20101220Vol IV Technical Hearing, pp 580-820.pdf

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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-I0-07
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 1, 2010
VOLUME IV - Pages 580 - 820
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HEDRICK
COURT REPORTING
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
tleR-V tk !t1J1K~ olíru 1978
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1 APPEARANCES
2 For the Staff:
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For PacifiCorp
dba Rocky Mountain Power
(RMP) :
SCOTT WOODBURY, Esq.
and NEIL PRICE, Esq.
Deputy Attorneys General
472 West Washington
Boise, Idaho 83702
HICKEY & EVANS, LLP
by PAUL J. HICKEY, Esq.
Post Office Box 467
Cheyenne, Wyoming 82003
-and-
DANIEL E. SOLANDER, Esq.
ROCKY MOUNTAIN POWER
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
RACINE, OLSON, NYE, BUDGE
& BAILEY
by RANDALL C. BUDGE, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
RACINE, OLSON, NYE, BUDGE
by ERIC L. OLSEN, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
BENJAMIN J. OTTO, Esq.
IDAHO CONSERVATION LEAGUE
710 North Sixth Street
Boise, Idaho 83702
WILLIAMS BRADBURY, PC
by RONALD L. WILLIAMS, Esq.
1015 West Hays Street
Boise, Idaho 83702
-and-
DAVI SON VAN CLEVE, PC
by MELINDA J,. DAVISON, Esq.
333 Southwest Taylor, Suite 400
Portland, Oregon 97204
BRAD M. PURDY, Esq.
Attorney at Law
2019 North Seventeenth Street
Boise, Idaho 83702
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For Monsanto:
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For Idaho Irrigation
Pumpers Association (IIPA):
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16 For Idaho Conservation
League (ICL):
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For PacifiCorp Idaho
Industrial Customers (PIIC):
For Community Action
Partnership Association
of Idaho (CAP AI):
HEDRICK COURT REPORTING
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APPEARANCES
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1 I N D E X
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WITNESS EXAMINATION BY PAGE
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Carol Hunter
(RMP)
585
588
609
623
637
647
659
661
Mr. Solander (Direct)
Prefiled Rebuttal
Mr. Otto (Cross)Mr. Olsen (Cross)
Mr. Purdy (Cross)
Mr. Woodbury (Cross)
Commissioner SmithMr. Solander (Redirect)
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8 Cindy Crane
(RMP)
Mr. Solander (Direct)
Prefiled Direct
Prefiled Rebuttal
Ms. Davison (Cross)
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666
676
690
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Darrell Gerrard
(RMP)
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696
715
735
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792
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Mr. Hickey (Direct)
Prefiled Direct
Prefiled Rebuttal
Prefiled Direct (Cupparo)
Mr. Otto (Cross)Mr. Olsen (Cross)
Ms. Davison (Cross)
Mr. Budge (Cross)
Mr. Woodbury (Cross)
Commissioner Redford
Commissioner Kempton
Commissioner Smith
Mr. Hickey (Redirect)
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18 EXHIBITS
NUMBER PAGE
For Rocky Mountain Power:
85 Hunter Sur-surrebuttal Updated Table
Page 10
Marked 587
23 For PacifiCorp Idaho Industrial Customers:
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619 PIIC Data Request 141 Marked 692
HEDRICK COURT REPORTING
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INDEX
EXHIBITS
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1 BOISE, lDAHO, WEDNESDAY, DECEMBER 1, 2010, 8:35 A.M.
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4 COMMISSIONER SMITH: Good morning, everyone.
5 Thank you for making what I know in some cases probably were
6 pretty heroic efforts to get through the snow to be here this
7 morning.
8 Mr. Hickey, do you have a report on your
9 examination of surrebuttal?
10 MR. HICKEY: I do. We had a chance to visit with
11 Ms. Hunter regarding the Olsen surrebuttal that was accepted
12 yesterday, and she will be addressing his surrebuttal -- the
13 surrebuttal filed by Mr. Olsen on behalf of his client
14 during her testimony this morning. So, in addition to her
15 direct testimony and her rebuttal testimony, we'll now have her
16 appearing once to deliver the sur-surrebuttal.
17 In addition, we have reviewed the testimony of
18 both Mr. Widmer and Mr. Falkenberg that was filed as
19 surrebuttal testimony, and we will not obj ect to that going
20 into the record with the request, Madam Chair, that we be able
21 to have the option of calling either Mr. Duvall or Dr. Shu to
22 present live sur-surrebuttal to that on Thursday.
23 COMMISSIONER SMITH: Mr. Hickey, you always have
24 that option. You i re the Applicant: You can save all your
25 rebuttal till the end or call whoever you need.
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1 MR. HICKEY: Thank you very much. With that
2 COMMISSIONER SMITH: And how about Mister -- or,
3 Dr. Peseau?
4 MR. HICKEY: I guess we didn't get a chance to
5 focus on Dr. Peseau, but I -- if you can give me just two
6 seconds--
7 COMMISSIONER SMITH: We can. We'll be at ease
8 for a few moments.
9 (Discussion off the record.)
10 MR. HICKEY: Thank you for the opportunity to
11 have a quick sidebar with my clients. And we have no obj ection
12 to Mr. Peseau' s testimony being made a part of the record, with
13 the understanding that we'll have witnesses that respond to it
14 live as well, Chairman Smith.
15 COMMISSIONER SMITH: Thank you. So, the
16 surrebuttal of those three you can present with your witnesses,
1 7 Mr. Budge.
18 And I think I agreed to look at the Motion to
19 Strike last night, which I did do. I think with regard to the
20 testimony of Ms. Iverson and Mr. Smith, I would deny the Motion
21 to Strike. I think a lot of the testimony is in the nature of
22 historical context, explanation, and none of it really goes to
23 the calculation of the value of the interruptibili ty.
24 I kind of lean in your favor, Mr. Hickey, with
25 regards to the testimony of Mr. Collins, and I think it does
581
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1 actually go into the issues that are in the second hearing that
2 we'll hold later, but I i m kind of torn whether it's really
3 harmful to have it in or not. I don't think it's necessary to
4 cross-examine on it. The Commission certainly won't be
5 evaluating it in this first round of setting rates. So, I
6 don't know, I'm kind of ambivalent about that.
7 MR. HICKEY: Okay. I think we'd certainly agree
8 wi th your observation, Chairman, that it does go directly to
9 the economic valuation, and we again understand that's exactly
10 the reason that there is a second hearing. Where I think
11 there's a prejudice here is if it comes in at this phase and
12 there's some examination on it and then they bring it in again,
13 they have actually had two opportunities to present a witness.
14 So, somewhere in that process if you let it in at this phase,
15 it seems like fairness would say that Mr. Clements or whoever
16 the appropriate Company-endorsed witness to respond to this
17 addi tional opportunity of Mr. Collins would be afforded to the
18 Company.
19 COMMISSIONER SMITH: Mr. Budge, do you have any
20 comment on this?
21 MR. BUDGE: I think the Chair's ruling is fine.
22 Excuse me. I understand the ruling is it will be accepted. I
23 reviewed carefully that testimony as well, and you can't deny,
24 even though the Company would like to, they would like to
25 assume for purposes of revenue allocation cost for the revenue
582
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COLLOQUY
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1 requirement phase and cost allocation to Idaho, they would like
2 to -- they would like folks to believe that Monsanto is a firm
3 customer all the time for all purposes, and that really was the
4 thrust of the testimony we had from Walje and McDougal and
5 Duvall. And as I looked at the Collins testimony and
6 Ms. Iverson's testimony, none of them proposed a methodology or
7 advocated a value or advocated a price for Monsanto
8 interruptibili ty. That was the part in phase two, and those
9 were all the numbers and the methods that we did, in fact, take
10 out of the initial testimony.
11 So, Collins i testimony is simply to address what
12 the Company has brought up in their whole case. They're trying
13 to say there's no difference between the service to Monsanto
14 and any other customer and we are firm for all purposes; and
15 they want to then treat us as firm for purposes of allocating
16 costs to Idaho under their jurisdictional allocation study and
17 that's--
18 COMMISSIONER SMITH: I understand the distinction
19 between issues regarding cost allocation and issues regarding
20 valuation of the interruptibility, which is why I frankly think
21 Ms. Iverson's testimony gets to stay in.
22 Here's what I'd like to do: I think Mr. Budge
23 can present the testimony, you can register your obj ection.
24 I'll let it be spread on the record, but if the cross goes to
25 issues that you believe really should wait, then obj ect and
583
HEDRICK COURT REPORTING
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COLLOQUY
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1 we'll deal with it that way, with the knowledge that the
2 valuation of the interruptibility is really in the second
3 phase.
4 MR. HICKEY: Are we in agreement then that
5 Mr. Collins would not be brought again in February for a second
6 opportuni ty to testify?
7 COMMISSIONER SMITH: No, I don't think that was
8 part of the deal.
9 MR. HICKEY: Okay.
10 COMMISSIONER SMITH: I would expect that they
11 would either refile testimony we don't consider this time, or
12 they would refile a supplemented with actual testimony
13 regarding valuation. That would be my expectation; I don't
14 know about them. So, no, I don't think this would foreclose
15 him from appearing in the second phase, just as none of your
16 witnesss are foreclosed.
17 Mr. Hickey, did you have any further comment?
18 MR. HICKEY: No. We were just discussing the
19 fact that we'll probably call a rebuttal witness to respond to
20 Mr. Collins, but understand from your prior comments that we
21 don i t even need to make that request into the record.
22 COMMISSIONER SMITH: That's right.
23 MR. HICKEY: So we're ready to call a witness
24 when you are and whenever your fellow Commissioners are.
25 COMMISSIONER SMITH: I think we're as ready as
584
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COLLOQUY
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1 we're going to get.
2 MR. HICKEY: Good. All right, we'd like to call
3 Carol Hunter as our next witness, and she'll be handled by
4 Mr. Solander.
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6 CAROL HUNTER,
7 produced as a witness at the instance of Rocky Mountain Power,
8 being first duly sworn, was examined and testified as follows:
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10 DIRECT EXAMINATION
11
12 BY MR. SOLANDER:
13 Q.Good morning.
14 A.Good morning.
15 Q.Could you please state and spell your last name
16 for the record?
A.My name is Carol Hunter: C-A-R-O-L, H-U-N-T-E-R.
Q.And by who are you employed and in what
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A.Rocky Mountain Power, as vice president.
