM program,
there is the added benefit that derives from keeping customers on the system and
improving the timeliness of their bil payments. That is, when customers are in such
financially dire straits that they canot pay their utility bils, let alone pay them in a
timely fashion, and they might end up in shelters ik%ißerwise leaving the system with an
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outstading balance and no means of repayment, programs such as LIW A that help
reduce their bils can literally make the difference between keeping these customers on
the system and avoiding the costs of bad debt and lost income. Customers with
disposable income can afford to implement their own weathenzation measures, helping
defer the date by which additional, higher-cost marginal resources, are required. Low-
income customers, however, tyically live in the poorest of
housing stock and strggle to
pay for life's basic necessities such as rent, food, utilities, and care for their children.
Even if they own their own home, weathenzation for people livig on the margin of
society is nothg short of a luxur they canot afford.
Why is it relevant whether these customers own their own homes?
Because renters tyically do not even have the nght to intal weathenztion measures.
Whle the CAP agencies work with owners of multi-family dwellings such as aparents,
there often are not suffcient financial incentives for such individuals to install
weathenzation measures on their own from a cost-benefit stadpoint.
Would you please elaborate on the "system-wide benefits" you referred to?
As I alluded to, reducing the utility bils of the poor through weathenzation measures
allows them to shift their inadequate financial resources from one necessity to others.
Ths, in tu, will increase the likelihood tht low-income customers will make their
utility payments more timely thereby improvig the utilities' cash flow, keep them from
leaving the system, increasing the utilities' overall revenues, and avoiding walking away
from an outstading bil, reducing the utilities' costs of bil collection and bad debt wnte-
off that they likely would not recover. Tbs obviously benefits all other utility ratepayers.
Finally, like any effective DSM progra, it benefits all customers to defer the point in
time at which new resources must be acquied whether by constrcting new generation
resources, or purchasing power on the open mark~9pbìed higher than embedded costs.
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Are there other reasons why RM should increase its LIW A fuding in this case?
We are at a semial moment in time with respect to low-income weatherization. In 2009,
Congress passed The American Rec very and Reinvestment Act (AA) providing CAP
agencies with a limited but substanti i increase in fuding for, among other things,
weatherizing low-income household . In Idaho, those AA fuds must be completely
spent by March, 2012. Though it is possible to predict, there is curently no basis to
believe that Congress will tae actio to extend or replace AA. In fact, there is
concern among the low-income advo ate community that the federal governent might
reduce other federal weatherization ding resources such as LII-IEAP to pre-2009
levels.
What are the consequences of ths?
As a condition of AA, CAP agen ies were required to fully invest the increased
fudig by early 2012. In order to ac omplish ths, most CAP agencies needed to ramp
up their capacity for deliverig low-i come weatherization services including everyng
from installng actual energy savings easures to admstration of the programs. This
created a large infastrctue capable f investing vastly greater fuds and weatherizing
more households th previously pos ible. For example, additional personnel or
contractors were employed or retane and properly trained to instal, report on, and
otherwise administer the varous low- ncome weatherization programs conducted by the
CAP agencies. The CAP agencies als improved their contracting, reporting, and
auditing processes, etc. Once AA ds are exhausted, however, and especially if
other federal resoures are reduced, th re will be nothng to fill the void created by the
loss of these fuds and the existing i astrctue will collapse and disappear.
What specific concerns does this caus
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CAP AI views the loss of this infasructue as a lost opportty cost. As I have testified
numerous times before this Commission involving all thee ofIdaho's investor-owned
electric utilities, there exists a tremendous backlog of households eligible for LIWA
fuding but for which said fuding is insuffcient. Increased LIW A fuding authorized
by ths Commssion helped reduce the backlog, but AA injected such substantial
resources into the problem that the possibilty of substatially reducing the backlog
became quite real. With the loss of AA and other fuding sources it seems likely that
we will revert to fighting an uphill battle. It would not only be unortate for the CAP
agencies to lose the impressive increased capacity to reduce weatherization-eligible
households, but would constitute a lost opportty for all ratepayers to lose the abilty to
acquire a cost-effective resource with system-wide benefits. Ths is why it is essential
that the utilities step in to at least parially fill the void that will result when AA
expires. Any shortcoming or delay in tht effort could have irversible consequences.
Without funding to continue maintag the inastructue, the increased personnel and
other resources applied to invest AA fuds will simply disappear. Whle AARA was
a desperately needed infsion of capital into low-income weatherization, it was never
intended to be a fi solution. Rather, it was intended to, and successfuly did, stimulate
the CAP inastrctures to gain an upper hand on the problem. That is why I charcterize
this moment in time as critical and respectfly urge ths Commission to not delay in
filling the gap that will be created in the near future. In order to properly budget and
establish their weatherization objectives, the CAP agencies need to know today what
their resources will be tomorrow.
Are there any other reasons why you believe that RM's LIWA fuding should be
increased in the imediate futue?
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Yes. As discussed below, although CAP AI does not oppose the implementation of a
tiered, inverted block residential rate design, setting a first block level of consumption
below the average residential consumption, with a significantly higher second tier
commodity rate, especially when coupled with RM's seasonal rate differential, creates
the risk that some low-income customers who exceed that first block of consumption will
realize a heavy rate impact, especially durg the higher priced "summer" season. This
fuer justifies the need for increased low-income weatherization to give these customers
a chace to keep the majority of their consumption withi that first block.
B. 75/25 SPLIT OF LIWA FUNDS
Would you please provide a brief background and explanation of ths issue.
Ths has been an issue of contention for PacifiCorp, operating though RM or its
predecessors, for quite some time. In fact, ths Commssion intiated a separte
proceeding specifically to address the issue (Case No. PAC-E-06-10). Without delving
into the intrcate details of this issue, the Company has argued that it should be allowed to
condition low-income weatherization fuding with the requiement that for every dollar
spent on a weatherization measure, a cert percentage of that dollar come :fom other
sources such as U.S. Deparent of Energy LIHAP funds. Regardless of what RM's
rationale for ths is, it hamstrgs the CAP agencies in several ways. For example,
because each low-income weatherization fuding source comes with its own conditions
and limtations, depriving the CAP agencies frm using their discretion to utilize those
resources in a maner that is best suited to any given project impedes their abilty to
maximize the energy savings obtained from that project. As a practical matter, the utilty
should be indifferent to how the CAPs mi and match their funding sources so long as
they do so within the confies of the various conditions and limitations of those sources.
The CAP agencies operating in RM's service teiJftó& spend their full allotment of
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utility fuds every year. Thus, it makes no economic difference to the utility how the
funding sources are allocated on a project by project basis.
What was the history of the contention between PacifiCorp and CAP AI?
Initially, PacifiCorp insisted that 50% of every dollar comes from non-utility resources
until those other resources had been fully exhausted. Only then would PacifiCorp agree
to fud 100% of a weatherization measure.
What is the curent program design in ths regard?
As a result of a compromised settlement in Case No. P AC-E-06- i 0, PacifiCorp agreed to
increase its "match" of low-income weatherization fuding from 50% to 75%.
Do other utilities have similar matchig requirements built into their LIW A programs?
Idaho Power originally asked for a higher level of matchig, but ultiately settled for its
curent matchig of 85% utility fuds and i 5% fuding from other sources. A VISTA
allows i 00% of every dollar of LIW A fuding to be spent on any given project or
measure until its total fuds have been exhausted. CAP AI intends to seek an agreement
to eliminate the 85/15 split from Idaho Power at the next opportty.
Are there any final reasons why ths case would be an opporte time to elimiate RMP'
matchig requirement?
Yes. For all of the reasons I have discussed in support of the need for increased LIW A
fuding, including the expirtion of AA, it is essential to equip the CAP agencies with
the greatest latitude and flexibility possible to address the disparty between low-income
weatherization need and resources.
What is your specific proposal regarding this issue?
CAPAI proposes that RM's matchig requirement be eliminated entirely. Our rationale
is that if the Company has trly committed to funding a project, it should have no reason
to hamper the efforts of the CAP agencies to maxiMl~the energy savings derived from
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any given project. 'Ts defeats the very purose of LIW A or any DSM program. In no
event is CAP AI suggesting that RMP money be invested unreasonably or that RMP be
held responsible for fuding more than the total amount agreed to under the program.
Are there other reasons to eliminate RM's matching requirement?
Yes. It has always been CAP AI's position that there exists no valid reason to treat
PacifiCorp differently than Idaho Power or A VISTA. In the interests of party, therefore,
CAP AI believes that the matching requiement, to the extent there was ever an arguble
basis for it in the fist place, is a progr design featue that serves no usefu purose and
there is no reason to allow RMP to insist on this condition, especially to the extent it
does. As I said, CAP AI will seek to elimite Idaho Power's lesser matching of 85/15%.
C. TIERED BLOCK RATE
What is RM's proposal on ths issue?
As a result of the settÍement reached in Case No. PAC-E-08-07, RM is proposing a
tiered residential rate design in ths case. Specifically, RM proposes a two tiered,
inverted block, residential rate design strctue that would price the first 800 kWh of
residential class consumption at a lower commodity rate and a signficantly higher
commodity rate for all consumption in excess of 800 kWh. RM proposes to maintain its
existing seasonal rate differential. RM witness Wiliam Grffth testifies that the 800
kWh first block consumption level was chosen because the Company believes that its
average monthly residential class consumption is 839 kWh. Testimony of Wiliam R.
Grifth, p.4.
What is CAPAI's response to ths proposal?
CAP AI support, in theory, the concept of an inverted block rate design for the residentia
class. Though, as stated, I am not an expert on rate design, I do have some concerns
regarding how such a rate design would impact l04irome customers. CAP AI has long
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been interested in detenninig what the average monthly consumption is for low-income
customers. This data is not as easily obtained as might be imagined. This is due, in par,
to the need to protect the privacy of individuas, and the fact that utilities do not track this
tye of data. Along these lines, AVISTA agreed in settling its most recent general rate
case (A VU-E-lO-OI), to work with CAPAI prior to its next general rate case to analyze
ths issue. The issue is complicated by the fact tht although low-income customers
typically have less discretionar usage, they live in the worst housing stock and often are
forced to rely upon electrc baseboard heat. Ths fact drves up their usage per squae
foot of housing.
How does ths concern you in the context ofRM's rate design proposal?
My concern is tht for the reasons just stated, there might be low-income customers
whose usage exceeds 800 kWhmonth. Given the substatially higher commodity rate
proposed for the second block of consumption, and if low-income customers exceed the
first consumption block durg the higher priced non-heating season, the consequences 0
an inverted block rate design could result in a heavy rate shock for those customers.
Do you have a solution that addresses your concern?
Yes, at least parially. Assumng Mr. Grffth's assertion that the "average" residential
customer's monthy use is 839 kWh, then CAPAI believes tht the fist block
consumption level should be set slightly higher at 875 kWh. Ths would provide a slight
buffer to hopefully capture those low-income customers whose usage falls very close to
the consumption level cutoff. Though ths is not a pedect solution, it would hopefully
cover the majority oflow-income customers' monthly consumption while stil sending
the appropriate price signals to those with relatively high levels of discretionar usage
and who have some degree of control over their consumption.
Do you have any other proposals regarding the ini~ block rate design?
DIRCT TESTIMONY OF TERI OTTENS
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Yes. I propose that RMP agree to work with CAP AI, Staff and all other interested
persons to conduct a workshop with one year from the date of the Commission's final
order in this case to examine whether there are obvious problems with the new rate
design, assuming that a block rate design is approved by the Commssion.
D. FIXD MONTHLY CHAGE
What is CAPAI's position on this issue?
CAPAI strongly opposes RM's proposal. Firt, CAPAI is confsed by Company
witness Griffth on ths issue. On page 4 of his testimony, Mr. Grffth testifies:
"Curently, residential customers served on Schedule 1 (residential class) pay a flat,
seasonally differentiated energy charge applied equaly to all kWh. In addition, a
monthy minium charge can apply." (Emphais added). It is unclear what Mr. Griffth
means by the statement that a "monthly minum charge can apply." It is my
understading that RM curently does charge a monthly minum in the amount of
$10.64 and that ths charge applies regardless of whether a customer has any usage. This
charge is assessed agaist all residential customers, thus makg Mr. Griffth's use of
the
word "can" confing. The matter is fuher confsed when Mr. Griffth testifies that:
"The Company proposes that the curent monthy mium charge be eliminated and
replaced with a proposed fixed Monthly Customer Servce Charge of$12.00." Testimony
a/Wiliam R. Grifth at p.5lEmphasis added). Ths suggests that RM is not curently
imposing a fixed monthly charge, but that its minimum charge is being replaced with a
"fixed" charge.
What is your understading of the Company's proposal to impose a "fixed" monthly
charge?
Again, it appears that RMP aleady does collect a basic monthy charge of$IO.64, a very
high charge in relation to other regulated public utÐitleg. Perhaps the distinction lies in
DIRCT TESTIMONY OF TERI OTTENS
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the fact that the charge is now supposedly designed to captue a portion of the "fixed"
costs the Company incurs to serve its residential customers. Support for this supposition
is found on pages 5-6 of Mr. Gnffth's testimony where he states that "(tJhe residential
Customer Service charge should recover customer-related costs defined in Mr. C. Craig
Paice's cost of service study including Distrbution-Meter, Distnbution-Service,
Distrbution-P&C, Distnbution- Tranformer, and Retail costs." Because neither Mr.
Gnffth, or any other Company witness that I am aware of, explais what the existing
monthy "mimum" charge supposedly recovers, it is diffcult to know whether the
$12.00 monthy charge in ths case is try being "elimiated and replaced," (Testimony
of Wiliam R. Grifth, p. 5), or just being increased by approxiately 20%.
What is CAP AI's position on the imposition of any type of fixed monthy chage?
CAP AI opposes such charges for numerous reasons. First, it is diffcult to explai to
low-income customers why they are charged a substtial fee each month regardless of
whether they so much as flp a light switch. Thus, any fixed charges not tied to energy
consumption send the wrong pnce signal to customers and rob them of any incentive to
conserve energy. Ths diminshes the effcacy of all DSM progrs in genera and low-
income customers in paricular due to the fact that they literally must count their pennes
each month.
Please identifY your other bases for opposing fixed monthy charges?
Agai, from the perspective of a low-income expert, and not that of a ratemakng
specialist, it is diffcult for me to conceptualize how the costs identified by Mr. Griffith,
as opposed to other costs, are "customer-related." It would seem that every cost incurred
by an electrc utility such as RM is related to providig electrcity to a residential
customer. Though my understanding of cost of service studies is limited, I am of the
belief that such studies are only one factor taen irg tÓnsideration by the Commssion in
DIRCT TESTIMONY OF TERI OTTENS
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allocating rates among customer classes. Furher, cost of service studies are generally
considered to be fairly subjective. I simply canot understand how anyone, analyzing the
seemingly ininte costs incured by a utility, can specify which of those costs are
"customer-related" as opposed to those that are not. As an expert on low-income issues, I
can state that inquires received by CAP AI on ths matter reveal that low-income
customers are equally baffed and concerned by what the fixed charge on their monthly
bil pertais to. Rhetorically speakg, isn't the cost to build a power plant one that is
necessar to serve customers? What about power lines and repair crews, and virly
everyg else? It stres me that a utilty could arguably include the vast majority of its
costs into the category of "customer-related" costs. As I said, the questions that CAP AI
receives from low-income customers suggests that those customers believe they should
only be chaged for how much electricity they use. Anytg beyond that is diffcult to
comprehend from a logical stdpoint.
Are there other concern you have about fixed monthy charges?
Yes. My concern about the possibility tht most any cost could be considered "customer-
related" is highighted by the testimony ofRM witness Mr. Grffth who testifies:
"Ultimately, the Monthly Customer Service Charge should recover all residential fixed
costs. Ths will assure recovery of fixed costs regardless afusage..." rId Pp. 5-6.
Emphasis added). Mr. Grffth concludes: "The inclusion of these fixed costs in the
monthy service charge would result in a rate of approxiately $29.86 per month." Id p.