Q.And are you the same Carol Hunter that filed
22 rebuttal testimony in this proceeding on November 16, 2010?
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A.Yes, I am.
Q.And do you have any changes or corrections to
that testimony?
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (Di)
RMP
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1 A.Yes, I do:
2 I'd like to change on page 10 -- excuse me, on
3 page 5 of my testimony, line 20, is the word "participants."
4 I'd like to change that to "total resource," so that that line
5 would read "cost test and the total resource cost test."
6 COMMISSIONER SMITH: If you could hold up a
7 minute, I'm lagging.
8 Okay, got it. All right, thank you. So if you
9 could say that one more time?
10 THE WITNESS: Okay. On page 5, line 20, the
11 sixth word in is "participants." That should say "total
12 resource" instead of "participants."
13 Q.BY MR. SOLANDER: In light of the ruling from the
14 Commission, have you read the surrebuttal testimony prepared by
15 Mr. Mickelsen?
16 A.Yes, I have.
17 Q.And have you prepared a statement responding to
18 Mr. Mickelsen you would like to share with the Commission
19 today?
20 A.Yes, I have.
21 Q.And did you also prepare an exhibit as part of
22 that sur-surrebuttal?
A.Yes, prepared a exhibit updating the exhibit on
24 page 10 of my prefiled testimony.
25 MR. SOLANDER: May I approach the witness?
586
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (Di)
RMP
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1 COMMISSIONER SMITH: Yes, you may. So would this
2 be Exhibit 85?
3 MR. SOLANDER: Rachel?
4 RACHEL: I think it was 620.
5 MR. HICKEY: You are correct, Chairman, it's
6 Exhibit 85.
7 COMMISSIONER SMITH: All right. We'll have this
8 marked as Exhibit 85.
9 (Rocky Mountain Power Exhibit No. 85 was
10 marked for identification.)
11 Q.BY MR. SOLANDER: And with the exception of the
12 correction that you made earlier on page 5 and this updated
13 table that I believe will replace the table on page 10, if I
14 were to ask you the questions set forth in your rebuttal
15 testimony, would your answers be the same today?
16 A.Yes, they would.
17 MR. SOLANDER: I would move that the prefiled
18 rebuttal testimony of Carol Hunter be spread upon the record,
19 including the Updated Table Page 10 as now Exhibit 85.
20 COMMISSIONER SMITH: Is there any obj ection?
21 Seeing none, the prefiled testimony of Ms. Hunter
22 will be spread upon the record as if read.
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THE WITNESS: Thank you.
(The following prefiled rebuttal testimony
of Ms. Hunter is spread upon the record.)
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (Di)
RMP
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1 Introduction
2 Q. Please state your name and business address.
3 A.My name is Carol L. Hunter. My business address is One Utah Center, 201 South
4 Main, Salt Lake City, UT 841 1 1.
5 Q.By whom are you employed and in what position?
6 A.I am a Vice President for Rocky Mountain Power.
7 Q.Please describe the responsibilties of your current position.
8 A.I am responsible for demand-side management for Rocky Mountain Power and
9 for Pacific Power. This includes, the planning, development, design, approval
10 and implementation of programs designed to reduce energy consumption though
11 energy efficiency and behavioral changes and to reduce consumption durng peak
periods of usage through load control.
Qualifications
Q. Please describe your background.
A. I received a B.S. in mechanical engineer in 1977 and an M.B.A. in 1987 from the
University of Utah. I joined PacifiCorp in 1977 as a customer service engineer
and have held various management positions in resource planning, wholesale
marketing, community and business services and economic development. In
2004, I was promoted to vice president.
I held numerous board positions over my 30 year career and curently
serve on the executive board of the Salt Lake Chamber of Commerce, the Idaho
Strategic Energy Allance and the energy efficiency subcommttee of the Utah
Energy taskforce.
588 Hunter, Di-Reb - 1
Rocky Mountain Power
.1 Q.Have you previously filed testimony in this proceeding?
2 A.No.
3 Q.What is the purpose of your testimony?
4 A.The purose of my testimony is to respond to or rebut certain issues raised in the
5 testimonies of Mr. Randy Lobb and Mr. Gar Grayson of the Idaho Public
6 Utilties Commssion (the "Commssion) Staff as it relates to the investment in the
7 company's energy efficiency and load control programs.
8 Q.Please summarize Mr. Grayson's testimony as it relates to the Company's
9 energy efficiency and load control programs?
10 A.Mr. Grayson addressed: (1) the prudency of the 2008 and 2009 investment in
11 energy effciency; (2) the issue he refers to as "customer segment equity"; and (3).12 the use of a tarff rider to recover the costs associated with the Company's
13 demand-side management program.
14 Q.Please summarize Mr. Lobb's testimony as it relates to the Company's
15 irrigation load control program?
16 A.Mr. Lobb believes that the irgation load control program allocation is not
17 reasonable because "Idaho receives a reduction of system costs that equate to a
18 program benefit of approximately 66 percent ($7.0 millon/$ 11.4 millon) of the
19 costs."i He views this as unfai when 100 percent of the program costs are
20 diectly assigned to Idaho. Mr. Lobb proposes that the "Company treat the
21 program costs as system purchase power cost and allocate them just as it would
22 any other system power supply expense."i
.1 Randy Lobb Direct Testimony Page 15, Lines 3-5.
2 Ibid, Page 16, Line 2-4.
589
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Rocky Mountan Power
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1 Prudency
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Did Mr. Grayson find the 2008 and 2009 energy effciency and load
management programs operated by Rocky Mountain Power in Idaho
prudent.
Yes, he indicates that the 2008 - 2009 program were "generally prudent and
cost-effective. ,,3
Please summarize Mr. Grayson's testimony regarding "customer segment
equity."
Utilzing the total investment in energy efficiency and load control for the
company's programs in 2009, Mr. Grayson calculates the percentage of the total
investment by class. Based on this analysis he determned that 81 percent of the
DSM expenditures were associated with the irgation load control program with
the remaining 19 percent going to support the residential' energy efficiency
programs (6.5%,) commerciaVindustral (4.5%,) agricultural (5.9%) and market
transformtion (2.1 %.) Based on this evaluation he indicated that the Company
should endeavor to find ways to "pursue all cost-effective DSM while strving
toward greater balance with regard to customer segment equity."
It is important to note that while Mr. Grayson's analysis is correct when
looking at the overall demand-side management portfolio, the energy efficiency
portfolio, excluding market transformtion is faily well balanced between
classes; residential at 38 percent of the investment made in energy efficiency,
commerciaVindustrial at 27 percent and agriculture at 35 percent.
3 Gar Gryson Dirt Testimony, page 7 lines 4-9.
590
Hunter, Di-Reb - 3
Rocky Mountai Power
591 Hunter, Di-Reb - 4
Rocky Mountain Power
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We could attempt to acclerate the acquisition of energy efficiency
savings in the residential and commerciaVindustral segments by increasing
incentives. Modest increases might improve the "customer segment equity"
without a significant impact to the program cost effectiveness or quality control.
Significant increases, however, could reduce the cost effectiveness and have an
adverse impact on the quality control of the programs. Consequently while you
could mitigate an imbalance in the customer segment equity increasing spending
in the other customer segments could raise prudency issues.
As an alternative or in addition to increases in investment in the residential
and commerciaVindustrial segments, steps could be taken at this time to reduce
the investment in the agricultual segment in 2011 without an ~dverse impact on
the overall cost-effectiveness of the demand-side management portfolio.
How would you approach reducing the investment in the agricultural
segment?
There are only two progras available to ths segment; the Agricultural Energy
Savers Program and the irgation load'control program. As Mr. Hedman
indicated in his diect testimony both of these programs were cost-effective;
however, the Agricultual Energy Savers program's benefit to cost ratio was
lower than the irgation load control program's benefit to costratio on a utilty
cost test basis and the paricipants cost test basis. While from a utilty standpoint
the Agricultural Energy Savers program is cost effective, eliminating the program
would have a beneficial impact on the overall energy efficiency portfolio cost
effectiveness. The overall energy efficiency portfolio cost effectiveness would
592
Hunter, Di-Reb - 5
Rocky Mountain Power
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improve from 1.93 to 2.05 as measurd by the utilty cost test.
Would you recommend this action absent the issue of customer segment
equity?
While the 2009 Agricultual Energy Savers program was determned to be cost
effective, the program's benefit to cost ratios, as measured by the PacifiCorp total
resource cost test, the total resource cost test, utilty cost test, and the ratepayer
impact test, are lower than irgation load control's benefit to cost ratios.
Consequently before reducing the irgation load control program beyond the
recommendations I discuss later in my testimony, I would recommend eliminating
the Agricultual Energy Savers program.
Irrigation Load Control Progrm
Q. What is the current status of the irrigation load control program?
A. Two of the thee thid-par delivery vendor agreements utilzed in operating this
program were set to expire on December 31,2010. Based on the expiration date
of these agreements a request for proposal ("RF") was prepared and issued in
July of this year. The RF was later cancelled given uncertinty related to the
ongoing natue and strctu of the program and the potential changes resulting
from the Staff s review and recommendations.
At this time we have extended the remaining two agreements though
2011 and anticipate the RFP wil be reissued during the second quarer of 201 1.
The RFP includes an option for the continued operation of the program utilizing
multiple vendors as subcontractors. Once the responses are received they wil be
evaluated on technical and commercial terms prior to awarding an agreement. If
593
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Rocky Mountan Power
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the curent approach is determned to be less costly after consideration of the
technology and risk, the Company wil continue operating the program as it does
today. Otherwise, the new agreement covering the operation of the program wil
be completed in time for the 2012 control season.
It is important to note however, any control unit purchase before or durg
the 2011 control seasons has a reasonable probabilty of only being in service one
year as a result of the procurement process.
What actions must the Company pursue pending re-procurement?
As stated, the company wil be extending its agreement. To avoid purchasing
new equipment the company wil seek to optimize the existing equipment.
While the company has had the authority under its tarff to restrct paricipation
by customers with irgation equipment motor load size less than 30 Hp, it has not
done so. However when we factor in the cost associated with recursive field
costs, which doesn't var by pump size, the smaller pumps contrbute less to the
overall cost effectiveness of the program. By restrcting paricipation during the
2011 control period to equipment greater than 30 Hp in size approximately 300
control units wil be made available to replace damaged or failed units on larger
equipment while only reducing the total connected irgation load under contract
by approximately 8 megawatts. If we.extend the limitation to all equipment 50
Hp or less in size approximately 500 control units wil be made available with a
total reduction of approximately13 megawatts. In summar, by limiting
paricipation in 2011 to larger equipment we optimie the use of the equipment
thereby improving cost effectiveness.
594
Hunter, Di-Reb - 7
Rocky Mountan Power
.1 Q.How do you respond to Mr. Lobb's concerns that Idaho customers may not
2 be receiving the full benefits of the program while paying for the ful cost?
3 A.This situation may exist if the curent costs are built into rates in 2011 on an Idaho
4 situs basis. However, the company is also placed in a difficult position by Staff s
5 proposal that an allocation of costs would occur, shifting program costs away
6 from Idaho to other states before the issue has been addressed and resolved by the
7 MSP Standing Commttee or factored into cost recovery filings in other states.
8 While the program is cost effective as compared to alternatives, shareholders do
9 not receive compensation for benefits achieved (costs not incurred), only the
10 recovery of its actual costs. As a result, the company believes that 2011 should be
11 treated as a transitional year to afford the company and Staff the opportnity to.12 work together to address the treatment of Class 1 DSM resources with the MSP
13 Standing Commttee.
14 Additionally, the Company believes that certain changes need to be made
15 to the program to increase its cost effectiveness and resolve operational issues that
16 have been identified during the last two years as the program rapidly expanded.
17 Q.What changes do you propose?
18 A.The company proposes that the irgation load control program continue to be
19 treated as a situs assigned cost during 2011 to allow the issue to be addressed with
20 other states through the MSP process. Additionally, the Company proposes to
21 make certain adjustments to the program to reduce the costs of the program and
22 increase its effectiveness..
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Rocky Mountain Power
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Please identify the changes that you are proposing to the irrigation load
control program.
The Company proposes that the following changes be made to the program:
. Increase the authority under the tarff to restrict paricipation by customers
with irgation equipment motor load size from less than 30 horsepower
(Hp) to a minimum of 50 Hp;
· Add Idaho Power's paricipation selection language to the tariff
"The Company shall have the right to select and reject Program
paricipants at its sole discretion based on criteria the Company
considers necessar to ensure the effective operation of the Program.
Selection criteria may include, but wil not be limited to; Biling
demand, location, pump horsepower, pumping system configuation,
or electrc system configuation. Past paricipation does not ensure
selection into the Program in futue years. Parcipation may be limited
based upon the availabilty of the Program equipment and funding."
· Change the penalty for opt-out events available to the Schedule 72A
parcipants to a percentage reduction in the paricipate credit for each
event as follows:
.1 opt out event 100% of the parcipation credit paid to paricipant
2 opt out events 90% of the participation credit paid to paricipant
3 opt out events 70% of the parcipation credit paid to paricipant
4 opt out events 50% of the participation credit paid to paricipant
5 opt out events 25% of the paricipation credit paid to paricipant
6 opt out events paricipation in program termnated for the year
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. Reduce the paricipation credit to $25 per kW in 2011 and then reinstitute
the $30 per kW in 2012;
· The Company and IPUC Staff should work collaboratively to address the
issue of system allocation of demand response programs with other states
through the MSP Standing Commttee or other appropriate venues.
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Benefit
Pump (g Net
Size kW $44/kW Cost Benefit
30 22 985 1,340 (355)
35 26 1,149 1,340 (191 )
40 30 1,313 1,340 (27)
45 34 1,477 1,340 137
50 37 1641 1,340 301
.
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.1 Q.
2
3 A.
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.12
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18
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22.23
Please explain the change in tariff language you are recommending to align
the company with Idaho Power's participation selection languge.
Beginning in 2008, the program manager for the irgation load control program
began fielding complaints from the distrbution field engineers regarding voltage
excursions during dispatch events. In response, the program manager began
notifying distribution engineering of pending events so troublemen could make
the necessar adjustments to the system to limit the impact to the system.
Program participation continued to grow and in 2009 the solution implemented in
2008 was insuffcient to address the issue.
During the period following the 2009 control season the program manager
working with the company's engineers identified the upper limits of the load that
could be removed from each circuit without adversely impacting the distribution
circuit, distrbution substation, transmission substation and/or generating voltages
that impacted end-use loads. On a circuit by circuit basis and ultimately on a
grower by grower basis loads were organized so they could be "stair-stepped" on
and off in three minute intervals. While this approach resolved par of the issue
there was stil an issue on select distribution substations where reductions were
limited to a certain magnitude. In these instances only solution was to allocate
load away from the 2:00 - 6:00 p.m. dispatch to two dispatch periods 11:00 a.m.-
3:00 p.m. and 3:00 -7:00 p.m. The result was three distinct dispatch periods and
within each of the dispatch periods approximately five different "stair step"
dispatches. While this best utilzes the loads under management it dilutes the
program's contrbution during the highest peak hours when the control is need the
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1
2
3
4
5
6 Q.
7
8 A.
9
10 Q.
11 A.
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14
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most.
By including language in the company's tarff, Rocky Mountain Power
would have the flexibilty to manage the load on any given substation or ciruit.
By better managing the loads we can improve the impact of the load control
program at peak, lower costs and as a result improve cost effectiveness.
Would the Company be requesting this change absent the concerns
expressed by Mr. Lobb and Mr. Grayson?
Yes. As paricipation in the program has increased, transmission and distrbution
issues of this natue have become more prevalent.
Please explain the changes to the opt-out penalties you are recommending.
Let me star by summarzing the current program. Parcipants in Schedule 72A
Dispatchable Irgation program agree to allow the Company to dispatch their
pumps for 52 hours per year. Each dispatch event cannot exceed four hours
totaling a maximum of 13 interrptions annually. Program paricipants are
permtted to "opt-out" of up to five events on the sixth event they are termnated
from the program. If they do opt-out they pay the posted day ahead market price.
While the company only experienced 2.9 percent of customers opting out of
control events, the penalty associated with opting out is inconsistent with the
impact to the program. Consider the following example:
· Assume an irgator opts a 135 Hp pump (100kW) out of the program
durng five control events.
22 . Assume an average value of the liquidated damages in 2010 curently
23 provided for in the taff.
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.1
2
3
4
5
6
7
8
9 Q.
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11 A..12 Q.
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14 A.
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20 Q.
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22 A..23
· Under the curent tarff provision the irgator would receive 96 percent of
the total paricipation credits.
. Base on the proposed opt-out schedule the irgator would only retain 25
percent of the credits.
The proposed change wil improve the performnce of the program by (1)
reducing the number of opt-outs and as a result increasing the amount of load
reduced during events, and/or (2) reducing the total incentives reducing the
overall cost of the program.
Would the company be requesting this change absent the issues raised in this
cae?
Yes.
What would the impact be to the program if the incentive payments are
lowered to $25 during 2011 ?
We anticipate that some customers wil elect to suspend participation in the
program. Given the number of factors that may impact a customer's decision to
suspend parcipation, we are unable to provide an estimate of the impact on the
overall size of the program. Assuming however 230, megawatts of connected
load, the proposed change in incentive payments wil result in a $1,150,000
reduction in credits.
How would customers benefit from these program changes if they reduce
costs and increase program effectiveness?
The company wil credit the savings from these changes to the demand-side
management balancing account for the program savings in excess of the amount
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.1 in base rates and reduce the amount owed from customers to the company in that
2 account. This wil speed up the amortization of that account and provide greater
3 flexibilty with the level of the surcharge related to the DSM program cost
4 recovery.
5 Q.Wil these changes resolve the customer segment equity issue raised by Mr.
6 Grayson?
7 A.No. While reducing the costs mitigates the issue raised by Mr. Grayson it does
8 not elimnate the issue. To ensure customers in one class are not paying for
9 energy savings or load control in another class, the costs associated with each
10 segment could be assigned a separte balancing account representing the
11 segments identified by Mr. Grayson. The cost associated with each balancing.12 account would then be recovered from the appropriate customer segment. For
13 example, the cost associated with energy efficiency programs are assigned to
14 three separate balancing accounts in Wyoming - residential,
15 commerciaVirgation and large industraL. The cost associated with each segment
16 is recovered from the customers in the segment. A similar approach could be
17 used in Idaho separating the costs into the thre customer segments identified by
18 Mr. Grayson.
19 Q.You stated that Mr. Grayson questioned the use of a tariff rider for recovery
20 of costs associated with the company's energy effciency and load control
21 programs. Can you expand?
22 A.Yes. He indicated that most customers are not famliar with the long-term.23 benefits associated with energy efficiency and load control programs and as a
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.1 result customers, especially non-paricipants, question the customer efficiency
2 service charge. Mr. Grayson however did not recommend a solution.
3 Q.Does the company utilze a line item customer effciency service charge to
4 recovery costs associated with energy efficiency in all of its jurisdictions?
5 A.No. Consistent with the other states served by PacifiCorp, the Washington
6 Utilties and Transportation Commssion utilzes a balancing account to ensure
7 recovery of all expenses associated with demand-side management. However,
8 rather than setting a rate based on a percent of revenue to recover the costs, the
9 Washington Commssion sets a rate based on the cost per unit of sales. The rate
10 is then applied to a customer's usage and incorporated in the overall cost of
11 providing service, eliminating the need for a customer efficiency service charge.12 on the customers' bil.
13 Q.Would this eliminate the issue raised by Mr. Grayson in his testimony?
14 A.Yes, as I understand his issue.
15 Q.Does this conclude your rebuttal testimony?
16 A.Yes.
.
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.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 Q.BY MR. SOLANDER: Ms. Hunter, would you please
4 proceed with your sur-surrebuttal testimony?
5 A.Yes, thank very much, and I appreciated the
6 opportuni ty to have a chance to review Mr. Mickelsen's
7 testimony.
8 On reviewing his testimony, it was clear that,
9 you know, additional explanation regarding the cost
10 effectiveness of the program is needed to answer some of the
11 questions he's -- some of the issues he's raised, particularly
12 regarding the Company's intent by the changes I proposed in my
13 testimony. Mr. Mickelsen indicated that it was his belief that
14 our intent was to reduce the cost of the program.
15 The proposals in the testimony prefiled went to
16 improving the efficiency or cost effectiveness of the program.
17 We have discussed on prior cases that the value of irrigation
18 load control on a long~term basis from our IRP is approximately
19 $73. That $73 applies not to the connected load we have in
20 Southeastern Idaho that's irrigation load or the connected load
21 that is participating in the program. That $73 is to apply to
22 the amount of load that we can reduce at the time of peak.