6. Ths last remark is quite distubing to me. To even suggest charging low-income
customers nearly $30 per month regardless of how much energy they use could have
severe consequences. Based on my expertise workig with the poor, I strongly believe
that they wil quickly lose all incentive to control their energy consumption and be
instiled with a sense of hopelessness regarding tl\~í2 atiity bils. Compared to the past,
DIRCT TESTIMONY OF TERI OTTENS
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electrc utilities file general rate cases quite frequently, even those who have some form
of power supply cost adjustment mechansm in place. It has also become common for
utilities to increasingly recover more of its costs though a fixed charge, rather than a
commodity rate. The appeal of ths to utilties is fairly obvious. It reduces risk and
enhces their overall rate of retu. For the reasons stated herein, it is CAPAI's position
that such requests be denied.
Is there anytg else about RM's stated rationale for its proposed fixed montWy charge
that you object to?
RMP attempts to justify its proposal by comparng the proposed $12.00 monthy charge
to purortedly similar charges levied by ten other "Idaho utilities." On p. 6
of his
testiony, Company witness Willam Griffth refers to a "study" conducted by RMP
makg this comparson but the study is not included as par of the Company's case and
all of the ten utilities are not identified. Instead, Mr. Grffth lists only three utilties, all
of which are relatively small "cooperatives." Though I am not an attorney, it is my
understanding that cooperatives are not "public utilities" and are not regulated by the
Commission. Because RM's proposed fixed charge is supposedly cost-based, it seems
irelevant what other utilities chage. Regardless, it also seems intutive that a large
company such as RM might have dratically different costs in serving its customers th
a small, rual cooperative. RM could have more appropriately compared its proposed
charge to Idaho Power's or AVISTA's. RM could have even compared its proposal to
its own sister companes such as Pacific Power & Light (PPL) in Washigton state which
serves a service terrtory not dissimilar to RM's Idaho terrtory. Though I do not know
the specifics involved, I am aware that there is curently pending before the Washington
Utilities Transportation Commssion Docket No. i 00749 in which PacifiCorp, through
PPL, is proposing to increase its existing fixed mObthchage which is curently
only
DIRECT TESTIMONY OF TERI OTTENS
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$6.00 per month. PPL is proposing to increase that charge to $9.00, substantially below
the $12.00 proposed in Idaho.
What is your specific proposal regarding RMP's proposed fixed monthy charge?
CAP AI proposes that RM fist be required to explain what its existing monthly
"mium" charge pertns to and, assumng that charge is even legitimate, that any
proposed increase to it be denied in this case.
IV. CONCLUSION
Would you please sumarze your testimony?
1. CAP AI proposes that RM's LIW A fudig level be increased from its curent
level of $1 50,000.00 to an anual level that is $4.08 per residential customer, based on a
test year average;
2. The existig 75/25% LIWA fuding matchig requirement be completely
elimiated;
3. That RM's proposed two-tier, inverted block, residential rate design be
approved, but with the first block consumption level set at 875 kWh per month, and;
4. That the Commssion Order RM to fuly explai its existing monthy mium
chage and that it be proven reasonable as is, or be reduced or elitated, and;
Does this conclude your testimony?
Yes, it does.
1924
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2 open hearing.)
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15 BY MR. OTTO:
16 Q.
(The following proceedings were had in
MR. PURDY: Thank you. And I tender her for
COMMISSIONER SMITH: Thank you.
Mr. Williams, do you have questions?
MR. WILLIAMS: No questions.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: I just have one question.
CROSS-EXAMINATION
Did you happen to review Dr. Reading's testimony
No, I did not.
You did not?
No.
Okay. Fair enough. That's fine.
COMMISSIONER SMITH: Mr. Woodbury.
1925
17 in this case?
18 A.
19 Q.
A.
Q.
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
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1 CROS S - EXAMINAT I ON
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3 BY MR. WOODBURY:
4 Q.Just a couple of questions, Ms. Ottens, regarding
5 the CAPAI Exhibit 701.
6 A.Uh-huh.
7 Q.My copy is, on page -- at the end, the last page
8 is not signed by either party. Is this a current valid
9 contract between the parties?
10 A.This is the contract that was sent to me two days
11 ago by the EICAP agency and was represented as their most
12 recent copy. It was sent to me electronically.
13 Q.So it's your understanding that this is an exact
14 copy of the contract that was. signed by the parties?
15 A.That's my -- yes, that's my understanding as
16 represented by EICAP.
17 Q.Okay. And who in EICAP?
18 A.Brad -- I've got his last name here. He is the
19 weatherization manager. I'm sorry. Brad Simmons.
Q.Sumons?
A.Simmons.
Q.Simmons. And EICAP is what?
A.Eastern Idaho Community Action Partnership.
MR. WOODBURY: Thank you. No further questions.
COMMISSIONER SMITH: Mr. Solander, Mr. Hickey.
1926
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
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1 MR. SOLANDER: No questions.
2 MR. HICKEY: No questions.
3 COMMISSIONER SMITH: I take it Mr. Budge has no
4 questions.
5 MR. SMITH: Mr. Budge is taking care of another
6 matter and there are no questions.
7 COMMISSIONER SMITH: From the Commission.
8 COMMISSIONER KEMPTON: No.
9 COMMISSIONER REDFORD: No.
10 COMMISSIONER SMITH: Nor I.
11 Mr. Purdy, I don't think you have redirect.
12 MR. PURDY: No, I do not.
13 COMMISSIONER SMITH: Thank you.
14 Thank you for your help, Ms. Ottens.
15 THE WITNESS: Thank you.
16 (The witness left the stand.)
17 MR. PURDY: Madam Chair, that concludes Community
18 Action's case.
COMMISSIONER SMITH: Thank you very much,
20 Mr. Purdy.
21 That brings us to Mr. Woodbury.
22 MR. WOODBURY: Thank you, Madam Chair. Staff
23 would call as its first witness Randy Lobb.
24
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1927
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CAPAI
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1 RANDY LOBB,
2 produced as a witness at the instance of Staff, being first
3 duly sworn, was examined and testified as follows:
4
5 DIRECT EXAMINATION
6
7 BY MR. WOODBURY:
8 Mr. Lobb, could you please state your full nameQ.
9 and spell your last name for the reporter?
10 My name is Randy Lobb: L-O-B-B.A.
11 And for whom do you work and in what capacity?Q.
12 I work for the Idaho Public Utili ties Commission.A.
13 I am the administrator of the utili ties division.
14 And in that capacity, did you have occasion toQ.
15 prefile in this case on October 14th direct testimony
16 consisting of 31 pages?
17 Yes, I did.A.
18 And have you had the occasion to preview thatQ.
19 testimony prior to this hearing?
20 I have.A.
21 And is it necessary to make any -- I believe youQ.
22 do have a change on page 8 of your testimony?
23 Yes, page 8, line 16.A.
24 What is that change?Q.
25 Transposed the numbers. The "900" on line 16A.
1928
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (Di)Staff
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1 should be "700," and the "700" should be "900."
2 With that change, if I were to ask you theQ.
3 questions set forth in your testimony, would your answers still
4 be the same?
5 A.Yes, they would.
6 MR. WOODBURY: Madam Chair, I would ask that
7 Mr. Lobb' s testimony be spread on the record, and Staff would
8 present him for cross-examination.
9 COMMISSIONER SMITH: Without objection, it is so
10 ordered, noting that there are pages of confidential
11 information in his testimony.
12 MR. WOODBURY: Oh, yes.
13 (The following prefiled direct testimony
14 of Mr. Lobb is spread upon the record.)
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P. O. BOX 578, BOISE, ID 83701
LOBB (Di)Staff
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1 Q.Please state your name and business address for
2 the record.
3 A.My name is Randy Lobb and my business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed?
6 A.I am employed by the Idaho Public utilities
7 Commission as Utili ties Division Administrator.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science Degree in
11 Agricultural Engineering from the University of Idaho in
12 1980 and worked for the Idaho Department of Water Resources
13 from June of 1980 to November of 1987. I received my Idaho
license as a registered professional Civil Engineer in 1985
15 and began work at the Idaho Public Utilities Commission in
16 December of 1987. My duties at the Commission currently
17 include case management and oversight of all technical
is Staff assigned to Commission filings. I have conducted
19 analysis of utility rate applications, rate designi
20 proposed tariffs and customer petitions. I have testified
21 in numerous proceedings before the Commission including
22 cases dealing with rate structure i cost of service, power
23 supply, line extensions, regulatory policy and facility
24 acquisitions.
25 Q.What is the purpose of your testimony in this
CASE NO. PAC-E-I0-0710/14/10 LOBB1 R. (Di)
STAFF
1930 1
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1 case?
2 A.The purpose of my testimony is to summarize the
3 Staff revenue requirement recommendation¡ introduce Staff
4 ,wi tnesses and describe the issues that each will address.
5 i will also discuss treatment of costs associated with the
6 Irrigation Load Control program¡ rate base treatment of
7 investment associated with the Populus to Terminal
8 transmission line and recovery of costs associated with
9 wind resource acquisition.
10 Q.Could you please summarize your testimony?
11 A.Yes. Staff will sponsor ten witnesses in this
13 increase of $14.8 million or 7.3% based on an Idaho
12 case to support its recommendation for an overall revenue
14 jurisdictional rate base of $682.3 million. Staff proposes
15 an overall rate of return of 8.025% and a return on equity
16 of 10%.
17 I will show that the costs of the Irrigation Load
18 Control program assigned to Idaho customers is inequitable
19 when compared to the program benefits received. I will
20 show that 50% or approximately $401 million of the $802
21 million cost incurred for the Populus to Terminal
22 transmission line is not currently used and useful and
23 should be placed in plant held for future use rather than
24 included in rate base as proposed by the Company. Finally,
25 I will discuss Staff's review of the Company¡ s wind
CASE NO. PAC-E-10-0710/14/10 1931 2LOBB, R. (Di)
STAFF
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13
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1 acquisition process and my recommendation to include the
2 cost in rate base as proposed by the Company.
3 Q.How is your testimony organized?
4 A.My testimony is organized as follows:
5 I. Recommendation Summary
6 II. Introduction of Staff witnesses
7 III. Case Evaluation
8 IV. The Irrigation Load Control Program
9 V. The Populus to Terminal Transmission Line
10 VI. Wind Resource Acquisition
11 Recommendation Sumary
12 Q.Could you please summarize Staff's
recommendations in this case?
15 revenue requirement increase of $14.8 million or 7.3% with
A. Yes, Staff recommends an Idaho jurisdictional
16 an overall rate of return of 8.025% and a return on equity
17 of 10% (Company proposed 10.6%). Staff accepts the
18 Company's proposed historic test year of January 1, 2009
19 through December 31, 2009 with reasonable proforma
20 adjustments through December 31,2010.
21 Staff rate base adjustments include placing a
22 portion of the Populus to Terminal transmission line and
23 the Dunlap I wind proj ect cost in plant held for future use
24 on the basis that the facilities are not fully used and
25 useful. Recommended expense adjustments include
CASE NO. PAC-E-I0-07
10/14/10 LOBB, R. (Di)
STAFF
31932
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1 elimination of all salary increases and bonuses for 2009
2 and 2010, reductions in pension cost, reductions in annual
3 power supply costs, removal of costs associated with wind
4 integration and a variety of other smaller adj ustments.
5 Staff's recommended revenue requirement adjustments reduce
6 the Company's annual request by $12.89 million.
7 Staff accepts the Company proposed jurisdictional
8 allocation methodology with the exception of the proposed
9 treatment of Idaho Irrigation Load Control program costs.
10 Staff also accepts the Company proposed class cost of
11 service methodology. Based on the Staff revenue
12 requirement proposal, Staff recommends a class revenue
13 spread that largely follows cost of service with revenue
14 increases of 3.06% for irrigation customers, 4.78% increase
15 for residential customers and a 12.94% increase for
16 Monsanto. Staff does not separate Schedule 1 from Schedule
17 36 Residential customers for the purposes of class revenue
18 spread.
19 Staff supports the Company's proposed two tiered
20 commodity rate for Residential Schedule 1 customers but
21 proposes seasonal block sizes and a limited increase in the
22 customer charge. Staff recommends an increase in the rate
23 components of other customer classes by the percentage
24 increase in the overall class revenue requirement.
25 Staff recommends that Company DSM expenditures
CASE NO. PAC-E-10-0710/14/10 1933 LOBB , R . ( D i )
STAFF
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14
1 for 2008 and 2009 be found prudent and that the Commission
2 consider a modification to the base rate/tariff rider
3 method of DSM cost recovery. Staff recommends that costs
4 associated with the Idaho Irrigation Load Control program
5 be treated as system power supply expenses instead of being
6 directly assigned to the Idaho Jurisdiction.
7 Finally, Staff recommends that the Company read
8 electrical meters and disconnect when service at a customer
9 location is discontinued to avoid the loss of revenue for
10 unbilled electrical consumption.
11 Introduction of Staff Witnesses
Q.Could you please describe Staff's filing in this
case?
A.Yes. Senior Staff Auditor Cecily Vaughn provides
15 the summary exhibits reflecting Staff's case. She begins
16 with actual audited PacifiCorp system data for the
17 historical 12-month test period of January i, 2009 through
18 December 31, 2009 with known and measurable changes in and
19 adj ustments to investment and expense levels through
20 December 31, 2010 (the Company case). Ms. Vaughn then
21 shows Staff adjustments and allocates the system adjusted
22 costs tò the Idaho Jurisdiction. The resulting Idaho
23 revenue requirement increase is $14.8 million or
24 approximately 7.3%.
25 The revenue requirement proposal provided in
CASE NO. PAC-E-I0-0710/14/10
1934 5LOBB, R. (Di)
STAFF
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1 Ms. Vaughn's testimony is based on rate base adjustments,
2 expense adjustments and jurisdictional allocation
3 modifications that she recommends and that are provided to
4 her by other Staff witnesses.
5 Senior Staff Auditor Joe Leckie reviewed a broad
6 cross section of Company investments included in the test
7 year and the Company's proposed plant additions through
8 December 31, 2010. Mr. Leckie makes adjustments to
9 proforma rate base additions, removes a portion of the
10 Dunlop I wind project costs that are not used and useful,
11 reduces the value of the Company's coal stockpile inventory
12 and recommends an adj ustment for the Bridger #2 overhaul.
13 Mr. Leckie also makes an expense adj ustment for wind
14 project O&M expenses and supports tax adjustments proposed
15 by the Company.
16 Senior Staff Auditor Donn English addresses
17 revenue requirement adj ustments for salaries, pensions,
18 property taxes and office. lease expense. He recommends
19 that salaries be adj usted to January 1, 2009 levels to
20 reflect appropriate cost control measures in a weak
21 economy. He further recommends that all bonuses included
22 in revenue requirement be removed. Mr. English recommends
23 an adjustment in pension costs to reflect the appropriate
24 amortization of contributions. Finall~, he recommends
25 adjustments to reflect a more appropriate accounting of
CASE NO. PAC-E-10-07
10/14/10
LOBB , R . (D i )
STAFF
61935
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1 property taxes and office lease revenues.
2 Deputy Administrator and Audit Section Supervisor
3 Terri Carlock addresses cost of capital and return on
4 equity. Ms. Carlock recommends a return on equity of 10%,
5 updates the cost of debt and preferred equity, and
6 recommends an overall rate of return of 8.025%. Ms.
7 Carlock also addresses the Staff's recommended allocation
8 of the Idaho Irrigation Load Control program costs with
9 respect to the Revised Protocol jurisdictional allocation
10 methodology.
11 Senior Staff Engineer Keith Hessing addresses
12 class cost of service and revenue spread among the classes.
13 Mr. Hessing accepts the Company's class cost of service
14 methodology and recommends that all classes, except the
15 lighting classes, be moved to ful1 cost of service as
16 proposed by the Company. Based on the Staff's recommended
17 revenue requirement, Mr. Hessing recommends class revenue
18 changes ranging from a 3.06% increase for irrigation
19 customers, to a 12.94 % increase for Monsanto. Residential
20 customers will see an increase of 4.78%.
21 Staff Economist Bryan Lanspery addresses power
22 supply expense including the Company's proposed wind
23 integration adj ustment and rate design. Mr. Lanspery
24 recommends that system power supply costs be reduced to
25 reflect removal of uneconomical contracts, modified
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di)
STAFF
1936 7
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1 treatment of non-firm transmission revenue and
2 recalculation of Bear River hydro generation. He also
3 recommends the Company's proposed expense addition to
4 reflect wind integration cost be removed. The basis for
5 this adjustment is his position that even if these costs
6 were known and measurable, they already flow through and
7 are recovered as part of underlying test year expenses or
8 energy cost adjustment mechanisms. The total revenue
9 requirement impact of these adjustments is $2.65 million on
10 an Idaho jurisdictional basis.