23 And so as you -- as you take a look at the value
24 and the benefits, you'll notice in I believe it is the fourth
25 column, you take the $73 and you have to adjust it for the
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1 actual amount of load available to control, and as Pete Eelkema
2 will testify, that's approximately 185 megawatts.
3 So, you take 185 megawatts and you divide it by
4 the amount of connected load participating in the program,
5 which is 285 megawatts, and you come up with 68 percent. That
6 68 percent needs to be applied to the $73 so that the $73 would
7 then be reflective of the value per connected kilowatt hour of
8 load.
9 And then, you know, you do -- we do need to
10 recognize that í t also reduces line losses, so then you
11 increase that by approximately 10 percent. You come up with
12 the $55 shown in Column 4. That is the what we call realized
13 value of the approximately 256 megawatts of load that was
14 connected to the system in 2009.
15 It's a little cumbersome calculation, but it just
16 goes to the point that how much did you actually have available
17 to save versus the amount that you had connected, and that's
18 how we sort of work through this. It's called a realization
19 rate. We'll be talking a great deal more to Staff and to the
20 Commission as we complete our impact studies for the
21 demand-side management programs over the next six months.
22 The cost is not merely the cost of delivery, but
23 it's the cost including the incentives. You have to take a
24 look at all of the cost, and in doing so, then you have an
25 abili ty to compare the benefits versus the cost. And as that
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1 realization rate shrinks or gets lower, so the more connected
2 load you have, if you don't, along with additional connected
3 load, gain the ability to control more load at the time of
4 peak, that the net benefits of the program suffer.
5 And so the proposals we've made in the testimony
6 go to improving that ratio, trying to increase that 68 percent
7 to a higher value. In 2008, we were operating the system and
8 at a level where we weren't causing a great deal of problems to
9 the transmission and distribution system. As we increase
10 participation in the program -- because, as Mr. Mickelsen
11 indicated, it's been successful; we're very pleased with our
12 relationship with the irrigators, they have been great to work
13 wi th -- but with success has come some transmission and
14 distribution operational issues.
15 So in 2009, our transmission and distribution
16 folks indicated that when we took a control event -- so when we
17 dropped the irrigation load -- the reduction in current on our
18 lines caused a increase in voltage that was unacceptable. So
19 we were causing transmission and distribution operational
20 issues in Southeastern Idaho.
21 So between 2009 and 2010, we worked on trying to
22 figure out how you would how you would go into a control
23 event so you wouldn i t cause what we call voltage excursions,
24 and how you would come out of the control event in a way that
25 you wouldn't drop the voltage. Because as the current goes up,
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1 the voltage goes down, and so you would have the opposite
2 problem coming out of the event.
3 We came up with a dispatch protocol that would
4 drop portion of the load on each circuit every three minutes
5 and step us into it, and we worked a great deal with the
6 irrigators because we not only had to identify how much load we
7 could take every three minutes, but we had to match that to the
8 pumps that we had in the field and we had to confirm with the
9 irrigators that it was acceptable as we took these approaches.
10 So as we went through that, we got to where we thought we could
11 drop the load and discovered that the amount of load we had
12 available to drop on any given circuit in Southeastern Idaho
13 exceeded the circuit i s ability to allow that much load off the
14 circuit. So, we have a foundation problem where we have more
15 load to shed than we have the capability to shed, and it has to
16 do with the operation of the T and D system.
17 At that point in time, we started taking load out
18 of what we called the "sweet spot" control period, the two p.m.
19 to six p.m., which is the highest value and typically where we
20 peak, and we started moving it into the 11 a.m. to two -- 11 to
21 three p.m. period of time. So we actually had to move some of
22 the load earlier in the day, keep some of the load during the
23 mid part of the day, made it through that, thought we were in
24 good to go for 2010, and we discovered midway through the 2010
25 control season we still had too much load on certain circuits
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1 and we had to move some of the load to the seven a. m. to 11
2 a.m. bracket.
3 Now, the tariff does not provide for our ability
4 to move load to the seven a. m. to 11 a. m. bracket, so we did
5 obtain approval by the irrigation customer that was involved to
6 move the load control event there. The Company was faced with
7 either discriminating by not controlling all of the customers
8 equally, or moving that load into a period where the value
9 wasn't -- wasn't as great as it would if it were in the two to
10 six p.m. bracket.
11 So as we've tried to manage this wildy successful
12 load control program, we've discovered that there are certain
13 constraints that we have as a system that we have to
14 acknowledge. For those of you who are not familiar with the
15 Idaho irrigation load control program, it probably is one of
16 the best examples of smart grid you will find in the country,
17 and it has been very, very effective. The irrigation
18 customers, as Mr. Mickelsen says, I think our relationship with
19 the irrigation customers has been fantastic, but we have
20 discovered that too much load to control can drive the value of
21 the program down; that is, that the customers are paying more
22 for a program than they would need to pay for it if we were to
23 optimize it by constraining some of the participation in the
24 program.
25 So, the proposals made in my prefiled testimony
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1 were operational considerations that we're looking at in an
2 effort to constrain that load. Absent that, the customers are
3 paying for load that we really can't control. And for every
4 dollar that we pay in incentives, the rest of our Idaho
5 customers are paying for that dollar in their net power costs.
6 And so in response to Mr. Lobb' s issues and
7 Mr. Grayson's issues, we looked seriously at ways to optimize
8 this program, and how do you -- how do you look at it and how
9 do you operate it in a manner that you get the greatest value
10 for the dollar invested by our customers.
11 Q.Does that conclude --
12 A.No, there was one other issue, and, I'm sorry, I
13 failed to mention, and that was Mr. Mickelsen's discussion
14 about the $30 incentive payment.
15 The recommendation made in my prefiled testimony
16 was not made easily, it was a very difficult decision to make,
17 but as I mentioned, for every dollar paid incentives, our Idaho
18 customers are paying that dollar into the net power costs. So
19 in looking at trying to temper that and pull it back so that
20 we've got a efficient program where we're only paying what we
21 need to pay to get the value, the recommendation was to reduce
22 the cost per kilowatt hour.
23 Q.Thank you.
24 MR. SOLANDER: Ms. Hunter is available for
25 cross-examination.
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20
1 COMMISSIONER SMITH: Thank you very much.
2 Mr. Otto, let's start with you today.
3 MR. OTTO: All right. I do have a few questions
4 for Ms. Hunter.
5
6 CROSS-EXAMINATION
7
8 BY MR.OTTO:
Q.Thanks for braving the snow today,so --
A.It was my pleasure.I'm a skier:It's okay.
Q.I guess Utahns know how to do it,so --
A.Yeah.
Q.Sorry,I wasn't expecting to go first;give me
9
10
11
12
13
14 one second here.
15 A.Not a problem.
16 Q.Okay. Let's start with your proposal to consider
17 transitioning the irrigation load control program to a system
18 resource.
19 A.Actually
Q.You said sorry, I didn't mean to interrupt.
21 I wanted to clarify my question.
22 You testify on page 8, at lines 14 and for a few
23 lines after that, that it's something that Staff and the
24 Company and others should consider; the proper procedure you
25 think is to go through the multistate protocol committee to
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1 consider that; and you say that we should maybe treat 2011 as a
2 transition year for this kind of -- exploring this option.
3 A.Uh-huh.
4 Q.Is this something that the Company is prepared to
5 commit to 2011 being a transition year and really exploring
6 this option?
7 A.You know, the Company looks at this from the
8 perspecti ve that our demand-side management programs are a
9 are such that we do not make any money or expect to make any
10 money. We operate these to the benefit of our customers. So
11 we were looking just merely for recovery of our cost associated
12 wi th these programs.
13 The statements on page 8 were such that if the
14 Commission decided or determined that it was necessary or that
15 they believed that it should be treated on a mul tistate basis,
16 that they provide a one-year transition period so the Company
17 is not unduly harmed from operating what has been, I believe, a
18 successful program; and that we have an opportunity in that
19 one-year transition period to recover our cost of the program
20 and operate in 2011. Absent that transition year, basically
21 have no revenue to operate the program on and, you know, that
22 becomes quite problematic.
23 So the proposal is, yes, I believe -- and I am
24 not the expert on mul tistate process by any means; I operate
25 demand-side management. I would recommend that if you've got
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1 questions about the mul tistate process, talk to Mr. McDougal
2 who will handle that for the Company. But I believe that's the
3 appropriate forum to bring that issue in front of the
4 mul tistate, that there is an Agreement in place that all
5 demand-side management programs be treated on a situs basis,
6 but, again, I'm not the expert.
7 Q.Thank you for that. I'm going to move on to
8 specific issues in the load control program now, and on page 5,
9 lines 6 through about 14, one of the -- let me check that real
10 quick.
11 I'm sorry, I'm referring to Mr. Mickelsen's
12 surrebuttal testimony which was -- did I get his name right? I
13 apologize. Yeah, Mickelsen.
14 On his testimony, page 5, lines about 6 through
15 14, he talks about one of your proposals to change the eligible
16 pump size to 50 horsepowers and above, and that that would
17 impact 25 percent of sites.
18 Now, is it true that individual participants or
19 customers may have multiple sites?
20 A.Yes, that is true. It also is true that when you
21 take a look at sort of the realized value of the irrigation
22 program from the table that I provided, that those smaller
23 pumps at this point in time are not cost effective with the
24 realization rate of 68 percent included.
25 Q.Now, considering that a single customer may have
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1 multiple sites, do you have any indication of how many
2 customers would be impacted by changing to 50 horsepower?
3 A.This is the wonder of the Idaho irrigation load
4 control program. A great deal of learning goes into working
5 with the Idaho irrigation customers. I grew up in Eastern
6 Wyoming on a ranch, and so was not unfamiliar with the
7 practices.
8 They do lease property back and forth, so it's
9 difficul t at any point in time to tell you how many customers I
10 have in any given segment because it changes from year to year.
11 So one irrigator may be irrigating -- may own property that he
12 irrigates or she irrigates for five out of six years, but on
13 that sixth year they may turn that -- lease that property to
14 some other individual in the area to raise crops on. So, it's
15 not uncommon for us to have, you know, a lot of movement in
16 this program that we're trying to manage to ensure that the
17 credits are given to the right individual and that, you know,
18 we get everything trued up at the end of the year.
19 So it's difficult for me to tell you how many
20 customers. I can give you real good data on sites, but the
21 number of customers are extremely difficult to get a real good
22 hold on.
23 Q.And just for maybe my education, when you give
24 the credits, do those go to a site or do they go to a
25 customer?
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1 A.We work with the irrigators to make sure that the
2 irrigator who's paying for the energy to water a certain area
3 of crops are the ones that ultimately, you know, get the
4 appropriate credits. So it is a lot of -- lot more work than I
5 think any of us had anticipated making sure that everything is
6 trued up at the end of the year.
7 We have what we call true-up meetings where we
8 discuss these issues with the irrigators and we meet with them,
9 and if there's any issues we meet with multiple irrigators and
10 we talk about their -- how many opt-outs they may have taken
11 during the year and confirm those so that they know what
12 they're going to be getting in their incentive checks. We also
13 talk about any other issue that may be in existence. We do
14 that at the beginning of the year and we also do it as we close
15 out the year.
16 Q.Great, thanks. That's helpful to me, at least.
17 Now I'm going to turn to -- to the issue of the
18 back balance on your DSM account.
19 A.Yes.
20 Q.On page 10, lines 5 through 9 of your testimony,
21 you make two recommendations about the eliminating the spending
22 on the NEEA program and the agricultural energy savers program,
23 and you say that will allow the Company to reduce its past
24 balance. Also, you're also proposing some changes to the
25 irrigation load control program: Limiting to 15 horsepower,
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1 changing the incentive payment.
2 When you're considering being able to payoff
3 that back balance, are you factoring in kind of all four of
4 those changes I just listed?
5 A.You know, the items you listed are
6 recommendations to the Commission with respect to what actions
7 we could take to reduce the cost of demand-side management
8 going forward in sort of a, you know -- what would have, you
9 know, the least impact on the customers right now would be the
10 NEEA contract because it's a mid-market activity where NEEA
11 works upstream of the customers and upstream of the actual
12 acquisition process. So there isn't a customer going to a
13 store and expecting to get an incentive from the Company for
14 buying energy efficiency. It rather works mid-stream.
15 And in our market as we've developed our home
16 energy savings programs and our commercial energy savings
17 programs, we've picked up some of that acti vi ty already. So
18 we've taken a look at NEEA and believe that, you know, to pull
19 the back balance down, not -- not entering into another
20 extensi ve contract with NEEA for Southeastern Idaho would
21 probably be in the interest of our customers if the question is
22 that the investment in DSM is too high.
23 The next one would be as we take a look at the
24 cost effectiveness of the program, and we've looked at
25 Mr. Grayson's testimony on customer segment equity, we've
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1 looked at those things and said if you're going to eliminate
2 something, it would probably be the agricultural energy savers
3 program. While it's cost effective, it's not as cost effective
4 as our other energy efficiency programs. So we would recommend
5 that.
6 So that was the basis of the recommendations.
7 The basis of the recommendations for the load
8 control program, the bulk of those recommendations on the
9 opt-outs and being allowed to include the Idaho Power language
10 in our tariff to deal with what we call "system issues," that
11 was just to improve the effectiveness of that program. And
12 then we also provide a recommendation on, you know, the impact
13 if you were to reduce the incentive payments from $30 to $25
14 for the Commission's consideration.
15 Q.So it's kind of a menu of items?
16 A.Yes.
17 Q.In terms of dollars that would be saved, how
18 would you rate that menu as kind of the best way to -- not the
19 best way -- the most dollars that could go towards reducing the
20 back balance?
21 A.Let me -- give me a second and I'll get a table
22 here that has the expenditures.
23 In 2009, the NEEA energy efficiency Agreement ran
24 it at just under 300,000. The cost of that contract has gone
25 up, so it will be closer to, you know, 350- to 400,000.
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1 The agricultural energy service in 2009 closed at
2 about 800,000. We expect it to close in that range, slightly
3 higher, for 2010, so you've got that.
4 The I believe in my testimony I indicated the
5 amount that would be saved if you were to reduce the incentive
6 by $5, and that was just about a million, 150, to a million and
7 a quarter on the Idaho irrigation load control just on the
8 incenti ve change.
9 The changes associated with improving the
10 effectiveness of the program, at this point in time it's
11 difficult to give you a -- you know, a absolute number on how
12 much we would save in cost. What we would do would be reducing
13 the connected amount of irrigation load control in hopes of
14 improving that ratio.
15 Q.So there would be some benefits there lost?
16 A.There would be some benefits. You know, right
17 now I know that I've got 26 megawatts that I'm dropping in the
18 seven a. m. to 11 a. m. period. I know that 26 megawatts, if I'm
19 going to have it, I'd prefer to have it between two and 2: 00
20 and 6:00, and I can't put it there. So I know at least 26
21 megawatts is problematic. And, you know, it could be more than
22 that as we go into the next control season. We see a lot of
23 fluctuation as we move. So far, all the fluctuation, however,
24 has been up.
25 Q.So just to kind of summarize, I think you rate
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1 them as the irrigation, changing the credit on the load control
2 would be about $1.15 million?
5
A.
Q.
range?
A.
Q.
range?
A.
Q.
And NEEA is in the I think you said $350,000
6 Yes.
7
8
11 transformation, kind of upstream things, more regional.
12 Do you feel like Rocky Mountain Power has the
13 abili ty to do a similar type of program, or is that something
14 that's done better on a more region-ride basis with many
15 multiple partners?
16 A.Southeastern Idaho from a market standpoint sort
17 of attaches itself to Northern Utah, so you get a lot of
18 similar acti vi ties taking place. NEEA does not go into Utah,
19 and I'd suggest that one good example would be to take a look
20 at the performance of the programs in Utah.
21 We, as a company, have now stepped in at the
22 mid-market level on our compact fluorescent light bulbs,
23 because that's the most effective way to increase
24 participation. That is, rather than sending light bulbs out
which we did once. That's really problematic, suggest that
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1 that's not a great idea. We did that in California. We've
2 done coupons; that doesn't work particularly well.
3 So what we're doing now is we do what we call a
4 mid-market, which is very similar to what NEEA does, which is
5 we work with the retailers and the distributors and make sure
6 that the cost of those compact fluorescent light bulbs are such
7 that customers are not price comparisoning CFLs against
8 incandescent light bulbs and just on a price-point basis going
9 wi th the incandescent light bulbs. So we are at least we
10 are moving it. We have used that program for a number of years
11 now.
12 This last summer, we pulled the CFLs -- we
13 stopped complete -- we stopped incenting CFLs for a period of
14 time in Utah and watched the market, and what we saw was the
15 purchase of CFLs dropped significantly, and as a result, we're
16 pretty comfortable that this mid-market approach we've taken
17 wi th compact fluorescent light bulbs is a very effective
18 approach at least until folks are required to buy compact
19 fluorescent light bulbs.
20 Q.Thank you. One more question about NEEA:
21 They also work in market transformation on
22 building codes and appliance standards. Is that something
23 Rocky Mountain Power is engaged in as well?
24 A.Yes, it is, and we continue to monitor and Rocky
25 Mountain legislators adopt current national and international
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1 codes. We serve a very small part of Idaho in Southeastern
2 Idaho, and our -- we are greatly influenced by what the other
3 two utili ties do.
4 Fair enough. Okay, the last issue I want to talkQ.
5 about is on page 14, at the bottom, beginning -- the question
6 begins on line 19 and kind of carries -- the balance of it is
7 on page 20. You talk about Mr. Grayson's questioning the use
8 of a tariff rider for recovery and how that might -- how that
9 causes some customer relation problems. Specifically , it says
10 on page 20: Nonparticipants might question the customer
11 efficiency surcharge.
12 Is this something you hear from your customers,
13 some push back on seeing this extra line item on their bill?
14 You know, we hear it, we hear that our customersA.
15 have provided comments to our Commissioners.
16 Q.Sure.
17 We don't typically hear a great deal about thisA.
18 you know, energy efficiency and load controlissue. It is
19 has grown substantially over the last five years, both on our
20 system and nationally. You know, customers are becoming
21 increasingly aware. We're starting to see a real jump in
22 awareness when we survey on these issues.
23 So we don't see it, but as an option and what
24 we've seen happen in Washington is that is just you know,
25 we've put it on a cents-per-kilowatt-hour basis in Washington,
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1 it's still a tariff, there's still a deferred account. The
2 accounting sort of from a utility standpoint is the same, but
3 as we apply it, we apply it to the customers' total kilowatt
4 hour usage prior to coming up with the amount we put on the
5 bill and we eliminate the line item.
6 And, you know, initially, the line item was
7 designed to try to educate customers to say, you know, you're
8 paying for energy efficiency, you might want to pick up the
9 phone or pop into the Web site and see what you're paying for
10 and take advantage of those programs. You know, we're seeing
11 customer participation is increasing annually. As it
12 increases, you know, probably the need for that prompter at the
13 bottom of the bill may have exceeded its life.
14 Q.So you said Washington, they have this
15 different
16 A.Yes.
17 Q.-- just rolled in their rates. Are you seeing
18 strong participation in Washington?
19 A.Absolutely.
20 Q.Are you hearing the same kind of customer
21 complaints to that Commission or to the Company?
22 A.No. As a matter of fact, the state of Washington
23 passed in 2007 a energy efficiency standard that requires that
24 the companies, utilities in the state, including municipal
utili ties so it's just not the investor-owned utilities --
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1 including municipal utili ties are required to acquire all
2 cost-effective energy efficiency; and it is the -- it is a
3 mandate and with that mandate there are penal ties. So, no. In
4 fact, that was an initiative, it was not a legislative action.
5 It was an ini tiati ve voted by the people of the state of
6 Washington, so I think the answer to the question is at least a
7 majority of them did not have an issue.
8 Q.Sorry, I just want to clarify. You said -- I
9 guess what I was asking is with -- because the energy
10 efficiency isn't a line item on people's bills in Washington
11 and more rolled into rates, in your opinion, do you think that
12 you're getting more customer acceptance or less customer push
13 back because it's not highlighted?
14 Yeah, I don't answer the calls at the CommissionA.
15 chambers, which is typically where those calls go. So I can
16 tell you I don't get -- I don't deal with any Commission
17 complaints in Washington, so nothing has come to the point of a
18 Commission complaint in Washington.
19 Again, the voters of the state of Washington
20 voted to have the companies acquire all cost-effective energy
21 efficiency, and, you know, we are and have been instructed to
22 run those programs as hard as we can to make sure we don't
23 leave anything on the table.