11 With respect to rate design, Mr. Lanspery
12 supports the Company's proposal to implement a two tiered
13 commodi ty rate design for Schedule 1, residential
14 customers. Rather than the Company proposed year round
15 first block, Mr. Lanspery proposes seasonal first blocks of
16 900 kWh and 700 kWh for summer and winter, respectively.
17 Mr. Lanspery also proposes a $5 Schedule 1 customer charge
18 rather than the $12 customer charge proposed by the
19 Company. Mr. Lanspery proposes a uniform increase in the
20 rate components for all other customer classes.
21 Staff Utility Analyst Gary Grayson addresses the
22 prudency of 2008 and 2009 DSM expenditures and recommends
23 that they be found to have been prudently incurred.
24 Mr. Grayson also addresses the Company's level of annual
25 DSM expenditures and discusses whether the method of cost
CASE NO. PAC-E-10 - 07
10/14/10 LOBB, R. (Di)
STAFF
81937
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1 recovery through base rates or tariff rider is appropriate.
2 Finally Utili ties Compliance Investigators
3 Marilyn Parker and Curtis Thaden address a variety of
4 consumer issues. Ms. Parker recommends that the Company
6 customer accounts close to eliminate unbilled electrical
5 implement a policy of meter reading and disconnect when
7 consumption. Mr. Thaden addresses the impact of the
8 economy on the customers of the Company and how customers
9 might better cope with increased utility bills.
10 Case Evaluation
11
12
13
14
Q.What has been your role in this case?
A.My role as Utilities Division Administrator is to
oversee the preparation of the Staff case with respect to
identification of issues, coordination of Staff position on
15 those issues and development of Staff policy.
16 Q.What are the important policy issues in this
17 case?
18 A.In my opinion the most important policy issues
19 deal with identifying revenue requirement adjustments,
20 assuring that customer benefits properly match assigned
21 costs and customer rates are properly established.
22 How did Staff take the weakened economy, theQ.
23 impact of rate increases on the Company's customers and
24 customer comments into account in preparing for this case?
25 The impact of rate increases on customers isA.
CASE NO. PAC-E-I0-0710/14/10
1938 9LOBE, R. (Di)
STAFF
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10
1 always a consideration of Staff in the preparation of its
2 case. The Staff objective is to always obtain the best
3 deal possible for customers. With the weakened economy,
4 the expectation of customers and the approach of Staff is
5 to more aggressively evaluate the Company's request.
6 Staff's recommendations on equity return, elimination of
7 salary increases and bonuses and reasonably limiting cost
8 recovery of investment demonstrates this approach.
9 Q.How did Staff identify its adjustments?
A.Staff focused its review on cost of capital,
11 large capital additions and the level of increased
12 operation and maintenance including employee compensation
13
14.
over the last two years. Based on an audit of actual costs
15 increases as compared to economic conditions and a thorough
booked during the test year, an evaluation of expense
16 review of large capital additions, Staff identified costs
17 that it believed were inappropriate.
18 What policy issues fall into the category ofQ.
19 customer benefits matching assigned customer costs?
20 The issues that L believe fall into this categoryA.
21 are the treatment of Idaho Irrigation Load Control program
22 costs and benefits, and the determination of what is "used
23 and useful" with respect to large plant additions. Staff
24 witness Carlock and I will address the treatment of
25 Irrigation Load Control program costs and Staff witness
CASE NO. PAC-E-I0- 07
10/14/10
1939 LOBB, R. (Di) 10
STAFF
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13
14
1 Leckie and I will address the issue of cost recovery
2 associated with the Dunlop I wind project and the Populus
3 to Terminal transmission line , respectively.
4 Q.What are the most important policy issues in this
5 case with respect to rate design?
6 A.I believe there are two important rate design
7 issues in this case. The first is revenue spread to the
8 various customer clasSes and the second is the tiered rate
9 design for Residential Schedule 1 customers. It is
10 important that class revenue requirement reflects class
11 cost of service and rate design reflects cost of service
12 wi thin customer classes. With cost of service in mind and
in response to customer concerns i Staff maintained the
differential between Residential Schedule 1 and Residential
15 Schedule 36. Staff witness Hessing discusses revenue
16 spread and Staff witness Lanspery discusses rate design.
17 Idaho Irrigation Load Control Program
18 Q.Please explain the Idaho Irrigation Load Control
19 program.
20 A.The Idaho Irrigation Load Control program is
21 offered to Idaho irrigation customers receiving retail
22 electric service under Schedule 10. Participants agree to
23 allow the Company to curtail their electricity usage, and
24 in exchange participants receive credits valued on a per kW
25 basis. The Idaho Irrigation Load Control Program is
CASE NO. PAC-E-I0-0710/14/10 1940 LOBB, R. (Di) 11
STAFF
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1
2 scheduled service interruption, whereas Schedule 72A is a
provided under Schedules 72 and 72A. Schedule 72 is a pre-
3 dispatchable service interruption.
4 How many Schedule 10 irrigation customersQ.
5 participate in the program?
6 In 2009 there were 938 customers participating inA.
7 the program, or nearly 46% of those eligible.
8 Q.How many Schedule 10 irrigation customers
9 participate in the dispatchable Schedule 72A option?
10 In 2009 there were 826 customers participating inA.
11 the dispatchable option, or approximately 88% of eligible
12 participants. Most of the customers participate under
13
14
Schedule 7 2A.
15 (Schedules 72 & 72A) grown?
Q. Has the Idaho Irrigation Load Control program
16 A.Yes. According to the Company's annual DSM
17 reports, the program participation has grown as follows:
18
19
20
21
Year
2006
2007
2008
2009
Participation
478
405
609
938
Annual MW
51
78
215
276
Q.How have program costs grown since the Company
22 started reporting results?
23 According to the Company's annual DSM reports,A.
24 program costs have increased as follows:
25
CASE NO. PAC-E-10-0710/14/10
1941 LOBB, R. (Di) 12
STAFF
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7
1
2
Year
2006
2007
2008
2009
Program Cost
$ 1,299,129
$ 2,584,508
$ 8,908,216
$11,114,948
Annual % Increase
3
99%
245%
25%
4
5 Q.Has the Company calculated the system benefit of
6 the Idaho Irrigation Load Control program?
A.Yes. In its 2009 DSM Report, the Company
8 calculates a system benefit value of over $20 million for
9 the Idaho Irrigation Load Control program over ten years.
10 Is the Idaho Irrigation Load Control programQ.
11 deemed to be cost effective?
12
13
14
A.Yes. According to the Company's 2009 DSM report
the Idaho Irrigation Load Control program meets all cost
15 (TRC), the Ratepayer Impact Test (RIM) and the Utility Cost
effectiveness tests including the Total Resource Cost Test
16 Test (UCT).
17 Q.How does the Company propose to treat costs and
18 benefits associated with the Idaho Irrigation Load Control
19 program?
20 A.The Company proposes to directly assign alI $11.4
21 million in program cost to customers in the Idaho
22 jurisdiction. The Company then credits or decrements the
23 Idaho jurisdictional demand allocator used in the
24 allocation of system costs to Idaho. The reduced
25 jurisdictional allocat~on factor, reflecting the demand
CASE NO. PAC-E-I0-0710/14/10
1942 LOBB, R. (Di) 13
STAFF
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1 reducing affect of the Idaho Irrigation Load Control
2 program, benefits Idaho customers by reducing the Idaho
3 jurisdictional revenue requirement.
4 Q.What is the revenue requirement impact of this
5 allocation methodology on Idaho?
6 A.The total proforma cost of the Irrigation Load
7 Control program directly assigned to Idaho is $11.4
8 million. These costs include $7.6 million in program
9 incentive credits paid to customers participating in the
10 Irrigation Load Control program, and $3.82 million in
11 administrative costs. The cost of the incentive payments
12 are recovered through Idaho base rates and the
13 administrative costs are recovered from Idaho customers
14 through the Customer Efficiency Service Rate Adjustment
15 (Schedule 191, tariff rider).
16 The revenue requirement benefit to Idaho is
17 captured by reducing Idaho's jurisdictional allocation of
18 PacifiCorp system costs. This is accomplished by reducing
19 Idaho's share of system demand to reflect the impact on
20 system demand of the Idaho Irrigation Load Control program.
21 When this demand decrement is applied, Idaho's
22 jurisdictionally allocated revenue requirement is reduced
23 by approximately $7.48 million. The net effect is that
24 directly assigned Idaho program costs of $11.4 million
25 exceed allocated Idaho revenue requirement benefits of
CASE NO. PAC-E-10-0710/14/10
1943 LOBB i R. (Di) 14
STAFF
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14
1 $ 7.48 million by approximately $3.9 million a year.
2 Q.Is this reasonable?
3 A.No. Idaho receives a reduction of system costs
4 that equate to a program benefit of approximately 66% ($7.5
5 million/$11.4 million) of the costs. This is unfair when
6 100% of the program costs are directly assigned to Idaho.
7 Q.Does the Company assign any program costs to the
8 system to reflect benefits derived to the system from the
9 Irrigation Load Control program?
10 A.No program costs are directly allocated to the
11 system or other jurisdictions under the Company method.
12 Through the decrement in the demand allocator used to
13 jurisdictionally allocate system costs, other PacifiCorp
15 costs due to the shift in load responsibility. This amount
jurisdictions do receive $7.48 million more in other system
16 represents about 66% .of total Idaho Irrigation Load Control
17 program costs.
18 However, all other PacifiCorp system production
19 costs and thereby production costs avoided by implementing
20 the Idaho Irrigation Load Control Program are normally
21 allocated to jurisdictions other than Idaho at the rate of
22 approximately 94%. Consequently, non Idaho jurisdictions
23 are receiving 94% of the program benefits but only pick up
24 additional system costs equal to 66% of the program costs.
25 How do you propose to treat the Idaho IrrigationQ.
CASE NO. PAC-E-I0-07
10/14/10
LOBB, R. (Di) 15
STAFF
1944
.
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1
2
Load Control program costs?
A.I propose that the Company treat the program
3 costs as system purchase power cost and allocate them just
4 as it would any other system power supply expense. This
5 will assure that the costs allocated to each jurisdiction
6 follow the benefits received by each jurisdiction.
7 How does the Company view the capacity providedQ.
8 from the Idaho Irrigation Load Control program in
9 comparison to existing supply side resources?
10 A.The Company identifies the Idaho Irrigation Load
11 Control program as a Class 1 DSM resource defined as
12 follows:
13
14
15
16
17
18
Class 1 DSM: Resources from fully dispatchable orscheduled firm capacity product offerings/programs -
Class 1 programs are those for which capacity savings
occur as a result of active Company control or
advanced scheduling. Once customers agree to
participate in a Class 1 DSM program, the timing and
persistence of the load reduction is involuntary on
their part within the agreed limits and parameters ofthe program. In most cases, loads are shifted rather
than avoided.
19 The Company goes on to identify Class 1 DSM as a
20 resource type with its other supply side resources in
21 Table 5.6 - Capacity Ratings of Existing Resources, as part
22 of its 2008 IRP.
23 Q.What is the revenue requirement effect of
24 treating Idaho Irrigation Load Control program costs as a
25
CASE NO. PAC-E-10-0710/14/10
1945 LOBB, R. (Di) 16
STAFF
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1 system power supply expense in jurisdictional cost
2 allocation?
3 A.Idaho's net revenue requirement would be reduced
4 by approximately $3.25 million when Idaho Irrigation Load
5 Control program costs previously collected through the
6 tariff rider are included. The reduction in revenue
7 requirement collected from Idaho would be collected from
8 PacifiCorp's other jurisdictions through the dynamic system
9 cost allocation of additional system power supply expenses
10 under the Staff's proposal. This proposed distribution of
11 Class 1 Irrigation Load Control program costs more
12 accurately and fairly matches system benefits with system
13
14
costs.
Q.Does your recommended treatment of the Irrigation
15 Load Control program costs violate the Revised Protocol
16 jurisdictional allocation methodology?
17 I do not believe treating these Idaho IrrigationA.
18 Load Control Class 1 DSM expenditures as system production
19 costs violates the intent of the jurisdictional allocation
20 methodology. The Company views this program as comparable
21 to production resources in its IRP and the size of this
22 program has grown by 300% since Revised Protocol was
23 approved. Moreover, I believe that the magnitude of the
24 program costs relative to the size of the Idaho
25 jurisdiction makes situs cost recovery difficult when
CASE NO. PAC-E-10-0710/14/10
1946 LOBB, R. (Di) 17
STAFF
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13
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1 benefits are based on reduced allocation of unrelated
2 system costs. Staff witness Carlock provides additional
3 testimony regarding treatment of Idaho Irrigation Load
4 Control program costs in conj unction with the Revised
5 Protocol Allocation methodology.
6 Populus to Terminal Transmission
7 Q.What is the Populus to Terminal Transmission
8 line?
9 A.The Populus to Terminal transmission line is the
10 first of eight proposed new high voltage transmission
11 segments that will make up PacifiCorp's Energy Gateway
12 Transmission Expansion proj ect. Energy Gateway consists of
Gateway West, Gateway South and Gateway Central. Populus
15 Central. It is a dual circuit 345 kV, 135 mile long high
to Terminal is one of three segments that make up Gateway
16 vol tage transmission line stretching from Downey, Idaho to
17 Salt Lake City, Utah.
18 What is the cost of the Populus to TerminalQ.
19 project and how does it compare to the overall estimated
20 cost of Energy Gateway and the transmission plant in
21 service of PacifiCorp?
22 The total cost of the 135 mile Populus toA.
23 Terminal project is $802 million. In 2008, the 1700 mile
24 Energy Gateway proj ect was estimated at over $4 billion.
25 In 2010, Energy Gateway is described as a 2000 mile long
CASE NO. PAC-E-I0-0710/14/10
1947 LOBB, R. (Di) 18
STAFF
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10
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12
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1 proj ect at an estimated cost of approximately $6.6 billion.
2 PacifiCorp currently has only $2.2 billion in transmission
3 plant in service.
4 Q.What does the Company request in terms of cost
5 recovery for Populus to Terminal in this case?
6 A.The Company requests that the entire cost of the
7 Populus to Terminal project, or approximately $802 million,
8 be placed in rate base as part of this case.
Q.How does the Company justify construction of the
Populus to Terminal transmission line and including all of
the project cost in rate base in this case?
9
A.The Company describes the Populus to Terminal
transmission segment as a "key element in Gateway Central",
which is described as an "essential reliability backbone
15 allowing Gateway West and Gateway South to operate at a
16 higher reliability and an overall higher capacity". The
17 Company maintains that the Energy Gateway investment will
18 support future generation resource development. Cupparo
19 Di., p. 7, line 8
20 Q. What is the Company's estimated time frame for
21 completion of the Energy Gateway Transmission expansion
22 project?
23 The original estimate in February of 2008 was forA.
24 completion of Gateway South in 2013 and Gateway West in
25 2014. 2010 estimates now show completion of Gateway South
CASE NO. PAC-E-10-0710/14/10
1948 LOBB, R. (Di) 19
STAFF
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.
.
1 in the 2018 to 2020 time frame and Gateway West in the 2014
2 to 2018 time frame.
3 Q.Does the Company provide other justification for
4 its proposed treatment of the Populus to Terminal
5 transmission costs?
6 A.Yes. The Company maintains that the proj ect
7 satisfies a Mid American Energy Holdings Company (MEHC)
8 merger commitment to improve the transfer capability over
9 Path C. The Company also maintains that overall
10 reliability is improved and the Company can cover reserve
11 requirements without building new generation.
12
13
14
What was the commitment by PacifiCorp to improveQ.
transfer capability over Path C as part of the MEHC merger?
15 Commission Order No. 29998 (Case No. PAC-E-05-08) issued in
A. The Path C upgrade commitment as stated in
16 March of 2006 was as follows:
17 Path C UPsrade (-$78 million) ~ Increase Path C
Capaci ty by 300 MW (from S. E. Idaho to Northern Utah) .
18
19
20
21
22
23
24
25
The target completion date is 2010.