24 And the last question about -- but using theQ.
25 system in Washington, is the Company collecting sufficient
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1 money to go after all this cost-effective energy, energy
2 efficiency?
3 A.We'll be adjusting our tariff rider in probably
4 May of next year. We're permitted to adj ust it as necessary,
5 but we are required to make a filing during that time period to
6 reflect what the balances are and to discuss the issue. We'll
7 be filing to reflect the increases not only in the demand-side
8 management acti vi ties, but we're also required in the state of
9 Washington to pursue distribution energy efficiency and
10 production energy efficiency. Those are two new items for the
11 Company, and we're required to -- we're allowed to recover
12 those costs through the tariff rider also or the deferred
13 accounting process, so we will be filing for increases in May.
14 Q.This is actually the last question, honestly.
15 A.Not a problem.
16 Q.Would the same kind of situation work in Idaho?
17 Is there any reason it wouldn't?
18 A.You know, the Company does not see a problem.
19 It's clearly the discretion of the Commission.
20 Q.Thank you very much. That's all I have.
COMMISSIONER SMITH: Thank you.
Mr. Olsen.
MR. OLSEN: Yes, thank you, Madam Chair.
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1 CROSS- EXAMINAT ION
2
3 BY MR. OLSEN:
4 Q.Good afternoon -- good morning.
5 A.Good morning, Mr. Olsen.
6 Q.Ms. Hunter, how are you doing?
7 I have a number of questions here and would like
8 to start out did you file any direct testimony in this case?
9 A.No, I did not.
10 Q.Why?
11 A.You would have to ask my attorney.
12 Q.Okay. But you have filed rebuttal testimony?
13 A.Yes, I have.
14 Q.What -- what concerns did Staff raise that you
15 have sought to address here?
16 A.I addressed in my testimony Mr. Grayson's issue
17 of customer segment equity and Mr. Lobb' s issue with regard to
18 the cost of the program.
19 Q.Okay, so those were the main concerns that you
20 had addressed here now. I think here Mr. Hedman testified
21 earlier yesterday and referred to in your testimony I believe
22 in page 3, lines 2 through 6, that Mr. Grayson also testified
23 that the energy efficiency and demand-side management programs
24 were prudent or cost effective. Is that correct?
25 A.Yes, they are.
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1 Q.Now, I want to focus a little bit here on
2 Mr. Grayson's -- or, I guess is it Lynn Anderson's assertion
3 now -- Mr. Grayson's assertion that -- he said the Company
4 and I'm on page 3 of your testimony, lines 16 and 17. You
5 quote: The Company should find ways to pursue all
6 cost-effecti ve DSM while striving towards greater balance with
7 regard to customer segment equity.
8 Now, if the programs as they existed I guess at
9 the time you filed this case were determined to be prudent or
10 cost effective, why would you need to provide additional
11 testimony in this case?
12 MR. SOLANDER: Madam Chair, I'm going to obj ect:
13 That calls for a legal conclusion again.
14 COMMISSIONER SMITH: Mr. Olsen.
15 MR. OLSEN: I'm just trying to get to the point
16 of -- the issues that she was trying to address are rebuttal
17 testimony. She should be able to tell me that.
18 MR. SOLANDER: And Mr. Olsen can address the
19 points in her rebuttal testimony.
20 COMMISSIONER SMITH: So, Mr. Olsen, try again to
21 get to your point.
22 MR. OLSEN: Okay.
COMMISSIONER SMITH: Overruled.
Q.BY MR. OLSEN: Well, if prudence is not an issue,
okay, and the load control programs, energy efficiency programs
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i are cost effective, why would you want to reduce participation
2 in the programs like you've gone through in this testimony?
3 A.The programs are prudent, they are cost
4 effective, and we believe that we're progressing quite well in
5 Idaho on energy efficiency and load control.
6 The question of reducing the cost was brought up
7 by Mr. Grayson in his testimony when he talked about customer
8 segment equity. You cannot achieve customer segment equity
9 easily, and one of the -- you know, what I was trying to say in
10 my testimony is if the idea is to have all customers receive a
11 fair share or their share of the investments in demand-side
12 management and you try to balance that out and have all those
13 costs pooled into one tariff rider that they share -- so let's
14 say, for example, each of the three customer segments are
15 getting one-third of the value -- what you would find as an
16 operator of the energy efficiency programs would be to ensure
17 that everybody was getting one-third of the dollar value, that
18 you would be forced to make additional investments in segments
19 that possibly would not be as cost effective or it would
20 threaten the cost effectiveness of the program.
21 It would be the situation of it takes 30 cents to
22 insulate insul- -- to incent a customer to participate in an
23 insulation program, but because we're not investing much in
24 that segment as we are in other segments, then you would have
25 to increase the incentive to ten cents by ten cents to 40
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1 cents. That additional ten cents you increased it would
2 provide no marginal value to you.
3 So you can't do it -- you can't do it with just
4 increasing the cost in other segments. You've got to
5 achieve if you're going to try to mitigate this customer
6 segment equity that Mr. Grayson brings up, you'd have to
7 mi tigate it by dropping costs in other segments, and that is at
8 the discretion of the Commission if that's an issue they want
9 to address. That's one way you can achieve it.
10 Another way you can achieve it is the way the
11 State of Wyoming does it, you know, has approached it, in that
12 each customer segment has their own deferred account and they
13 pay for their own energy efficiency. So there is a customer
14 segment for large industrial, a customer segment for
15 commercial, and a customer segment for residential. Our
16 programs are charged in each one of those three buckets
17 depending on which -- you know, which -- what we're working on,
18 and those customers wi thin those segments pay just what's been
19 expended into their segment. It's another way of reaching
20 customer segment equity.
21 So, what I was trying to address with
22 Mr. Grayson's testimony was -- is how would you actually try to
23 do what he is asking us to do? And you could do it by
24 increasing the incentives, but increasing them without the need
25 creates marginal cost without marginal benefits, which probably
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1 is not prudent.
2 The next one would be to reduce the costs
3 associated with the programs, and that is at the discretion of
4 the Commission.
5 And the third one would be to establish some type
6 of accounting process to ensure each group received the costs
7 associated with the benefits or the incentives that were
8 provided to them.
9 Great. Thank you for that.Q.
10 Now, you focused on, you know, those three ways
11 to, I guess, achieve customer segment equity. Have you
12 proposed any new programs in your testimony for the residential
13 or commercial industrial sectors?
14 No, I don't believe so, unless you had somethingA.
15 I did not.
16 We have -- we are proposing some changes and
17 modifications in other filings to the existing programs to deal
18 wi th some code issues and standard issues.
19 Okay. But, you know, you talk about increasingQ.
20 investment is one way. That may not be cost effective, you've
21 just testified. But if you find a new cost-effective program,
22 isn't that a way to increase the investment in a cost-effective
23 manner?
24 That is a way to increase the investment on aA.
25 cost-effecti ve manner, but at this point in time our commercial
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1 industrial customers, we have prescriptive measures which means
2 that a commercial customer could go out and, you know, price
3 off of our tariff or obtain the incentive off of our tariff for
4 a lighting system or pumping systems or heating, ventilation,
5 and air conditioning systems, so it's very, very prescriptive.
6 Or you can do a custom calculation, which is having an engineer
7 come in and determine how much energy would be saved and then
8 we apply a custom value to it. That pretty much covers off
9 everything at the commercial/industrial level.
10 Residential level, we're touching all of the
11 lighting, we're touching refrigerators, we're touching washers
12 and dryers. The only thing we currently are not addressing
13 wi thin that segment are TVs, computers, and the -- sort of the
14 electronics component of those. And just as we've had
15 challenges with compact fluorescent light bulbs, these
16 particular components are causing some challenges on designing
17 a program.
18 The industry is moving fairly quickly to a higher
19 efficiency one. The question is whether or not the Company
20 should be incenting it if the market is already going there.
21 So we're watching that market, we're meeting this week and next
22 wi th individuals to try to further understand that particular
23 segment of the residential market, but at this point in time we
24 don't have anything to offer there but we are picking up pretty
25 much everything else you can do at the residential level.
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1 Q.Okay. Thank you. One of the other issues -- and
2 you discuss this in your, I guess, response to Mr. Mickelsen's
3 testimony that was filed -- that you were seeking to reduce --
4 or, increase the threshold for irrigation participation to 50
5 horsepower sites or pumps. Is that correct?
6 A.Yes.
7 Q.Okay. Now, in the Utah jurisdiction, don't you
8 have an irrigation load control program?
9 A.Yes, we do.
10 Q.And that, if I -- if I'm correct, that's under
11 the Utah Tariff Schedule No. 96?
12 A.Yes, it is.
13 Q.Okay. What's the minimum participation level in
14 that program for the moment?
15 A.I think it's very similar to Idaho. I did not
16 bring that tariff and as Mr. Walje testified yesterday we run
17 35 -- we have 35 tariffs, so I can't bring it up right at the
18 top of my head, but I do believe it's 30 horsepowers.
19 The Utah system, you know, runs fairly similar to
20 the Idaho system. It's a far more scattered system than Idaho.
21 We don't have the same system problems, because the irrigation
22 pumps tend to be on circuits where we have a lot of other types
23 of load creating a di versi ty that doesn't create the problem
24 we've had in Idaho with the operation of the program and the
25 continued operation of the transmission distribution system.
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1 Q.Would you accept, subj ect to check, that it's ten
2 horsepower currently?
3 A.That -- I would accept that.
4 Q.Okay. I'd like to go to page 8 of your rebuttal
5 testimony, starting on line 8, and here you make the statement
6 that while -- beginning there at line 8 -- while the program
7 while the program -- and you're referring to irrigation load
8 management programs -- is cost effective compared to
9 al ternati ves, shareholders do not receive compensation for
10 benefits achieved -- and you say "costs not incurred" -- only
11 the recovery of actual costs.
12 Now, what do you mean by that statement there
13 that the shareholders don't receive compensation for the
14 benefits achieved?
15 A.Both energy efficiency and load control is -- are
16 designed to reduce future acquisitions or acquisitions as we go
17 on, so what the -- you know, rather than, you know, investing
18 in another power plant or acquiring additional energy or
19 capacity over time, these are long-term views. The Company
20 Company, in lieu of that, has been working with our customers
21 to reduce consumption.
22 We provide -- you know, we -- if we incur any
23 costs, we place it in a deferred account. The customers just
24 pay for the costs we incurred because the power plant is never
25 buil t or the purchase is never made. You know, these are the
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1 benefits associated with these programs and the Company does
2 not -- you know, we don't incur those costs nor do we benefit
3 from not incurring those costs.