. Enhances reliability because it increases
transfer capability between the east and westcontrol areas,
. facilitates the delivery of power from wind
projects in Idaho, and
. provides PacifiCorp with greater flexibility and
the opportunity to consider additional optionsregarding planned generation capacity additions.
Q. As constructed, does the Populus to Terminal
Transmission line simply fulfill the Path C Commitment?
A.No. The Populus to Terminal proj ect was
CASE NO. PAC-E-10-07
10/14/10
1949 LOBB, R. (Di) 20
STAFF
.
.
.
1
2 Gateway Transmission Expansion proj ect. Rather than the
oversized to satisfy the future requirements of the Energy
3 300 MW specified in the MEHC merger commitment, the Populus
4 to Terminal project provides 700 MW of immediate additional
5 capacity and 1400 MW of additional future capacity. Rather
6 than $78 million, the project actually cost $802 million or
7 over ten times the estimated cost identified in the MEHC
8 merger commitment.
9
10
11
12
13
14
15
16
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CASE NO. PAC-E-10-0710/14/10
1950 LOBB, R. (Di) 21
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CASE NO. PAC-E-I0-0710/14/10
1951 LOBB, R. (Di) 22
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CASE NO. PAC-E-I0-0710/14/10
1952 LOBB , R . (D i) 23
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CASE NO. PAC-E-10-0710/14/10
1953 LOBB, R. (Di) 24
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CASE NO. PAC-E-I0-0710/14/10 1954 LOBB, R. (Di) 25
STAFF
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CASE NO. PAC-E-10-0710/14/10 1955 LOBB, R. (Di) 26
STAFF
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.14
1
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3
4
5
6 Q.What is your recommendation in this case for
7 treating the costs of the Populus to Terminal transmission
8 line?
9 A.As Staff stated in its comments filed in
10 Certificate Case No. PAC-E- 08 - 03 i "the actual costs subj ect
11 to recovery from Idaho ratepayers (related to the Populus
12 to Terminal 345 kV transmission line projectJ will not be
13 determined until the proj ect is completed, costs are fully
known and proj ect usefulness is fully quantified." I
15 recommend that 50% or approximately $401 million of the
16 investment in the Populus to Terminal transmission line be
17 allowed in rate base as part of this case and 50% or the
18 remaining $401 million be classified as capacity not yet
19 "used and useful" and placed in plant held for future use.
20 This recommendation is justified based on the undisputed
21 fact that the proj ect is oversized and will not be fully
22 utilized unless or until Energy Gateway is completed.
23 Given the changing economic conditions and the planned
24 delays in completion dates of future Energy Gateway
25 segments, it is unclear and speculative when or if the full
CASE NO. PAC-E-I0-07
10/14/10
1956 LOBB, R. (Di) 27
STAFF
.
.
.
15
1 benefi ts of the Populus to Terminal investment will accrue
2 to Idaho customers.
3 The 50% distribution between rate base and plant
4 held for future use was determined based on a usable
5 capacity of 700 MW out of a total design capacity of 1400
6 MW. Additional justification for the distribution includes
7 a cost per mile that is twice that of the remaining Energy
8 Gateway segments and a standalone economic analysis that I
9 believe overestimates the cost of transmission
10 alternatives. The rate base and revenue requirement impact
11 of this adjustment is presented in the testimony of Staff
12 witness Vaughn.
13 Q. Could you please summarize your testimony on
14 Popul us to Terminal cost recovery?
A.Yes. The Company has made it clear through the
16 testimony of Mr. Cupparo and Mr. Gerrard and responses to
17 numerous production requests that Populus to Terminal was
18 constructed in large part to provide the potential future
19 benefits that only completion of Energy Gateway can
20 ultimately ensure. The capacity oversizing of Populus to
21 Terminal is designed for future use and that oversized
22 portion of the Company's investment is not presently "used
24
23 and useful". Under Idaho Code § 61-502A, rate basing of
25
investment that is not presently "used and useful" in
providing utility service is prohibited. While some of the
CASE NO. PAC-E-I0-0710/14/10
1957 LOBB , R . (D i ) 2 8
STAFF
.
.
.
1 project costs are justified by benefits customers receive
2 today, 50% of the costs incurred do not generate current
3 benefits. It is unfair and inappropriate for current Idaho
4 customers to pay today for benefits that may only become
5 available when Energy Gateway is completed and Populus to
6 Terminal is fully utilized. Therefore, approximately $401
7 million of the Populus to Terminal proj ect costs should be
8 placed in an account containing plant held for future use,
9 Account No. 105.
10 Wind Resource Acquisition
11 Q.Has Staff reviewed PacifiCorp' s acquisition of
12 new wind resources for which it requests cost recovery in
13 this general rate case?
14 A. Yes, under my direction, Staff reviewed four
15 separate wind acquisition processes. First, Staff reviewed
16 acquisition of the Seven Mile HilI, Glenrock, Rolling
17 Hills, Seven Mile Hill II, Glenrock III, High Plains and
18 McFadden Ridge I proj ects. Together, these resources
19 provide a nameplate capacity of approximately 483 MW, and
20 represent an investment by PacifiCorp of $1.04 billion.
21 Acquisition of these resources is consistent with the
22 Company's 200.4, 2007, and 2008 Integrated Resource Plans
23 (IRPs). Staff reviewed the economic analysis conducted by
24 the Company for each of these resources and concluded that
25 each is cost effective and was prudently acquired.
CASE NO. PAC-E-10-0710/14/10 1958 LOBB, R. (Di) 29
STAFF
.
.
.
1 Next, Staff reviewed the Company i s resource
2 acquisitions in the 2008R, 2008R-1, and 2009R Request for
3 Proposal (RFP) process. In the 2008R RFP, PacifiCorp
4 signed a 20-year power purchase agreement (PPA) for the
5 energy and renewable energy credits (RECs) from the 99 MW
6 Three Buttes project. In the 2008R-1 RFP, a 20-year PPA
7 was negotiated for energy and RECs from the 200 MW Top of
8 the World project, and in the 2009R RFP the ILL MW Dunlap I
9 proj ect, a $261 million Company-owned benchmark proj ect,
10 was selected. Staff carefully reviewed all price and non-
11 price analysis conducted by the Company in each RFP
12 process, including a detailed review of the modeling used
13 to evaluate and score all of the short-listed bids
14 submitted under each RFP. In addition to the Company's own
15 analysis, Staff also reviewed all reports prepared by
16 independent evaluators hired to monitor and evaluate the
17 2008R-1 and 2009 RFP processes. In each of those RFP
18 processes, the independent evaluators concluded that the
19 selected proposals represented the resources with the
20 greatest net benefits to customers; that the processes were
21 fair and competitive; that the selected proposals
22 represented the lowest cost al ternati ves for customers,
23 wi th an accounting for risk.
24 Q.What do you conclude based on Staff's review of
25 the wind proj ects?
CASE NO. PAC-E-10-0710/14/10
1959 LOBB, R. (Di) 30
STAFF
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.
.
1 A.Based on Staff i s review, I conclude that all of
3 that are Company-owned and those for which the output is
2 the new wind resources acquired by PacifiCorp, both those
4 purchased under PPAs i were competitively acquired, are
5 consistent with Company IRPs i and are prudent. Costs for
6 acquisition of each Company-owned project should be allowed
7 to be included in rate base, and costs associated with each
8 of the PPAs should be included in the Company i s revenue
9 requirement.
10 Q.Does this conclude your direct testimony in this
11 proceeding?
12
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21
22
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24
25
A.Yes, it does.
CASE NO. PAC-E-10-0710/14/10 1960 LOBB , R . (D i ) 3 1
STAFF
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.
20
21
22
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Mr. Purdy, do you have
4 questions for Mr. Lobb?
5 MR. PURDY: I do not.
6 COMMISSIONER SMITH: Mr. Williams.
7 MR. WILLIAMS: No.
8 COMMISSIONER SMITH: Mr. Olsen.
9 MR. OLSEN: No, Madam Chair.
10 COMMISSIONER SMITH: Mr. Otto.
11 MR. OTTO: No questions.
12 COMMISSIONER SMITH: Mr. Budge.
13 MR. SMITH: Has no questions.
14 COMMISSIONER SMITH: From the Company.
15 MR. HICKEY: Yes. Thank you, Madam Chair.
16
17 CROSS-EXAMINATION
18
19 BY MR. HICKEY:
Q.Good afternoon, Mr. Lobb.
A.Good afternoon.
Q.I want to focus on the analysis that you did of
23 the cost of the Gateway project, and I'd like to begin by just
24 trying to establish Populus to Terminal is not Central Gateway,.25 is it?
1961
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (X)Staff
.
.
.
1 No, it's not. It's one of three segments, IA.
2 believe.
3 Thank you. So any suggestion that CentralQ.
4 Gateway is embodied or encompasses -- strike that. That's a
5 poor question.
6 There are two separate concepts. As you just
7 said, Populus to Terminal is only a part of Central Gateway.
8 Which is a part of Energy Gateway.A.
9 Yeah. And so against that backdrop, to talkQ.
10 about the cost of Populus to Terminal, you were here, weren't
11 you, sir, when Mr. Gerrard testified yesterday about the
12 70-some percent of Populus to Terminal that is actually in
13 use?
14 I was here and heard Mr. Gerrard's testimony,A.
15 yes.
16 Okay. Would you agree with the generalQ.
17 proposi tion that any transmission resource that is prudently
18 and properly planned and developed should have some additional
19 capaci ty beyond the in-service date needed capacity?
20 Well, in this case generally, I would agreeA.
21 with that, but in this case, the extra capacity, according to
22 the Company, is not made available until the other segments
23 Gateway West and Gateway South are completed.
24 Okay. Am I correct, sir, that you've not done anQ.
25 independent cost analysis to determine whether it would be more
1962
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (X)Staff
.
.
.
1 or less costly for customers to build a Populus to Terminal as
2 sized to alternative -- as sized to an alternative, building
3 less capacity now and adding later capacity in the future?
4 I have not done an independent analysis, no.A.
5 Q.Do you recall the Staff asking a Data Request to
6 compare the cost per mile of the Camp Williams-90th South line
7 to the cost per mile of the Populus-Terminal line?
8 A.Yes, I did.
9 And that the result of that analysis was that theQ.
10 11 miles of this we'll call it Camp Williams double circuit
11 345 kV line came in at a million, six fifty -- a million, seven
12 less than the Populus to Terminal line? Would you agree?
13 I don't have that Data Request before me.A.
14 I've marked it as Exhibit 93 and you'll have itQ.
15 in your hand in a minute, Mr. Lobb.
16 (Rocky Mountain Power Exhibit No. 93 was
17 marked for identification.)
18 BY MR. HICKEY: I'll give you a minute to look atQ.
19 it, and then when you're ready to take a couple of questions on
20 it, please let me know.
21 I i m familiar. I have reviewed it.A.
22 Okay. So with the advantage and benefit ofQ.
23 Exhibit 93 in front of you, is my approximation of the million,
24 seven accurate as the difference in a cost per mile that was
25 looked at in the top, upper half anyway of the first page of
1963
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (X)Staff
.
.
.
1 Exhibit 93?
2 A.According to the Data Request, it's about a
3 million, seven per mile difference in the two proj ects.
4 Q.And then doesn't the balance of this Data
5 Response go on to address what were identified as several
6 significant differences between the two proj ects that
7 contribute to the cost per mile variance?
8 A.Yes. The Company goes on and explains why they
9 believe the cost is different between the two.
10 Q.And wouldn't you agree that you'd have to kind of
11 unpack what was involved in the miles of Camp William as
12 opposed to the miles of Populus to Terminal to really
13 understand why some cost differences might exist?
14 A.True, I could agree that there are cost
15 differences between two separate and distinct proj ects located
16 in geographically-distinct areas.
17 Q.Sure. Maybe by way of an analogy if you let me
18 use an area I have some familiarity with, to put a four-lane
19 road through an area south of Yellowstone National Park that
20 will get out of the hands of the Federal government to say you
21 could even put a four-lane highway through there would cost
22 presumably more because of the mountainous terrain and the
23 drainages that would be involved than somewhere in Southern
24 Idaho or Southern Wyoming that might be a less tough topography
25 to locate a road in. Those costs are going to differ, aren't
1964
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (X)Staff
.
.
20
21
1 they, per mile?
2 A.Sure, I would agree with that.
3 So would you agree that the Company has fairlyQ.
4 identified some of the distinctive differences that drove cost
5 in Populus-Terminal that weren't a part of the Camp Williams
6 double circuit proj ect?
7 A.I think I could agree that there are cost
8 differences between the two proj ects, yes.
9 Q.Thanks.
10 MR. HICKEY: If I could have just a minute.
11 COMMISSIONER SMITH: Certainly.
12 MR. HICKEY: I have no further questions, thank
13 you.
14 COMMISSIONER SMITH: Do we have questions from
15 the Commission?
16 COMMISSIONER REDFORD: No.
17 COMMISSIONER KEMPTON: No.
18 COMMISSIONER SMITH: Any redirect, Mr. Woodbury?
19 MR. WOODBURY: Yes. May I approach the witness?
COMMISSIONER SMITH: You may.
MR. WOODBURY: I would -- I i II hand what will be
22 Staff Exhibit 133.
23 (Staff Exhibit No. 133 was marked for
24 identification.)
4t 25
1965
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (X)Staff
.
.
.
20
1 REDIRECT EXAMINATION
2
3 BY MR. WOODBURY:
4 Q.Mr. Lobb, I've handed you what I've identified as
5 Staff Exhibit 133. Are you familiar? Can you identify this?
6 A.Yes. It's a cover page to a February 2009 report
7 from the Ernest Orlando Lawrence Berkeley National Laboratory
8 entitled The Cost of Transmission for Wind Energy: A Review of
9 Transmission Planning Studies.
10 And the second page is Table 4, range of
11 equipment cost assumptions for transmission lines.
12 Q.Okay. And this was the same study that was
13 identified yesterday and in Staff's cross-examination of
14 Mr. Gerrard?
15 A.Yes, it is.
16 Q.And regarding the cost of transmission projects,
17 have you reviewed the underlying report from which this is an
18 excerpt?
19 A.Yes, I have.
Q.And what does Table 4 on page 2 of the exhibit
21 depict?
22 A.The report reviews 40-some regional transmission
23 studies to identify the cost generally associated with wind but
24 recognize that transmission will be required for new resources,
25 and to identify what type of costs could be expected. And so
1966
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (Di)Staff
.
.
.
1 the table shows the results of those studies, the minimum cost
2 estimates -- per-mile cost estimates for various size of high
3 vol tage transmission lines, and then the maximum cost per mile
4 for those same transmission proj ects. And it also shows the
5 number of samples that used the -- that included the various
6 transmission voltages.
7 I refer to the in the middle of the page,
8 Column 1 is the 245 (sic) kV double circuit, which is the same
9 transmission configuration of Populus to Terminal, and it shows
10 minimum cost of one million per mile to a maximum cost of 2.3
11 million.
12 COMMISSIONER SMITH: Did you mean to say "345"?
13 THE WITNESS: 345 kV, sorry, double circuit,
14 that's correct.
15 Q.BY MR. WOODBURY: And what is the maximum cost of
16 all of the projects identified in that table per mile?
17 A.What is the maximum cost of what?
18 Q.Yeah, what is the highest cost of all of the
19 proj ects identified in this table?
20 A.The highest cost is the high voltage DC undersea
21 cable at four million per mile.
22 Q.Okay.
23 MR. WOODBURY: Madam Chair, Staff would have no
24 further redirect.
25 COMMISSIONER SMITH: Okay. Mr. Lobb, thank you
1967
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LOBB (Di)Staff
.
.
1 for your help.
2 (The witness left the stand.)
3 MR. WOODBURY: Madam Chair, Staff's next witness
4 is Joe Leckie.
5
6 JOE LECKIE,
7 produced as a witness at the instance of Staff, being first
8 duly sworn, was examined and testified as follows:
9
10 DIRECT EXAMINATION
11
12 BY MR. WOODBURY:
13 Q. Mr. Leckie, please state your full name and spell
14 your last name for the record.
15 A.My name is Joe Leckie.
16 Q.And for whom do you work and in what capacity?
17 A.I am an accountant for the Idaho Public Utili ties
18 Commission.
19 Q.And your last name is a challenge. Could you
20 spell your last name?
21
22
A.L-E-C-K-I-E.
Q.And in that capacity at the Public Utili ties
23 Commission, did you have occasion to prepare prefiled testimony
24 in this case consisting of 14 pages and three exhibits, 101.25 through 103?
1968
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (Di)Staff
.
.
.
1 A.Yes, I did.
2 Q.And that testimony was filed on October 14th, and
3 is it necessary to make any changes to that testimony?
4 A.Yes, there is.
5 Q.It is?
6 A.Yes. Based on the rebuttal testimony from the
7 Company--
8 Q.No. Are you making changes to your testimony or
9 do you wish to provide a --
10 There aren't any changes to the testimony that
11 you filed on October 14th; that is correct as it was filed on
12 that date?
13 A.Yes, on that date.
14 Q.And as a result of reviewing the rebuttal
15 testimony of the Company, is there any way that we could
16 perhaps segue into your cross-examination which might alleviate
17 some subquestions?
18 A.Yes.
19 Q.And could you --
20 A.Based on the rebuttal testimony of Mr. McDougal,
21 I did not have the depreciation expense correct on the rate
22 base adjustment that I made for the changes in in-service dates
23 and changing cost for the 2010 projects; and I went back
24 through and calculated that, and my calculation agrees with
25 Mr. McDougal's calculation in his rebuttal Exhibit 78.
1969
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (Di)Staff
.
.
.
22
1 Addi tionally, the accumulated depreciation
2 adj ustment for that corrected depreciation amount is correctly
3 stated in Mr. McDougal's exhibit.
4 Q.Okay.
5 A.Addi tionally, I looked at the testimony of
6 Ms. Crane on the coal pile adj ustments that I made. She had
7 indicated that there were four coal piles that were
8 interrelated. And, in fact, based on my knowledge of those
9 particular coal piles, she's correct that they are interrelated
10 and that they should not be looked at separately. Those coal
11 piles are the Carbon, Huntington, Deer Creek, and Rock Garden.
12 So I went back through and aggregated those and
13 came out with a net change in coal pile ton, and then I
14 mul tiplied that net change by the lowest cost of those coal
15 piles to come out with a corrected amount for that coal pile
16 adj ustment. And the corrected amount for the coal pile
17 adjustment is instead of the 15,970,759, is $9,554,206.
18 COMMISSIONER SMITH: And although that -- those
19 numbers appear on yellow paper, that number is not secret?
20 THE WITNESS: That particular number isn't.
21 COMMISSIONER SMITH: Okay.
Q.BY MR. WOODBURY: What page do those numbers
23 appear on?
24
25
A.That comes on page 6 of my testimony.
COMMISSIONER SMITH: I was looking at
1970
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (Di)
Staff
.
.
.
1 Exhibi t 102.
2 THE WITNESS: Yeah. And you'd have to actually
3 ask the Company, but I believe the actual inventory tonnage and
4 the cost per ton are the elements that are confidential.
5 COMMISSIONER SMITH: Okay. Thanks. Could you
6 state that number once more, please?
7 THE WITNESS: So instead of the 15,970,759
8 COMMISSIONER SMITH: That's on line 17.
9 THE WITNESS: That's -- yes.
10 -- it should be 9,554,206.
11 And then --
12 COMMISSIONER SMITH: It's also on line 19.
13 THE WITNESS: Yes, those.
14 And then on line 23 of that same page, I
15 indicated that there were reductions to six coal fuel
16 stockpiles. Because of the aggregation of the others, that
17 should be four coal fuel stockpiles.
18 Then there is one other area, and that is in the
19 rebuttal testimony of Mr. McDougal. He addresses the issue of
20 the bonus depreciation, and Staff accepts his and Company's
21 recommendations in regards to that bonus depreciation.
22 Q.BY MR. WOODBURY: And does that complete your
23 corrections?
24
25
A.That completes.
MR. WOODBURY: Madam Chair --
1971
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (Di)Staff
.
.
20
21
22
23
24
. 25
1 Q.BY MR. WOODBURY: If I were to ask you the
2 questions set forth in your testimony, would your answers be
3 the same as of the date that you filed it?
4 A.Wi th those changes, yes.
5 MR. WOODBURY: And, Madam Chair, I'd present
6 Mr. Leckie for cross-examination, and I'd ask that his
7 testimony be spread on the record and Exhibits 101 through 103
8 be identified.
9 COMMISSIONER SMITH: If there i s no obj ection, the
10 testimony will be spread with the changes noted, and the
11 exhibits will be identified.
12 (The following prefiled direct testimony
13 of Mr. Leckie is spread upon the record.)
14
15
16
17
18
19
1972
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701 LECKIE (Di)Staff
.
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Joe Leckie. My business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
I am employed by the Idaho Pulic Utilities6A.
7 Commission (Commission) as a senior auditor in the
8 Utilities Division.
9 Q.What is your educational and experience
10 background?
11 A.I graduated from Brigham Young University with a
12 Bachelors of Science degree in Accounting. I worked for
13 the accounting firm Touche Ross in its Los Angeles office
14 for approximately one year. I then attended law school
15 and graduated from the J. Rueben Clark School of Law at
16 Brigham YoungUni versity with a Juris Doctorate degree. I
17 am licensed to practice law in the State of Montana and
18 practiced there for approximately 25 years. I have been
19 employed at the Commission as an auditor since March 2001.
20 I have attended the annual regulatory studies program
21 sponsored by the National Association of Regulatory
22 Utility Commissioners (NARUC) at Michigan State University
23 in August of 2001. I have attended several other training
24 courses sponsored by NARUC on regulatory accounting and
25 auditing.
CASE NO. PAC-E-10-07
10/14/10
1973 LECKIE, J. iDi~ 1
STAFF
.
.- .
.
1 Q.Would you please summarize your contribution to
2 Staff's recommendations in those areas of the rate case
3 that you personally reviewed?
4 A.I personally reviewed a broad cross section of
5 the Company's investments and expenses, and I recommend
6 the following adjustments effecting revenue requirement:
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
4 )
5 )
1)Removal of $33,976,054 (system) from Company
adjusted rate base to account for the
differences in the cost and in-service dates of
the 2010 capital addition r~quested by the
2 )
Company.
Removal of $15,970,759 (system) from rate base
to reduce the value of the Company's coal fuel
stockpile inventory.
3 )Removal of $1,000,000 (system) from the
Company's rate base for a portion of the cost of
the Dunlap I Wind Proj ect . It is the portion of
the Dunlap Ranch land that is not currently used
and useful.
Removal of $240,497 (system) from rate base to
properly account for liquidated damages received
by the Company associated with the 2009 Bridger
Unit #2 overhaul.
Removal of $662,119 (system) of incremental O&M
expenses claimed by the Company for future
1974CASE NO. PAC-E-l0-0710/14/10 LECKIE, J. (Di5 2
STAFF
.
/~\,.
.
1 operation of the High Plains, McFadden Ridge I,
and Dunlap I wind facilities.2
3 6 )I additionally reviewed the Company's proposal
to establish a regulatory asset or liability4
5 resulting from the Company's accounting change
6 regarding the deductibility of capital repairs
7 for tax purposes. The Company also wants to
8 normalize income tax expenses. I support the
9 Company proposal on both issues.
Are your adjustments shown and included in10Q.
11 Staff's proposed revenue requirement?
12 A.All of my adjustments are included in Staff's
13 proposed revenue requirement as shown in Staff witness
14 Vaughn's Staff Exhibit No. 108.
15 Q.Would you please explain your recommendation to
16 remove $33,976,054 (system) from the Company's adjusted
17 rate base?
18 A.In the ini tial f i i ing by the Company, rate base
19 included not only plant placed into service by the Company
20 though December 31, 2009 (the end of the test year) ¡but
21 also plant that was expected to be placed into service by
22 December 31, 2010. The total plant expected to be placed
23 into service in 2010 was $1,852,283,166. See Company
24 witness McDougal, Exhibit 2, page 8.6.2. Staff reviewed
25 these projects and requested that the Company update the
CASE NO. PAC-E-10-0710/14/10
1975 LECKIE, J. (Di) 3
STAFF
.
.
.
1 dollar amounts and the expected in-service dates for each
2 proj ect. The Company provided the information for Staff's
3 Exhibit No. 101. The updated information indicated that
4 some in- service dates changed and that the forecasted cost
5 for some proj ects also changed. The difference between
6 the updated cost and the original forecasted cost is in
7 Column (h) "Change in Cost" of the Exhibit. The total of
8 all the updated costs is $1,818,307,112 (Column (g)). The
9 difference between the original cost and the updated cost
10 is $33,976,054 (Column h). Staff has included this amount
11 as an adjustment reducing the Company's rate base.
12 The $33,976,054 is a Company system total.
13 Idaho's share of this amount is $2,031,303.
14 Q. Does this reduction in rate base have any effect
15 on the depreciation expense?
16 A.Yes, depreciation expense on a total Company
17 basis is reduced by $875, 226 and Idaho's share of the
18 depreciation expense reduction is $52,583. Also,
19 accumulated depreciation is reduced by the same amounts.
20 Q.Please summarize the adjustment to the coal fuel
21 stockpile the Company described in its Application as an
22 adjustment to Miscellaneous Rate Base.
23 A.The Company increased coal fuel stockpile in
24 Account 151, Fuel Stock, by $24,644,591 on a system basis
25 with $1 1581,176 allocated to Idaho. The Company stated
CASE NO. PAC-E-10-0710/14/10
1976 LECKIE, J. (Di) 4
STAFF
.
.
.
1 that this increase was due to the cost of coal and the
2 number of tons stored at each site (McDougal direct
3 testimony at page 33, lines 4 - 5. )
4 Q.Did you examine the increase in coal fuel
5 stockpile proposed by the Company?
6 A.Yes. In response to Confidential Audit Request
7 dated April 27, 2010, the Company provided a schedule of
8 fuel stockpile values and tons at each plant. I used this
9 schedule to estimate the average cost per ton for each
10 stockpile at each plant as of Decembe~ 31, 2010. See
11 Staff Confidential Exhibit No. 102, Column (f). The
12 average cost per ton is the Dec-2010 projected coal
13 stockpile cost, Column (e) divided by the pro forma
14 tonnage, Column (d). The average cost per ton was
15 compared to the cost per ton of contracted coal for each
16 plant and found to be a reasonable cost per ton for
17 valuing the total value of the stockpile.
18 Q.Since you agree with the Company on the average
19 cost per ton of each stockpile, do you also agree with the
20 Company on the increase in tonnage of the stockpiles as
21 proposed by the Company for each location?
22 A.No. As shown in Staff Confidential Exhibit
23 No. 102, Column (g), there were some noticeable changes in
24 the stockpile tonnage at the different plant sites with a
25 significant tonnage increase at several plants. The
CASE NO. PAC-E-I0-0710/14/10
1977 LECKIE, J. (Di) 5
STAFF
.
.
.
1 Company provided no acceptable explanation or
2 justification for these increases. Therefore, Staff
3 believes the tonnage of the stockpiles should be no
4 greater than the 2009 actual tons level, Staff
5 Confidential Exhibit No. 102, Column (b).
6 In determining the value of each sites'
7 stockpile, if the stockpile increased in tonnage
8 between 2009 and 2010, the 2009 actual tonnage is used.
9 (See Confidential Exhibit 102, Column (b)). The 2009
10 tonnage is then valued at the average _cost per ton as of
11 December 31, 2010. Column (b) is multiplied by Column (f)
12 to determine the value of Staff's Stockpile Values in
13 Column (i). If the stockpile decreased in tonnage
14 between 2009 and 2010, the 2010 tonnage and dollars are
15 used.(See Confidential Exhibit No. 102, Columns (d)
16 and (e)). The Company's stockpile value of $188,279,981,
17 Column (e) is $15,970,759, Column (j) more than Staff's
18 stockpile value of $172,309,222, Column (i). Therefore,
19 Staff is recommending a $15,970,759 reduction to the
20 Company's rate base on a system basis, and an allocated
21 reduction to the Idaho rate base of $1,015,344.
22 Q.Staff Exhibit No. 102, Column (h) shows
23 reductions to six coal fuel stockpiles. Does your
24 adjustment accept the Co~pany' s 2009 to 2010 tonnage
25 reductions for these six stockpiles?
CASE NO. PAC-E-10-0710/14/10
1978 LECKIE, J. (Di) 6
STAFF
.
.
.
1 A.Yes. The reduction of stockpile size was a
2 decision made by the Company. Staff's adjustment only
3 questions the necessity of increasing the tonnage size of
4 the stockpiles from 2009 actuals to 2010 pro formas. The
5 customers should receive the benefit of the Company's
6 ability to operate the six coal sites at the reduced
7 tonnage levels; but should not bear the cost of the
8 increase tonnage without just and reasonable cause for the
9 increase.
10 Q.Why have you recommended that the rate base for
11 the Dunlap I Wind Project be reduced by $1,000, OOO?
12 A.The Dunlap I Wind Proj ect was constructed on
13 real property purchased by the Company in 2008 and
14 referred to as Dunlap Ranch. The original property
15 included deeded property of approximately 15,000 acres
16 or 23 sections of land and the right to lease one
17 additional section plus two (2) smaller portions of
18 property owned by the State of Wyoming. The Company also
19 has leased two sections of property owned by the United
20 States Bureau of Land Management (BLM). The Company used
21 the deeded property for the placement of the Dunlap I Wind
22 Project which consists of 74 wind tower sites. The State
23 of Wyoming land was crossed by the transmission line
24 serving the wind generators but no generators were sited
25 on either the State of Wyoming or the BLM land. The 74
CASE NO. PAC-E-10-07
10/14/10
1979 LECKIE, J. (Di) 7
STAFF
.
.
.
13
14
15
16
17
1a
19
20
21
22
23
24
25
1 sites use property from only 10 of the 23 sections of land
2 that was purchased. The. transmission facilities are
3 located on 5 of the 23 sections purchased. This leaves 8
4 sections of land without any generation or transmission
5 facility within its 640 acres. Additionally, one section
6 only has 2 generation sites located on it and these are
7 located in the upper north east corner occupying less than
a 20 acres.
9 Staff recognizes that not all property will be
10 equally suitable for the placement of _wind generation, and
11 that there may be other restrictions on the property that
12 would curtail the number of .wind generation sites.
However, it appears to S taf f that some of the land
purchased is not currently used and useful in providing
utility service. Idaho Code § 61-502A.
The Company included in rate base the entire
purchase price for the Dunlap Ranch as used and useful,
and as part of the cost for the Dunlap I wind facility
(the purchase price for the Dunlap Ranch is in Company's
Confidential Responses to IPUC Production Request iaO).
Page 1 of the Agreement to Sell and Purchase is shown as
Confidential Exhibit No. 103, page 1. Staff is
recommending that $1.0 million of that purchase price be
excluded from rate base at this time and put into
Account 105, Property Held for Future Use.
CASE NO. PAC-E-10-0710/14/10
1980
LECKIE, J. (Di) a
STAFF
.
.
.
1 Q.You are recommending that the total Company's
2 rate base be reduced by $240,497 to properly account for
3 liquidated damages received by the Company as part of
4 the 2009 Bridger Unit #2 overhaul. What are your reasons
5 for this recommendation?
6 A.The Company contracted to overhaul Bridger
7 Unit #2 in 2009. As part of that overhaul, the contractor
8 doing the overhaul became liable to the Company for
9 $625,000 in liquidated damages. After the overhaul was
10 completed, the Company accounted for the repairs to
11 Unit #2 by capitalizing the complete cost of the overhaul
12 and adding the complete cost. to rate base.
13 The Company accounted for the liquidated damages
by reducing the cost of other jobs the contractor was
15 doing. An amount of $264,254 was accounted for as a
14
16 credit against the total cost of repairs to the Bridger
17 Uni t #1 Reheater. The balance of the liquidated damages
18 was credited to other various smaller repairs and are not
19 included in the accounting for any of the proj ects
20 included by the Company in this case.
21 The appropriate accounting for the liquidated
22 damages should have been to reduce the total cost of the
23 Bridger Unit #2 overhaul by $625,000. Since the Bridger
24 Unit #1 Reheater project is part of the 2010 capital
25 proj ects included by the Company in rate base for this
CASE NO. PAC-E-10-07
10/14/10
1981 LECKIE, J. (Di) 9
STAFF
.
.
.
1 case, the credit of $264,254 applied to the total cost of
2 this project undervalues its total cost.