4 Q.Okay. I'd like to focus on the same page 8
5 there, the bottom. You go in to talk about the proposed
6 changes to irrigation load management program. And earlier,
7 right above that, you say that these changes are addressed to
8 focus on the program's cost effectiveness, and then and/or
9 address operational issues. Is that fair to say?
10 A.Yes.
11 Q.Okay. I just want to go through that there, if
12 you'd turn over to page 9. The first one is, you know, the
13 restricting the participation in addition of horsepower. Is
14 that just a cost or is that an operational?
15 A.That's an operational issue for the Company for
16 2011. We'd like to relook at that issue at the end of 2011.
17 The Company was in the process of rebidding all
18 of our load control operations both in Utah and Idaho for the
19 2011 season. Those RFPs were canceled because we weren't quite
20 sure what the program was going to look like or what the
21 resul ts of these proceedings would be. Consequently, we find
22 oursel ves in an interesting situation: The system that, you
23 know, we were not really quite sure we would be operating and
24 we're now looking at how we will operate in 2011.
25 As we take a look at 2011, those -- the 50 and
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1 under horsepower pumps are, you know -- we can generate about
2 500 control units from those sites, and that will give us the
3 control units we need to replace control units on larger pumps
4 as they fail. We do experience a significant failure rate.
5 One of the challenges with load control programs,
6 which has been true since the very beginning with irrigation
7 control programs, is these control devices are in incredibly
8 hostile areas. You know, effectively, you're putting a small
9 computer board, phone board, in a device and sticking it out in
10 a field that's going to get hit with dust, water, equipment,
11 you know, fertilizer. So they all have a little bit of a
12 hostile existence. So we do see a turnover rate or a failure
13 rate in our control units.
14 So, looking at how to optimize the operation for
15 2011 from an operational standpoint, those control units would
16 provide greater value on the larger pumps.
17 In addition, there because of the situation
18 we're currently in at this point in time and the realization
19 rate, the cost effectiveness of those pumps are questionable.
20 Q.With the second change that you talk about, you
21 want to add Idaho Power's participation selection language. Is
22 that a cost or an operational issue?
23 A.That's operational.
24 Q.Okay. Now, with respect to the third change, you
25 want to change the penalty provisions for opt-outs. Now, later
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1 in your testimony you say that there's only 2.9 percent, on
2 average, opt-out. So, why is this such a big deal?
3 A.You know, as we've taken a look at the opt-outs,
4 we're making this recommendation because, you know, as you take
5 a look at the input of the opt-outs, you want to have folks
6 there. If you're planning on having them there, you want to
7 have them there.
8 The opt-outs, if you take five opt-outs, I
9 believe I stated it was like a 25-percent reduction in your
10 incenti ve payment. Let me look at that. Yeah, just on a
11 you know, we used 130 horsepowers pump as an example. If you
12 took five out of your six opt-outs, you'd still retain 75
13 percent of the credits.
14 Excuse me. Let me reread this again.
15 Excuse me. Under the current tariff provisions,
16 if you take five out of the six opt-outs, you'd retain 96
17 percent of your credits. So you were only -- you know, you're
18 only there for one of the six, if we took six control events.
19 If you go to the new one, your penalty would go up such that
20 you'd only retain 25 percent of the opt-outs.
21 Q. Now, the next proposed reduction is the credit
22 amount. I guess you addressed this a little bit as you
23 reviewed Mr. Mickelsen's testimony. So, do you have a copy of
24 that testimony in front of you?
25 A.Yes, I do.
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1 Q.Did you get a chance to review Exhibit 304 that's
2 attached?
3 A.Yes, I did.
4 Q.Now, as Mr. Mickelsen provides in his testimony,
5 the irrigators worked with the Company and came up with a
6 three-year worked pricing -- or continue -- they continue
7 current pricing program in the tariff through 2012. Isn't that
8 correct?
9 A.Yes, that is.
10 Q.All right. Now, you're saying, I guess, for
11 operational or cost purposes, why does that need to change?
12 A.The $25 -- the change from $30 to $25 is a option
13 the Company provided the Commission to consider if they're
14 concerned about the costs of the programs and to address
15 Mr. Grayson's issue of customer equity. That is a decision
16 that, you know, is at the discretion of the Commission. The
17 Company provided the recommendation so they had that -- you
18 know, could take a look at that option.
Q.Well, if you had made an Agreement and someone
20 wants to go back on that, wouldn't you be a little concerned?
21 A.At the time, you know, at the time the Agreement
22 was made, the Company was, you know, looking and hoping to
23 exceed 185 megawatts. We've exceeded that significantly.
24 Proprium' s gone extremely large.
25 In addition, there, you know, has been questions
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1 raised regarding the amount, sort of the investment the Company
2 has made in the various segments in the state of Idaho. So the
3 option provided to the Commission is an option for them to
4 consider in light of the size of the program and the impact on
5 other customers.
6 Q.Now, later on -- and I'm still speaking about the
7 credi t amount here -- on page 13, lines 12 through 15, you
8 testify as to what you think the effect of reducing a credit
9 may be. What is that?
10 A.That's merely taking $5 times 230. It's a
11 million, 150.
12 Q.And I guess let me clarify that: Effect on
13 participation as far as irrigators goes on that credit.
14 A.On how many irrigators would drop out of the
15 program?
16 Q.Correct.
17 A.We are really not sure at this point in time. We
18 don't you know, the sense is that in the $25 range probably
19 is is the point at which participation will level off. You
20 know, we're not sure because we didn't stop at in-between
21 steps; we went to $30 rather quickly. So I can't tell you if
22 we would see a great departure from participation; I would
23 certainly hope we would not.
24 The program, in all honesty, is one that, you
25 know, we're very pleased with. But saying that, we understand
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22
1 there are ways to improve that program for all customers in the
2 state of Idaho.
3 Q.Okay. Could you turn to page 10 of your rebuttal
4 testimony and then also the additional exhibit that you handed
5 out before, and I have just some limited questions regarding
6 that.
7 Now, on your new exhibit -- I don't recall what
8 number that is.
9 COMMISSIONER SMITH: It's 85.
10 MR. OLSEN: Pardon?
11 COMMISSIONER SMITH: 85.
12 MR. OLSEN: Eighty-fi ve. Okay.
13 Q.BY MR. OLSEN: On Exhibit 85, you talk about the
14 benefits there in the fourth column. You have benefits at $55.
15 And if I understand correctly, that is the $ 7 3 benefit you
16 determine at generational level, then after it's applied a
17 realization rate or a factor.
18 Is that a fair characterization of your prior
19 testimony?
A.No.
Q.Okay. Could you clarify for me then?
A.It's the $ 7 3, increased by ten percent recognized
23 generation level, and then adjusted by 68 percent to reflect
24 the realization rate or how much we're actually seeing or
25 having available for peak reduction versus the connected.
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1 The connected also is a very interesting number
2 because it is the average of the prior two years' peak from the
3 customer's bill. So it, you know it's an interesting number
4 but the only way we had available to calculate it. So, it's
5 the sum of those sum of the customer's average peak for
6 prior two years.
7 Q.No further questions. Thank you, Ms. Hunter.
8 COMMISSIONER SMITH: Thank you, Mr. Olsen.
9 Ms. Davison.
10 MS. DAVISON: No questions, Madam Chair.
11 COMMISSIONER SMITH: Mr. Purdy.
12 MR. PURDY: Yes.
13
14 CROSS-EXAMINATION
15
16 BY MR. PURDY:
17 Q.Good morning.
18 A.Good morning.
Q.Ms. Hunter, were you here yesterday when
20 Mr. Walj e testified?
21
22
23
24
25
A.Yes, I was.
Q.Did you hear my cross-examination of Mr. Walj e?
A.Yes, I did.
Q.I'm going to characterize some of the things that
I believe he said in his testimony, and if at any time you
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1 disagree, please bring that to my attention.
2 Would you agree that he characterized the
3 Company's low-income weatherization assistance program as a
4 prudent, cost-effective resource?
5 A.I believe so.
6 Q.Do you need assistance in
7 A.No, it
8 Q.your certainty?
9 A.It depends on the state in which we're located as
10 to whether you know, I can't say point blankly all
11 low-income weatherization programs are cost effective, because
12 it varies by state policy. Idaho's low-income weatherization
13 program is cost effective.
14 Q.That's what I was asking about, thank you.
15 And I also asked Mr. Walj e some questions about
16 the decision-making process that goes into the Company's
17 proposals that it makes in any given case such as the one we
18 are participating in today. He described, if I understood
19 correctly, a sort of collaborative effort, including him as
20 well as others, and I believe he mentioned your name. Is that
21 true?
22 A.Low-income weatherization throughout the Company
23 is managed by our customer service vice president, along with
24 our low-income funding sources, so we've sort of pooled those
25 wi thin the customer service department. So, you know, I work
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1 with the manager of the low-income weatherization program which
2 is in cust- -- she is physically located within our customer
3 service organization. We work with her to, you know, evaluate
4 her programs, help her with her procurement, make sure that
5 they fit within the rest of the program suite for energy
6 efficiency. But Barb Coughlin who manages that individual is
7 here today; she can provide you with additional information.
8 We're sort of the program's technical experts wi thin the
9 Company, so we provide more technical assistance than I would
10 say policy assistance to the low-income weatherization group.
11 Q.And, I'm sorry, who's "we"?
12 A.The inter- -- demand-side management
13 organization, so myself and my staff.
14 Q.All right. Are you Ms. Coughlin's supervisor or
15 the other way around?
16 A.No, Ms. Coughlin reports to another vice
17 president wi thin Rocky Mountain Power, Karen Gilmore.
18 Q.I did not hear Mr. Walje include Ms. Coughlin in
19 his discussion of the process that takes place within the
20 Company--
21 A.He included Ms. Gil-
22 Q.Let me, if you don't mind, let me finish.
-- in making recommendations concerning
24 low-income weatherization. Is she, in fact, part of that
25 collaborati ve team?
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1 A.Yes, she is.
2 Q.All right. And could you identify who else is on
3 that team or in that group?
4 A.I would be advising from a technical standpoint,
5 along with those that work with me.
6 Karen Gilmore, who is the vice president of the
7 customer service and responsible for the low-income
8 weatherization programs, would clearly be involved; along with
9 Becky Eberle, who's program manager; and Barbara Coughlin, who
10 is the director that Becky reports to.