3 The matching principles of accounting require
4 the total liquidated damages of $625,000 be credited to
5 the total cost of the Unit #2 overhaul, and a reduction to
6 the amount included in rate base. With the total amount
7 of the damages credited to the Unit #2 overhaul, the total
8 cost of Unit #1 Reheader should not have received a credit
9 of $264,254. Therefore, the total cost of Unit #1
10 included in rate base should be increased by $264,254.
11 The difference between these two changes of $360,746 is a
12 reduction in the Company's accounting for these two
13 projects.
14 The Company owns two thirds (2/3) of the Jim
15 Bridger facility, therefore the Company's rate base should
16 be reduced by 2/3 of the reduction of $360,746. This
17 equals a total reduction in the Company's rate base
18 of $240,497 (system).
19 Q.Will this reduction in the Company's rate base
20 request have any effect on the total Company's
21 depreciation expense and accumulated depreciation?
22 A.Yes, the rate base reduction of $240,497 will
23 reduce the depreciation expense by $5,690 (system). The
24 composite depreciation rate for this capital expense
25 is 2.366%. Accumulated depreciation is also reduced by
CASE NO. PAC-E-10-0710/14/10
1982 LECKIE, J. (Di) 10
STAFF
.
.
.
1 this same amount.
2 Q.Why have you recommended that $662,119 be
3 reduced from the Company's request for an increase in its
4 operation and maintenance expenses (O&M expense)?
5 A.The Company has requested an increase in its O&M
6 expenses in the amount of $7,333,392 (system) to cover its
7 anticipated increase in O&M expenses for the following
8 facilities: High Plains Wind, McFadden Ridge I Wind,
9 Dunlap I Wind, Wind Administration, DJ Scrubber. The
10 individual amounts requested for each ..facility are in
11 Exhibit No. 2 of Company witness McDougal's testimony,
12 page 4. 6 . These increases are intended to capture the
13 increase in costs to qperate these facilities that were
recently placed in service. Some of the increases in14
15 costs are due to contractual obligations that become
16 effective in 2010 and are not included in the case. These
17 contractual obligations are for land lease payments, plant
18 maintenance, weed control, pest control, and road and
19 vehicle maintenance. The Company is legally obligated for
20 each of these payments and the actual amount of the
21 expenses is capable of being determined. I have
22 determined that these contractual expenses are an
23 acceptable known and measurable increase in the test year
24 expenses.
25 The other increases in expenses claimed by the
CASE NO. PAC-E-10-0710/14/10
1983 LECKIE, J. (Di) 11
STAFF
.
.
.
1 Company are budgeted amounts for "labor, employee expense,
2 and electrical parts, breakers, fuses i filters, gaskets,
3 gear oils, propane etc." These expenses are not
4 sufficiently known and measurable and should not be
5 included in the Company's test year expenses. The Company
6 has not shown that the 2009 test year expenses are
7 insufficient to cover these costs.
8 Staff in Exhibit No. 103, page 2, shows the
9 specific increases proposed by the Company with the
10 removal of those expenses that are not known and
11 measurable.
12 Staff Exhibit No. 103, page 2, details the
13 difference between the Company's total O&M request and
Staff's recommendation. That difference of $662,11914
15 (system) is a reduction to the Company's total requested
16 revenue requirement.
17 Q.What is your assessment of the Company's request
18 to establish a regulatory asset or liability for interest
19 paid to or received from the Internal Revenue Service
20 (IRS) on adjustments made to the repairs deductions taken
21 in the Company's 2008 and 2009 federal income tax returns?
22 A.The Company is asking to have a regulatory asset
23 or liability account established for any changes in taxes
24 and the interest it may receive or be liable to pay for
25 changes in the repair deductions it is taking in its 2008
CASE NO. PAC-E-10-07
10/14/10
1984 LECKIE, J. (Di) 12
STAFF
.
.
.
1 and 2009 income tax returns with the IRS. Because of the
2 change it is implementing in the repair deduction, and as
3 explained in Company witness Fuller's testimony
4 (pages 2 - 6) there is the potential for either a refund
5 with interest for overpayment of taxes or a cost with
6 interest for underpayment of taxes. The final outcome is
7 subj ect to a subsequent review and determination of the
8 Company's repair deduction by the IRS. The establishment
9 of the regulatory asset or liability accounts will allow
10 the Company to track what the refund/çost will be and then
11 include that refund/cost in the next rate case. Staff
12 supports this accounting treatment. It allows the
13 customers to receive the benefit of any refund, and
14 protects the Company from any cost that may result from an
15 IRS audit.
16 Staff recommends that no interest accrue on
17 either the regulatory asset or liability account between
18 the time any refund or cost is determined and the matter
19 is considered in a rate case.
20 Q.The Company also requested Commission approval
21 of its proposal to move to full normalization treatment of
22 income taxes for purposes of setting rates. What is
23 Staff's recommendation on this change?
24 A.Staff agrees that the Company's income taxes
25 should be fully normalized. The Company's analysis of the
CASE NO. PAC-E-10-0710/14/10
1985 LECKIE, J. (Oi) 13
STAFF
.
.
.
1 reasons for such a change are in Company witness Fuller's
2 testimony (pages 6-11). Witness Fuller, in his testimony,
3 clearly provides reasonable justification for the
4 Commission's approval. The primary justification from
5 Staff's perspective is that the full normalization of
6 income taxes matches the tax benefits and the tax burdens
7 of the tax liability with the customers paying the
8 associated costs. Normalization allows all ratepayers to
9 receive benefits from an asset at the same effective tax
10 rate.
11 Q.Does this conclude your direct testimony in this
13
12 proceeding?
14
15
16
17
18
19
20
21
22
23
24
25
A.Yes, it does.
CASE NO. PAC-E-10-0710/14/10
~986 LECKIE i J. (Di) 14
STAFF
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER SMITH: Mr. Purdy, do you have
4 questions?
5 MR. PURDY: No, I don't.
6 COMMISSIONER SMITH: Ms. Davison.
7 MS. DAVISON: No.
8 COMMISSIONER SMITH: Mr. Olsen.
9 MR. OLSEN: No, ma'am.
10 COMMISSIONER SMITH: Mr. Otto.
11 MR. OTTO: No questions.
12 COMMISSIONER SMITH: Mr. Budge.
13 MR. BUDGE: No.
14 COMMISSIONER SMITH: From the Company?
15 MR. SOLANDER: Yes, please.
16 COMMISSIONER SMITH: Mr. Solander.
17
18 CROSS-EXAMINATION
19
20 BY MR. SOLANDER:
21
22
23
Q.Good afternoon.
A.Thank you.
Q.Have you ever been involved in developing or
24 siting a wind proj ect?
25 A.No.
1987
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (X)Staff
.
.
.
20
1 Q.You would agree though that not all property will
2 be equally sui table for placement of wind generation. I
3 believe that's your testimony?
4 A.Yes. Yeah, that's in my testimony.
5 Q.Does that recognition apply equally to land
6 whether it's under lease or ownership?
7 A.Yes.
8 Q.And have you ever done any analysis between a
9 cost associated with leasing property for the purpose of
10 developing a wind proj ect and the cost of buying property
11 A.No.
12 Q.-- for the purpose of developing?
13 You would agree that there are typically
14 environmental, geotechnical, land use, or other restrictions on
15 the development and permitting of a wind proj ect?
16 A.Yeah, there could be.
17 Q.And you would agree that constructing and
18 operating a wind facility in compliance with those restrictions
19 would be required and would be in the public interest?
A.Excuse me. The Company, as it obtained its
21 permi ts, would have to deal with those kinds of restrictions.
22 Q.And did the Company provide you with any evidence
23 in responsive Data Requests for your own investigation that
24 would indicate that it's not operating the Dunlap wind project
25 in compliance with the applicable permits?
1988
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (X)Staff
.
.
.
19
20
1 A.No.
2 Q.Are you aware of any evidence that the Company
3 did not have a reasonable expectation a cost-effective
4 generation resource could be placed on the Dunlap ranch?
5 A.No.
6 Q.Even if the exact placement of the turbines was
7 not known?
8 A.No.
9 Q.Would you agree that the Dunlaps were not seeking
10 to sell their property in individual parcels, but wanted to
11 sell it intact, as one piece?
12 A.I don't have any information from the Dunlaps. I
13 heard that from the Company.
14 Q.And you don't dispute that?
15 A.No.
16 Q.If the Company had leased the Dunlap ranch
17 instead of buying it, would you still have performed a used and
18 useful assessment on that property?
A.Yes.
Q.Do you know how much of PacifiCorp' s wind
21 projects placed in service since 2006 are located on leased
22 land versus Company-owned land?
23 A.I don't know the exact. I know of two
24 Company-owned sitings.
25 Q.Glenrock and Dunlap?
1989
HEDRICK COURT REPORTING
P. O.BOX 578, BOISE, ID 83701
LECKIE (X)Staff
.
.
.
1 A.Yeah.
2 So that would be four total wind proj ects: ThreeQ.
3 at Glenrock and one at Dunlap?
4 A.Yes.
5 And do you know how many wind proj ects theQ.
6 Company included in this case?
7 A.One: Dunlap.
8 I mean total, not that are -- that are includedQ.
9 in the rate base in this case, total overall.
10 Oh, you mean in the overall rate base?A.
11 Right.Q.
12 No, I don't know that number.A.
13 Did you express a concern for the used andQ.
14 usefulness of land rights associated with any of the other wind
15 proj ects presented in this case other than Dunlap?
16 No, I did not.A.
17 Do you feel that it's reasonable for the CompanyQ.
18 to expend costs to maintain, operate, and administer new wind
19 proj ects without those rates being included in rates?
20 Would you say that again?A.
21 Sorry. I know, I'm trying to slow down even forQ.
22 the court reporter.
23 Do you feel that it's reasonable that the Company
24 expend costs to maintain, operate, and administer three new
25 wind projects without those costs being included in rates?
1990
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (X)Staff
.
.
.
1 A.Well, I think any of those costs are subj ect to
2 examination as to determine whether they're reasonable, whether
3 they're used and useful, so there -- whether or not the Company
4 expended them is not the key determinant as to whether they
5 should be included in rate base.
6 Q.But do you disagree with any of the Company's
7 explanation regarding why the 0 and M expenses are not -- or,
8 the explanation that the 0 and M expenses are, indeed, known
9 and measurable?
10 A.They are -- if you're talking about the 0 and M
11 expenses that I excluded, those were budgeted amounts that they
12 were looking forward to for 2010. I limited those budgeted
13 amounts to what were actually expended in the test year 2009.
14 There were some of those costs that were related to specific
15 contractual obligations, and I included those because those
16 were easily measurable and they were known and you could
17 calculate those amounts, so I included those amounts as part of
18 the expenses in the rate case that could be recovered, but the
19 other budgeted or projected amounts I excluded.
20 Q.And what would those be?
21 A.There were some labor costs.
22 Q.I'm sorry, those are the ones that are addressed
23 in your testimony already?
24 A.Yes.
25 Q.Okay. Did any of the corrections that you made
1991
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (X)Staff
.
.
.
1 earlier with regard to your testimony address the Naughton
2 stockpile of coal?
3 A.Yes.
4 Q.And so are you now agreeing with the Company's
5 analysis on that issue as well, or is that just regarding the
6 Huntington and Rock Garden?
7 A. I maintained my position on the Naughton
8 stockpiled. The only changes I made were on the Carbon,
9 Huntington, Deer Creek, and Rock Creek stockpiles.
10 Q.Okay. Based on your analysis of the Naughton
11 plant's monthly stockpile levels, wouldn't you agree that the
12 December 2009 balance appears to be an anomaly relative to the
13 rest of 2009 and the first half of 2010?
14 A.I can't say that's an anomaly.
15 Q.Would you agree that the average stockpiled level
16 for calendar year 2009 was approximately 360,000 tons?
17 A.I don't know that.
18 Q.Would you agree that it would be inappropriate to
19 base a stockpile level on a month that was lower or -- lower
20 than the average due to mechanical issues, for instance, if a
21 conveyor or a stacker or a reclaimer was out?
22 A.I would assume that the Company would make an
23 adjustment in that as part of the 2009 test year.
24 Q.Okay. Moving on to the Bridger plant, would you
25 agree that underground mining poses additional supply and ?
1992
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
LECKIE (X)Staff
.
.
.
1 quality risks versus surface mining.
2 I don't have the expertise to say that.A.
3 MR. SOLANDER: I have no further questions.
4 COMMISSIONER SMITH: Any questions from the
5 Commission?
6 COMMISSIONER REDFORD: No.
7 COMMISSIONER KEMPTON: No.
8 COMMISSIONER SMITH: Nor I.
9 Redirect, Mr. Woodbury.
10 MR. WOODBURY: Madam Chair, Staff has no
11 redirect.
12 COMMISSIONER SMITH: Thank you, Mr. Leckie.
13 (The witness left the stand.)
14 MR. WOODBURY: Staff would call as its next
15 wi tness Donn English.
16
17 DONN ENGLISH,
18 produced as a witness at the instance of Staff, being first
19 duly sworn, was examined and testified as follows:
20
21 DIRECT EXAMINATION
22
23 BY MR. WOODBURY:
24 Mr. English, will you please state your name forQ.
25 the record, and spell your first and last names?
1993
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
ENGLISH (Di)Staff
.
.
.
1 A.My name is Donn English: D-O-N-N; last name,
2 E-N-G-L-I-S-H.
3 Q.And for whom do you work and in what capacity?
4 A.I work for the Idaho Public Utili ties Commission
5 as a senior auditor.
6 Q.And in that capacity, did you have occasion in
7 this case to prepare prefiled testimony filed on October 14th
8 consisting of 15 pages and four exhibits, Exhibits 104 through
9 107?
10 A.I thought I had sponsored five but it appears
11 that there is only four, so, yes.
12 Q.And have you had occasion to review that
13 testimony and those exhibits prior to this hearing?
14 A.Yes, I have.
15 Q.And as of October 14th, if I were to have asked
16 you the questions set forth in your testimony, would your
17 answers have been the same?
18 A.Yes, they would.
19 Q.And in light of your review of the Company's
20 rebuttal testimony, and in the same vein as the questions that
21 were asked of Mr. Leckie, is there anything that you could
22 provide at this point that would perhaps eliminate the need for
23 some needless questions?
24
25
A.Yes. The first adj ustment that I proposed on
Exhibi t 104 was the imputed revenue for some subsidized lease
1994
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
ENGLISH (Di)
Staff
.
.
. 25
1 where the Company leased space in the one Utah center to a
2 couple of nonprofit entities, and after reviewing the
3 accounting entries in Mr. McDougal's testimony, it appears that
4 those -- that amount is indeed included in Utah customers'
5 rates, or more fairly at least not included in Idaho customers'
6 rates.
7 Q.Okay. And is that the only addition that you'd
8 like to make?
9 A.Yes.
10 COMMISSIONER SMITH: Does that mean we should
11 substitute the number "0" for the imputed revenue amount
12 underneath the system in Idaho, or what are we supposed to do?
13 THE WITNESS: Yes.
14 COMMISSIONER SMITH: Zero under Idaho or --
15 THE WITNESS: I would probably just eliminate
16 that entire line.
17 COMMISSIONER SMITH: Thank you.
18 MR. WOODBURY: Madam Chair, I would ask that
19 Mr. English's testimony be spread on the record, and that
20 Exhibits 104 through 107 be identified.
21 COMMISSIONER SMITH: Without obj ection, it is
22 without objection, it is so ordered.
23 (The following prefiled direct testimony
24 of Mr. English is spread upon the record.)
1995
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
ENGLISH (Di)Staff
.
.
.
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Donn English. My business address is
4 472 W. Washington, Boise, Idaho 83702.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a senior auditor in the Utilities Division.
8 Q.What is your educational and experience
9 background?
10 A.I graduated from Boise State University in 1998
11 wi th a BBA degree in Accounting. Following my graduation,
12 I accepted a position as a Trust Accountant with a pension
13 administration, actuarial and consulting firm in Boise. As
14 a Trust Accountant, my primary duties were to audit the
15 day-to-day financial transactions of numerous qualified
16 retirement plans. In 1999, I was promoted to Pension
17 Administrator. As a Pension Administrator, my
18 responsibilities included calculating pension and profit
19 sharing contributions, performing required non-
20 discrimination testing and filing the annual returns (Form
21 5500 and attachments) .In May of 2001, I became a
22 designated member of the American Society of Pension
23 Professionals and Actuaries (ASPPA). I was the first
24 person in Idaho to receive the Qualified 401 (k)
25 Administrator certification and I am one of approximately
CASE NO. PAC-E-10-07
10/14/10
1996 1ENGLISH, D. (Di)
STAFF
.
.
.
1 ten people in Idaho who have earned the Qualified Pension
2 Administrator certification. In 2001, I was promoted to a
3 Pension Consultant, a position I held until 2003 when I
4 joined the Commission Staff.
5 Wi th the American Society of Pension
6 Professionals and Actuaries, I served on the Education and
7 Examination Committee for two years. On this committee I
8 was responsible fOr writing and reviewing exam questions
9 and study materials for the PA-1 and PA-2 exams
10 (Introduction to Pension Administration Courses), DC-1,
11 DC-2 and DC-3 exams (Administrative Issues of Defined
12 Contribution Plans - Basic Concepts, Compliance Concepts
13 and Advanced Concepts) and the DB exam (Administrative
14 Issues of Defined Benefit Plans). I have also regularly
15 attended conferences and training seminars throughout the
16 country on numerous pension issues.
17 While with the Commission, I have audited a
18 number of utilities including electric, water and gas
19 companies and provided comments and testimony in several
20 cases that dealt with general rates, accounting issues,
21 pension issues and other reg~latory issues. In 2004 I
22 attended the 46th Annual Regulatory Studies Program at the
23 Institute of Public Utilities at Michigan State University
24 sponsored by the National Association of Regulatory Utility
25 Commissioners (NARUC). Since then I have regularly
CASE NO. PAC-E-10-0710/14/10
1997 2ENGLISH, D. (Di)
STAFF
.
.
.
13
14
1 attended NARUC conferences and meetings, primarily the
2 meetings of the Subcommittee of Accounting and Finance.
3 Q.What is the purpose of your testimony in this
4 proceeding?
5 A.The purpose of my testimony in this proceeding is
6 to present and support Staff adjustments to the Company's
7 revenue requirement, specifically adjustments to employee
8 wages and benefits, along with an adjustment to property
9 taxes and a minor adjustment to the Company's revenue to
10 impute fair market value for two subleases at the One Utah
11 Center in Salt Lake City.
12 Q.Are you sponsoring any exhibits in this
proceeding?
A. Yes,I am sponsoring Staff Exhibit Nos. 104-107.
15 Exhibit No. 104 is a summary of all of the adjustments I
16 propose to the Company's Revenue Requirement. The amounts
17 listed are on a total Company (system) basis and have been
18 provided to Staff witness Vaughn to include in the
19 Regulatory Adjustment Model (RA) and the Jurisdictional
20 Allocation Model (JAM).
21 Q.Please explain the imputed revenue adjustment on
23
22 Exhibit No. 104, line 1.
A.The Company's corporate offices are located at
24 the One Utah Center in Salt Lake City. The Company
25 currently leases 120,610 square feet at an average price of
CASE NO. PAC-E-I0-0710/14/10
1998 3ENGLISH, D. (Di)
STAFF
.1 $21.31 per square foot, and subleases some of its space to
2 three maj or tenants at an average price of $18.48 per
3 square foot. In addition, the Company also sublets office
4 space to the Utah Sports Commission and the Economic
5 Development Commission of Utah for $12.00 per year. Staff
6 believes that it is not appropriate for customers i
7 especially Idaho customers i to subsidize through
8 electrici ty rates the leases for these two Utah Commissions
9 at the below market rate that PacifiCorp has decided to
10 grant to them. The total office space occupied by these
11 two Commissions is 7 i 689 square feet. I impute revenue of
12 $142,069 at a price of $18.48 per square footi less the $24.13
14
15
annually received for these two sub-leases.
Q. Please explain your next adjustment.
A.The next adjustment I propose on Exhibit No. 104,
16 line 21 is to remove $1,603,785 (system) from FERC Account
17 925 for Injuries and Damages.
18
19
Q.What is the basis for this adjustment?
A.In its Application, the Company proposed using a
20 three-year average i net of receivables from insurance i of
21 amounts booked into Account 9251 Injuries and Damages, for
22 a total of $3/481/634 on a system-wide basis, compared to
23 only $1,877 i 849 during the 2009 test year.
24 Q.Has the Company used the three -year average for
25 Injuries and Damages in the past?.
CASE. NO. PAC-E-10-0710/14/10
1999 4ENGLISH, D. (Di)
STAFF
.
.
.
1 A.Yes, however, none of those general rate cases
2 went to a full hearing where the Commission has made a
3 ruling on the issue. Staff will occasionally support the
4 use of averages for accounts that show volatility from year
5 to year that are beyond the Company's control. However,
6 when it comes to Inj uries and Damages, each individual
7 entry into that account is, by its very nature, an
8 extraordinary and hopefully non-recurring expense. The
9 account is a catch-all account for minor accidents,
10 automobile accidents, and sometimes for damages where
11 employee negiligence is involved. For those reasons alone,
12 it would be feasible to argue that the entire amount should
13 be removed from revenue requirement.
14 Q. Are you recommending removal of the entire
15 amount?
16 A.No. I propose using the actual amounts booked in
1 7 2009 for Inj uries and Damages, net of receivables, for two
18 reasons. First, the 2009 level was the lowest level booked
19 into that account over the past three years, so it is an
20 amount that is reasonably attainable. By including the
21 lowest level incurred during the last three years, it
22 provides incentive for the Company to continue to manage
23 the amounts it spends on Inj uries and Damages. Secondly,
24 the amounts booked to Account 925 have been trending
25 downward, from $5.4 million in 2007, to $3.2 million in
CASE NO. PAC-E-10-07
10/14/10
2000 5ENGLISH, D.' (Di)
STAFF
.
.13
14
1 2008, to $1.9 million in 2009. This downward trend can be
2 attributed to safety measures undertaken by the Company
3 during 2008 and 2009.
4 Q.Briefly describe some of the specific safety
5 measures that were undertaken by the Company during 2008
6 and 2009.
7 A.The safety measures, among other things, ensured
8 that Company policy was developed, effectively communicated
9 to employees, and was being followed at all levels of the
10 organization and that there was sufficient control,
11 monitoring, and correct procedures in place to meet the
12 stated safey performance, which was to be in the top 10% of
the Company's peer group. The plan also established a road
risk management program to reduce preventable vehicle
15 accidents by 10% below the 2007 and 2008 targets. The plan
16 also included crew audits in the field, managers walking
17 the dock, management's morning stretch and flex and a daily
18 safety briefing at the start of each shift. Quarterly
19 facility audits and monthly crew audits were performed.
20 All deficiencies observed were corrected and responsible
21 employees received coaching, counseling and training.
22 Q.Does the decline in the amounts spent on Inj uries
24
23 and Damages reflect that the plan is working?
A.Yes, I believe it does. Therefore, it would not
25 be reasonably prudent to allow the Company to recover in.
CASE NO. PAC-E-I0-07
10/14/10
2001 6ENGLISH, D. (Di)
STAFF
.
.
.
1 rates any amount that does not take into consideration the
2 Company's recent safety efforts.
3 Q.Please explain the adjustment to property taxes
4 shown on Exhibit No. 104, line 3.
5 A.The Company has requested to recover in rates an
6 amount it believes will accrue for property taxes for 2010.
7 However, the Company routinely appeals the assessed value
8 of the property that is taxed by the different states in
9 which the Company owns and maintains property. Since 2005,
10 the Company has received. refunds from successful appeals
11 totaling over $1.7 million. Because the total accrual for
12 property tax is included in base rates, shareholders
13 receive the benefit of all property tax refunds. Customers
14 who are actually paying the accrued property taxes in their
15 retail rates should receive the benefit of any refunds from
16 the successful property tax appeals. The adjustment of
17 $288,125 is the~average amount refunded to the Company for
18 the tax years 2005 through 2010. This amount is
19 representantive of what I believe the Company may receive
20 in refunds for successful appeals of the 2010 tax
21 liability.
22 Q.Please explain the Company's treatment of pension
23 expense in this case.
24 A.The Company requested to recover its 2010 actual
25 cash contributions to the pension plan, instead of the
CASE NO. PAC-E-10-0710/14/10
2002 7ENGLISH, D. (Di)
STAFF
.
.
.
1 accrued expense calculated under the Statement of Financial
2 Accounting Standards No. 87 (SFAS 87), commonly referred to
3 as the pension expense. This is consistent with prior
4 PacifiCorp rate cases and the Letter of Understanding from
5 the Commission Staff.
6 Q.Can you briefly refresh the Commission on the
7 difference between the two amounts?
8 A.Without getting into the details of how the two
9 different amounts are calculated, which has been rehashed
10 in previous cases, the cash contribution is the actual cash
11 outlay invested into the plan's trust account, while the
12 SFAS 87 pension expense is reflected on the financial
13 statements of the Company as a reduction (or increase) in
14 the Company's earnings. Both amounts are calculated using
15 similar principles, although the rules for calculation are
16 very different. Staff and the Commission have generally
1 7 supported the use of the actual cash contribution as the
18 starting point for determining an amount to be included in
19 a utility's annual revenue requirement.
20 In this case, the Company reflects a pension
21 expense of $31,800,000 to be recorded on its books for
22 2010, .with a cash contribution of $104,800,000 for 2010 on
23 a total system basis. After adjusting the amounts to
24 remove the portion for the mines and to account for just
-25 the ü&M portion, the Company proposes an adjustment of
CASE NO. PAC-E-I0-0710/14/10
2003 8ENGLISH, D. (Di)
STAFF
.
.
.
1 $47.7 million, as shown on Exhibit No. 105, Column (c),
2 line 11.
3 Q.What is the basis for your adjustment to pension
4 expense?
5 A.At the time of this writing, the 2010 actuarial
6 valuation has not been completed. The Company has not
7 provided any detailed calculations from its actuaries
8 illustrating how the $104.8 million contribution was
9 calculated. Though there is no reason to believe that the
10 2010 contributions are miscalculated, Staff was not able to
11 verify the amounts. Furthermore, the estimated future
12 contributions .calculated by the Company's actuaries and
13 provided to Staff confidentially indicate a significant
14 decrease in pension funding in future years. The required
15 contribution for 2010 is approximately twice as much as the
16 contribution for 2009 and estimated contribution for 2011.
17 To include the 2010 contribution amount in rates that go
18 into effect in 2011 and could potentially remain in effect
19 for several years would allow the Company to collect
20 significantly more in revenue than necessary to meet its
21 pension obligations. I have used an average of the
22 proj ected contributions to the pension plan for the period
23 of 2010-2014 as the amount to include in Staff's revenue
24 requirement for pension expense, as shown on Exhibit
25 No. 105 Column (d), line 1. The projected future
CASE NO. PAC-E-10-0710/14/10
2004 9ENGLISH, D. (Di)
STAFF
.
.
.
1 contributions to the PacifiCorp Retirement Plan are shown
2 on Confidential Exhibit No. 106. The Staff adjustment that
3 I recommend for pension expense is $20,875,647 as shown on
4 Exhibit No. 105, Column (e), line 12 and Exhibit No. 104,
5 line 4.
6 Q.Please explain the next adjustment on Exhibit
7 No. 104, line 5 labeled as SERP.
8 A.SERP is an acron~~ for Supplemental Executive
9 Retirement Plan. A SERP is a non-qualified plan for
10 executives of a Company to provide additional benefits
11 above and beyond those covered in more conventional
12 retirement plans to ensure the executive can maintain the
13 same standard of living in retirement. The only active
14 participant in this retirement plan is the President of
15 Rocky Mountain Power, and the Company included $2.6 million
16 on a total system basis to cover this cost. Idaho
17 customers should not be required to pay for additional
18 retirement benefits for executives of a utility above and
19 beyond the retirement benefits that are available to rank
20 and file employees. Because an executive's salary is
21 already higher than the typical employee, and the typicai
22 retirement benefits provided are based on the level of
23 wages earned, the executive is already receiving a larger
24 benefit than the other employees. Any additional benefit
25 provided should be paid for solely by shareholders,
CASE NO. PAC-E-10-07
1.0/14/10
2005 ENGLISH, D. (Di) 10
STAFF
.
'.
.
1 especially since an executive's performance is typically
2 based on creating value for the shareholder.
3 Q. Please explain the next adjustment of $33,103,859
4 on Exhibit No. 104, line 6, labeled Incentive Payments.
5 A. Yes, this adjustment represents Staff's
6 adj ustment to the Company's proposed level of employee
7 bonuses, ultimately removing 100% of employee bonuses from
8 revenue requirement.
9 Q.Please briefly describe the Company's Incentive
10 Plan.
11 A.The Company establishes an annual amount to be
12 awarded to employees each year. The amount an employee
13 receives is based on an individualized set of goals for
16
15 goals, a bonus is awarded.
14 that particular employee. If an employee achieves those
Q.Why are you proposing to remove employee bonuses
18
17 from the Company's revenue requirement?
A.I am recommending the removal of bonus payments
19 for two reasons. First, because the criteria to receive a
20 bonus is on an individualized basis, it is impossible for
21 Staff to determine if such criteria benefits shareholders
23
22 or customers. The Commission has previously ruled that
24
incentive pay can only be included in annual revenue
requirement if it is related to indentifiable customer
25 benefits. If the criteria for an employee to receive a
CASE NO. PAC-E-I0-0710/14/10
2006 ENGLISH, D. (Di) 11
STAFF
.
.
.
1 bonus has a shareholder benefit, then the shareholders
2 should bear the cost. Any amount of bonus that ties to
3 operating budgets would have a direct impact on the
4 earnings per share of the Company and therefore would
5 benef i t shareholders. However, because of the complexi ty
6 of the Company's Incentive Plani there is no way to
7 determine whether the Commission's criteria to include
8 bonuses in revenue re~Jirement has been met. Secondly, I
9 believe that the Commission is cognizant of the public
10 perception of Rocky Mountain Power awarding employee
11 bonuses at a time when it is asking to increase the rates
12 it charges for electricity i and especially when many of its
13 customers are struggling financially. During a time of
14 economic despair throughout Rocky Mountain Power's
15 territory, which is described in Staff witness Thaden's
16 direct testimony and Exhibit Nos. 115 and 1161 it is not
17 appropriate to seek recovery of bonus payments from
18 customers. If Rocky Mountain Power believe 1 s that today's
19 financial environment mandates the need for rate increases i
20 those rate increases should be mitigated by a concerted
21 attempt to lower costs and salaries.
22 Q.What is the total percentage of the incentive
23 plan included in an employee i s total compensation?
24 A.The Company has proposed to recover $33,103,859
25 for the annual incentive plan and bonuses, which is the
CASE NO. PAC-E-10-0710/14/10
2007 ENGLISH, D. (Di) 12
STAFF
.
.
.
13
14
1 2010 budgeted level. Union employees do not participate in
2 the Company's incentive plan. The total 2010 non-union
3 proforma wages and salaries is $201/802/000. This equates
4 to incentives being 16.4% of total wages for 2010.
5 Q.Would you please explain the adj ustment to
6 Employee Wages listed on Exhibit No. 104.
7 A.The net effect of this adjustment removes all
8 wage increases awarded by Rocky Mountain Power to its
9 employees during 2009 and 2010, and sets the level of
10 straight-time labor at the January 11 2009 level.
11 Q.Please briefly descrive the Company 1 s proposal
12 for employee wages in this case.
A. Actual December 31, 2009 labor related expenses
15 2009 as being included for a full twelve months. The
were annualized to reflect any increases that occurred in
16 annualized 2009 labor expenses were then escalated at
17 ei ther the contractual increase for union employees or the
18 actual increase for non-union employees to reflect a 2010
20
19 pro forma budgeted amount.
Q.What types of wage increases were awarded in 2009
21 and 2010?
22 A. In 20091 non-union employees received a 3.5% wage
23 increase, while the union employees received between 1.25%
24 and 3 percent. In 2010, the non-union employees received
25 an increase of 0.88% while the union employees received
CASE NO. PAC-E-I0-0710/14/10
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1 between 1.5 and 2.5 percent.
2 Q.Why do you believe these increases are
3 inappropriate?
4 A. - Al though the increases may seem minimal, they
5 occurred at a time of economic distress for Rocky
6 Mountain's customers. Unemployment rates doubled and
7 tripled in many parts of the country, included Rocky
8 Mountain Power's service territory, while wages and the
9 consumer price index remained relatively flat. Americans
10 on Social Security will not receive cost of living
11 adjustments for 2010 and 2011, and most employees with the
12 State of Idaho were forced to take pay cuts. While much of
13 the population struggles, it is not prudent for utility
14 companies to continually grant increases to its employees.
15 Staff believes that during the past two years, Rocky
16 Mountain Power had the opportunity to better control costs
17 and mitigate rate increases. I recommend adjusting
18 employee wages by $14,375,075 (Exhibit No. 104, line 7).
19 Q.Please describe the last adjustment on Exhibit
21
20 No. 104, line 8.
A.The final adjustment I propose is to reduce the
22 MidAmerican Energy Holding Company (MEHC) Management Fees
23 allocated to PacifiCorp. Merger Commitment #28 commits
24 PacifiCorp to limiting the amount of allocations from MEHC
25 to PacifiCorp at $7.3 million, which the Company did in its
CASE NO. PAC-E-I0-0710/14/10
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1 Application. However, included in the $7.3 million
2 allocation from MEHC is $2.15 million in Supplemental
3 Executive Retirement Plan contributions and bonuses to
4 employees of MidAmerican. I remove this amount as a
5 logical continuation of adjustments. Because I recommend
6 removing bonuses and SERP contributions for Rocky Mountain
7 Power employees from customers' retail rates, then the SERP
8 contributions and bonuses for employees of MidAmerican
9 should also be removed. Exhibit No. 107 illustrates how
10 the $7.3 million cap is affected by this adjustment and
11 shows my adjustment of $1,100,635.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Q.Does this conclude your direct testimony in this
proceeding?
A. Yes,it does.
CASE NO. PAC-E-I0-07
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19
20
1 (The following proceedings were had in
2 open hearing.)
3 MR. WOODBURY: And I would present Mr. English
4 for cross-examination.
5 COMMISSIONER SMITH: Thank you.
6 Mr. Purdy, do you have questions?
7 MR. PURDY: No questions.
8 MR. WILLIAMS: No questions.
9 MR. OLSEN: No questions.
10 COMMISSIONER SMITH: Mr. Otto.
11 MR. OTTO: No questions.
12 COMMISSIONER SMITH: Mr. Budge.
13 MR. BUDGE: No questions.
14 COMMISSIONER SMITH: For the Company?
15 MR. HICKEY: Mr. Solander.
16 COMMISSIONER SMITH: Mr. Solander.
17 MR. SOLANDER: Thank you.
18
CROSS-EXAMINATION
21 BY MR. SOLANDER:
22
23
24
25
Q.Good afternoon, Mr. English.
A.Good afternoon.
Q.You would agree with me that as a general matter,
it's reasonable for Rocky Mountain Power to compensate its
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1 employees in line with market rates of pay for electric
2 utilities?
3 A.You know, I have some slight disagreement with
4 that, but generally speaking, I do agree. I think there are
5 critical operation roles that you can compare to other electric
6 utili ties. I do think the market for some of the admin
7 nonunion employees, there may be a lot of overlap into other
8 industries, but generally speaking, I will agree with you.
9 Q.And then wouldn't you agree that if an employee 's
10 base pay is set at a level that is below market, it would be
11 reasonable for the Company to include in that employee's pay
12 package an opportunity for him or her to receive pay at the
13 market level if they perform satisfactorily?
14 A.You know, again, I generally would agree, with
15 some caveats that, you know, current economic conditions,
16 experience of the employee. There i s a lot of other variables
17 that may lead one to conclude that employees should be paid
18 below market average, but generally speaking, I will agree with
19 you.
20 Q.And you include two main reasons that you suggest
21 that incentive pay should be included in rates, the first being
22 that the criteria to receive incentive pay is individualized,
23 and you can't tell if the criteria benefits shareholders or
24 customers?
25 A.That is correct.
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1 Q.And you also state that -- I don't want to
2 misquote you. Just one moment.
3 COMMISSIONER SMITH: Did you mean to say
4 "included" or "excluded" in your last question?
5 Q.BY MR. SOLANDER: It should be excluded because
6 Mr. English -- or, Mr. English contends it should be excluded
7 because he can't tell whether or not the criteria benefits
8 shareholders or customers. Is that right?
9 A.Yeah, there was a lack of transparency in
10 determining where and how these employees received their bonus
11 payments.
12 Q.And then you go on to say that the criteria for
13 determining individual performance are too complex?
14 A.Wi thout a specific line, I'm not sure if that was
15 my exact words, but I think the Commission has established in
16 prior rate cases some components that should be considered when
17 including bonus payments to employees, such as safety, customer
18 service, and we include those at reasonable target levels.
19 Q.Okay. But you state on page 5 of 12 -- page 12,
20 line 5: However, because of the complexity of the Company's
21 incentive plan, there is no way to determine whether the
22 Commission 's criteria to include bonuses in revenue requirement
23 has been met?
24
25
A.Yes, that is correct.
Q.If incentives are based only on a broad group of
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1 Company-wide criteria, would you agree that an individual
2 employee could qualify for an incentive payment even if he or
3 she performed poorly?
4 A.No.
5 Q.You would not agree with that?
6 A.Maybe you could repeat the question, but I'm not
7 sure
8 Q.If incentives were based only on Company-wide
9 criteria--
10 A.Uh-huh.
11 Q.-- wouldn't you agree then that an individual who
12 underperforms could earn an incentive?
13 A.Should earn it if he underperforms?
14 Q. No, would be able to, not should.
15 A. Oh, I think the employee could have the ability
16 to earn it. Whether or not the Company chose to provide that
17 employee with a bonus, I would assume --
18 Q.So wouldn't you agree then that indi viduali zed
19 incenti ve plans would be more effective in providing the
20 employee with a clear incentive to perform well?
21 A.Well, that's not exactly what my contention is.
22 I think if you set the target level based on some Company
23 standards and those standards are met, management of each
24 employee can then determine how much of that pool should be.25 allotted to each individual employee and how they contributed
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1 to those Company standards.
2 Q.Would you agree that if the Company operates
3 efficiently and expenses are less than budgeted amounts, that
4 would tend to keep rates down or keep them level?
5 A.I'm having a hard time hearing with the fan above
6 me.
7 Q.If the Company operates efficiently and expenses
8 are less than budgeted amounts, would you agree that that would
9 tend to keep rates down?
10 A.That would again depend. If you're referring to
11 operation and maintenance expense or A and G expenses and the
12 level that is determined in rates, then -- well, I guess for
13 your question, yes, I would agree with that.
14 Q.And so you would agree that keeping operating
15 expenses wi thin or below established budgets would benefit
16 ratepayers?
17 A.Yes, I would.
18 Q.And minimizing operating expenses would also
19 benefit ratepayers?
A.Yes, I would agree.
Q.And meeting safety goals, reducing accidents
22 addi tionally would benefit ratepayers?
23
24
25
A.I do agree with you there.
Q.And as would meeting customer service goals?
A.Yes.
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1 I would just like to just explain that when we
2 talk about budgets, I'm cautiously skeptical of budgets that
3 are produced by the Company; and so when it comes to meeting
4 those and maintaining those budgets, I hesitate to give the
5 assumption that I would approve any or recommend to the
6 Commission to approve any incentive payment, bonus payment
7 based on just those budgets for a couple of reasons. And one
8 that would determine if the level included in rates was already
9 set higher than the 0 and M expenses that the Company has
10 maintained, then the Company has pretty much self-funded any
11 incentive payment that they chose to make and the shareholders
12 would benefit because the additional moneys would be then
13 allotted or benefit directly to the shareholders.
14 So I have to throw a caveat in there because I'm
15 not sure that given your narrow question, the answer is yes,
16 I would agree with you, but there are circumstances that could
17 arise very easily where I would not.
18 Q.I'm not going to argue with you over the
19 credibili ty of all of the other witnesses
20 A.Sure. Okay.
21 Q.-- and the evidence the Company has presented
22 regarding, you know, our operating budgets and our expenses;
23 but can we just agree that to the extent that employees work to
24 meet the goals that we just discussed regarding safety, 0 and
25 M, that ratepayers would benefit?
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1 A.As would shareholders.
2 Q.Do you disagree with the statements from
3 Mr. Wilson that there are limited employees whose goals are
4 focused on improving the net income and revenues of the Company
5 to the benefit of shareholders?
6 A.I would definitely agree that Mr. Wilson has more
7 knowledge of the employees than I do.
8 Q.And would you agree that those limited number of
9 employees are not included in the incentive plan expense that
10 the Company is seeking to include in rates in this case?
11 A.I have no reason to disagree with Mr. Williams
12 (sic) .
13 Q.The second reason that you cite on page 12 or --
14 let me get the exact page here.
15 A.I believe it would be starting at line 9 on
16 page 12.
17 Q.Yes, it would: Public perception. Thank you.
18 Did you do any studies or do you have any data
19 that would confirm your assumptions about the public's
20 perception?
A.My assumptions about the public perception with
22 regards to incentive payments for --
23
24
25
Q.Correct.
A.I think we hear quite a bit from the public,
complaints and comments in this case and other cases that we've
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1 deal t with, that one of the areas where the customers seem most
2 concerned is the benefits and compensation packages of the
3 utility employees.
4 Q.Would you agree that that perception is really
5 tied to your characterization of the incentive plan as a bonus
6 plan?
7 A.No, I would think that there is a general
8 understanding of the public that utility Company employees are
9 generously paid.
10 Q.To the best of your knowledge, has this
11 Commission approved incentive plans in the past?
12 A.Yes, it has.
13 Q.Can I turn your attention to page 14, lines 17
14 through 18, of your testimony?
15 COMMISSIONER REDFORD: What's the page number
16 again?
17 THE WITNESS: Would you mind if I have a minute
18 just to get the context of this paragraph?
19 Q.BY MR. SOLANDER: Certainly. Page 14, lines 17
20 through 18.
21
22
COMMISSIONER REDFORD: Thank you.
Q.BY MR. SOLANDER: And really I guess you could
23 start with line 12.
24
25
A.Would you like me to read it? I'm sorry.
Q.You don't have to read it out loud; just refresh
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1 your recollection.
2 A.Okay.
3 Okay, yes.
4 Q.So in that paragraph, you recommend reducing the
5 employee wages by $14,375,075?
6 A.That is correct.
7 Q.Is there any support in the record other than
8 your opinion for that number?
9 A.For the number?
10 Q.For the number, for the $14 million.
11 A.The exhibits and work papers, and I'm not sure if
12 the work papers are part of the official record or not.
13 Q.Well, I mean, if you look at Exhibit No. 104,
14 isn't it just a line that says incentive payments, employee
15 wages, $14 million negative?
A.Well, I guess that would be part of the record,
17 yes.
18 Q.Yes. But you didn't perform any independent
19 analyses to come up with that $14 million number?
20 A.That $14 million number is just a difference
21 between the wages that were requested in this case and the
22 December 31, 2008, wages.
23 Q.And so it was just chosen as a reduction based on
24 general market conditions or general economic conditions?
25 A.Yes, and I think there's plenty of record in this
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1 case from the past couple of days about general economic
2 condi tions.
3 Q.Certainly. Wouldn't you agree that it's better
4 practice for the Company to base annual wage increases on a
5 recent analysis of wage rates and conditions in the utility
6 industry, rather than choosing an arbitrary number based on
7 general economic conditions?
8 A.I think general economic conditions need to be
9 considered, absolutely.
10 Q.That wasn't my question.
11 A.And your question was --
12 Q.Wouldn't you agree that it would be better
13 practice for the Company to base the annual wage increases on a
14 recent analysis of wage rates and conditions in the utility
15 industry rather than choosing arbitrary numbers based solely on
16 general economic conditions?
17 A.Wi thout trying to take exception to your term
18 "arbitrary," I'll go ahead and agree with you.
19 Q.Thank you.
MR. SOLANDER: That's all I have.
COMMISSIONER SMITH: Do we have questions from
22 the Commission?
23
24
25
COMMISSIONER REDFORD: No.
COMMISSIONER KEMPTON: Madam Chairman, I think
I'LL try a couple.
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1 COMMISSIONER SMITH: Commissioner Kempton.
2
3 EXAMINATION
4
5 BY COMMISSIONER KEMPTON:
6 Q.So, Mr. English, in looking at rates or the
7 salary increases in the utility business, are there different
8 levels of comparison in -- among different utili ties as to how
9 you would define the pay increases in each of those utili ties?
10 A.I'm not sure if I understand your question.
11 Q.As you look across the spectrum of utili ties and
12 if you were looking at pay raises annually by those utilities,
13 is there a spectrum that exists between smaller utilities and
14 larger utili ties?
15 A.There -- there's a -- there are differences that
16 exist. A lot of the data doesn't break it down specifically by
17 utilities, so, therefore, I can answer to the utilities that we
18 regulate and only based on when their past rate case was
19 determine how reasonable they are.
20 There is somewhat of a spectrum, I would say, but
21 it's usually an annual increase of a small percentage, every
22 year.
23 Q.Okay. You've reviewed the Company's filing. How
24 did the Company establish their average increase?
25 A.The Company had used a third-party vendor or
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1 third-party consultant -- and I can't remember exactly who it
2 was at this point -- as do other companies, but usually that
3 information is confidential. And I can explain how the Company
4 attempted to do it based in their own terms, but I believe the
5 Company witness kind of already expressed or already explained
6 that earlier, so
7 So in the case of previous testimony, the processQ.
8 was one of merit increases, I believe, that they looked at
9 across the spectrum of ten -- ten or 12, 15 companies. Is that
10 correct?
11 Typically, there's a peer group of companies ofA.
12 similar size and market capitalization that they would look at,
13 yes.
14 Is it possible to cherry pick among companiesQ.
15 when you're looking at things like that if you could take a
16 look at those merit increases across a broader spectrum?
17 Oh, it is possible.A.
18 Should all of the comparison -- there's -- whenQ.
19 we establish a return on equity, there's statutory requirements
20 and court precedent in the spectrum that you can look at when
21 you are determining a return on equity. Is that correct?
22 If you could ask me that question one more time,A.
23 I'll see if I can answer it or defer it.
24 Are there specific guidance is there specificQ.
25 guidance, statutory direction, and court case precedent that
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1 establish how you return a return on equity?
2 A.I believe there is, and I know Ms. Carlock has
3 that somewhat in her testimony, a couple court cases that she
4 refers to.
5 Q.It's a broad, general question.
6 A.Okay.
7 Q.Do you know of a similar process or guidelines
8 that are established for wage increases wi thin individual
9 utilities?
10 A.Not that I know of. I believe it's pretty much
11 up to the Commission i s discretion what to include in revenue
12 requirement.
13 COMMISSIONER KEMPTON: I have no further
14 questions.
15 COMMISSIONER SMITH: Of course, the Commission's
16 discretion would be bounded by the statutory requirement that
17 our decisions be based on substantial evidence --
18 THE WITNESS: Reasonable and correct.
19 COMMISSIONER SMITH: -- and not be arbitrary and
20 capricious.
21 THE WITNESS: I do agree with you, and I'm sorry
22 if I misled anybody.
23
24 any redirect?
COMMISSIONER SMITH: Mr. Woodbury, do you have
25 MR. WOODBURY: Just one question for -- with
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1 respect to clarification.
2
3 REDIRECT EXAMINATION
4
5 BY MR. WOODBURY:
6 Q.Wi th respect to the exchange between you and
7 Mr. Solander on your testimony on line 14 -- page 14, line 18,
8 and the -- your adj ustment to employee wage --
9 A.Yes.
10 Q.-- that figure, $14,375,075 was not -- it's not
11 an arbitrary figure, but as I understood you to say, yours have
12 scaled back to December 31, 2008, wages?
13 A.That's correct, or wages beginning January 1,
14 2009.
15 Q.Okay. And that's what's reflected also on
16 Exhibit 104, line 7?
17 A.That's correct.
18 MR. WOODBURY: Madam Chair, no further questions.
COMMISSIONER SMITH: Thank you, Mr. Woodbury, and
20 thank you, Mr. English. Appreciate your help.
21
22
23
24
. 25
(The witness left the stand.)
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