11 Q.One name that I wasn't familiar with, did you say
12 Karen Gilmore?
13 A.Yes. She's the vice president of customer
14 service.
15 All right. And she did not offer testimony inQ.
16 this proceeding, did she?
17 A.No, she did not.
18 Okay. So I just want to make sure I have thisQ.
19 group fully assembled here. It was Mr. Walj e, the Com~any
20 president; Ms. Coughlin; yourself; Ms. Gilmore; and
21 Ms. Eberle?
22 A.Yes.
23 Q.Did I miss anyone?
24 A.No.
25 And how does this group of individuals coalesceQ.
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1 in a way that ultimately results in a proposal made by the
2 Company to this Commission with respect to low-income
3 weatherization?
4 MR. SOLANDER: Madam Chair.
5 COMMISSIONER SMITH: Mr. Solander.
6 MR. SOLANDER: The witness has already said that
7 Ms. Coughlin can address the low-income weatherization program
8 when she's called to testify later this afternoon.
9 COMMISSIONER SMITH: Mr. Purdy.
10 MR. PURDY: Madam Chair, my concern is that, as
11 often occurs when a witness is placed at the end of the witness
12 list and I or any other attorney ask prior witnesses questions
13 of this nature, it gets punted to that last person at the end
14 of the last day of the hearing, who then for some reason cannot
15 answer, and I'm afraid that might happen here if I'm not
16 allowed to cross-examine.
17 COMMISSIONER SMITH: I'm going to overrule your
18 obj ection, Mr. Solander, and the witness can respond to the
19 extent she has personal knowledge; and when she doesn't, I'm
20 sure she will tell Mr. Purdy in a brief and succinct answer
21 that she does not know the answer.
22 THE WITNESS: Our -- my organization, demand-side
23 management, is responsible for taking a look at the actual
24 impact analysis associated with the low-income weatherization
25 program, so our recommendation or our information is more
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1 information provided to our customer service and low-income
2 staff would be regarding the performance of the program: Are
3 we getting the value that was anticipated? Is the program
4 being delivered as anticipated? An example is in another
5 program that we look at frequently is when a customer installs
6 insulation, do we receive the value from that insulation that
7 we anticipated.
8 So we do the technical evaluation of the program
9 from both a impact standpoint, as well as a process standpoint:
10 Do the customers receive the information they need to make a
11 decision? Or is the customer satisfied with how the process
12 operates? Did we follow all of the Rules and Regulations
13 associated with the process that is laid out in the tariff?
14 We'll provide that tariff to our friends over in
15 customer service for evaluation as they pull together
16 recommendations on going forward.
17 We also serve as the Company's interface with a
18 lot of State agencies that are involved in energy efficiency,
19 and to the degree we garner information from those State
20 agencies, that information will be provided over into
21 Karen Gilmore's operations in customer service so that they can
22 utilize that information to make decisions. So, for instance,
23 during the recent American Recovery and Reinvestment Act
24 funding process for weatherization, we were, in part, tracking
25 information on how those funds were distributed to the states,
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1 what impact they may have.
2 Q. BY MR. PURDY:Thank you. Again, I want to be
3 careful when we use pronouns. I just used one: We. You used
4 the word "we" quite often now.
5 A.I apologize.
6 Q.Are you referring to this collaborative group of
7 individuals I listed earlier?
8 A.When I talk about the impact evaluation, it is
9 the demand-side management organization that I manage working
10 wi th a third-party independent to do the evaluation. We -- you
11 know, we provide for the contracting; we make sure that the
12 contractor -- in this case, Cadmus -- is pursuing a very
13 thorough review of the program; you know, make sure that any
14 data that might be needed by the third-party evaluator is
15 provided to that third-party evaluator on a timely basis; make
16 sure any questions that arise out of that process are addressed
1 7 by the Company.
18 Q.Ms. Hunter, perhaps I wasn't clear enough. I
19 really want to get down to the nut of this. Who makes the
20 decisions, the final decisions that are presented to this
21 Commission in proceedings such as this, regarding the Company's
22 low-income weatherization program? Who are the individuals
23 invol ved and who is -- where does the buck stop?
24
25
A.Where does the buck stop?
Q.Yeah.
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1 A. I refer you to Barb Coughlin. She would be,
2 again,on the stand later today. You know, we would be
3 providing, like I said, technical assistance to their
4 organization and process assistance.
5 Q.So Ms. Coughlin is the individual with the
6 ultimate power to make the final decision regarding the
7 Company's low-income weatherization proposal in this case?
8 A.She will be making that decision -- and possibly
9 a better way to say it would be a "recommendation" -- to her
10 vice president.
11 You know, I'm not involved in that process other
12 than to provide data and assistance to the low-income
13 weatherization group. So, you know, there are times that, you
14 know, we may recommend different steps and work with them on
15 how to evaluate it, but that is -- that decision and those
16 decisions are handled inside of our customer service
17 organization.
18 Q.Is that a "yes" or a "no"?
19 A.That is a I believe Ms. Coughlin would be the
20 person to answer your question on how her organization
21 addresses the issue.
22
23
24
25
Q."Her organization" is
A.Wi thin customer service.
Q.And that's the body that makes the ultimate
recommendation regarding low-income weatherization?
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1 MR. SOLANDER: Madam Chair, he can ask
2 Ms. Coughlin the same question and actually get an answer and
3 not speculation from somebody about it.
4 COMMISSIONER SMITH: Mr. Purdy, it's clearly not
5 her: Ms. Hunter.
6 MR. PURDY: Pardon?
7 COMMISSIONER SMITH: It's clearly not Ms. Hunter.
8 MR. PURDY: I'm sorry, Madam Chair, I'm not
9 hearing you.
10 COMMISSIONER SMITH: I said it's clearly not this
11 witness.
12 MR. PURDY: All right.
13 Q.BY MR. PURDY: You mentioned a third-party
14 contractor. Could you identify that entity?
15 A. Yeah, the third-party contractor for this round
16 of evaluations is the Cadmus -- is Cadmus, and it's an
17 organization that is used by utili ties and by state agencies to
18 evaluate their programs.
19 Q.Could you spell that out?
A.C-A-D-M-U-S. Mr. Hedman testified yesterday.
21 He's from our -- he's a representative of Cadmus.
22
23
Q.Okay.
A.They -- they are -- they have -- we have entered
24 into a contract with them to evaluate 20 of our programs across
25 the states of Washington, Idaho, and Utah, and those
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1 evaluations will be available hopefully by the end of this
2 year, first of next year.
3 Q.And is this the entity, Cadmon (sic), that did
4 the evaluation Ms. Coughlin testifies about in her testimony?
5 A.I would believe so, because they are -- the
6 low-income weatherization program is one of the programs that
7 is being evaluated.
8 Q.All right.
9 A.And it is our intent to provide those -- the
10 resul ts of that evaluation to the parties, including the
11 Commission, in our 2010 annual reports. The results will be
12 incorporated in those. And we'd be happy to share the results
13 of that if there are a group of stakeholders who want to look
14 at those results prior to the filing of those annual reports.
15 What entity or department within the Company isQ.
16 in charge of monitoring that evaluation?
17 A.I am.
18 You are. All right. When will the results thatQ.
19 you speak of be available for the Commission to review?
A.The low-income weatherization results I believe
21 will be available the end of February, first of March, provided
22 that we have access to the data that we require from third
23 parties.
24
25
Q.And was this -- what precipitated this
evaluation?
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1 A.It's my understanding that -- you'll have to
2 address that with Ms. Coughlin. We received the request to do
3 the evaluation and make arrangements for the evaluation. We
4 have done that.
5 Q.All right. I will defer any further questions to
6 Ms. Coughlin. Thank you.
7 COMMISSIONER SMITH: Thank you, Mr. Purdy.
8 Mr. Woodbury, do you have cross?
9 MR. WOODBURY:(Indicating. )
10 COMMISSIONER SMITH: This would be a good time
11 then for us to have about a 12-minute break. We'll come' back
12 at ten minutes after 10: 00.
13 (Recess. )
14 COMMISSIONER SMITH: All right, we'll be back on
15 the record. I believe, Mr. Woodbury, we're ready for your
16 questions.
17 MR. WOODBURY: Thank you, Madam Chair.
18
19 CROSS-EXAMINATION
21 BY MR. WOODBURY:
22
23
24
25
Q.Good morning, Ms. Hunter.
A.Good morning.
Q.Did I understand that last exchange that the --
when the Cadmus report is submitted by the year end -- I guess
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1 he indicated he hadn't finished it yet -- that you review that
2 and then kick that up to Coughlin?
3 A.On the low-income weatherization program, that
4 particular impact evaluation started later than the major
5 programs we're evaluating, so that one will be done in
6 February. The rest of the evaluations, with the exception of
7 the irrigation program, will be done at the end of the year.
8 We had a bit of a staging issue, brought those on later, but
9 low-income weatherization should be available for review by the
10 end of February. The remainder of the programs will be
11 available by the end of this year, with the exception of the
12 agricul tural programs.
13 Q.Okay. Looking at your rebuttal testimony, do I
14 take the changes in programs and the irrigation load control
15 program as being proposed as a response to Staff's concerns
16 regarding the customer segment equity?
17 A.They were proposed as a way to, you know, improve
18 the -- improve the performance of the program and/or reduce the
19 cost, you know. Those -- the ones mentioned on, you know, the
20 opt-out provisions and our issue associated with the
21 operational issue on the T and D systems were designed to
22 increase the value of the program -- you know, increase the
23 overall value of the program. So, yes, they were there to
24 address this issue, at least that I took; maybe I read
25 Mr. Grayson's testimony --
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1 Q.I mean, they weren't filed in rebuttal to
2 anything else?
3 A.Mr. Grayson's testimony.
4 Q.All right.
5 A.And Mr. Lobb' s .
6 Q.And Mr. Grayson had expressed some concern, I
7 guess, with the disparity in the program dollars, that 81
8 percent I think that you indicate on page 3 go to irrigation
9 load control program. Is that correct?
10 A.Correct.
11 Q.Do you know the total dollar amount of DSM
12 expenditures in the test year for this case?
13 A.The test year -- we sort of monitor our
14 expendi tures on an annual basis. I can give you the
15 expenditures for Idaho for 2009; we have not closed the books
16 yet on 2010.
17 On 2000 in 2009, the total energy efficiency
18 expenditures were 2.6 million, the load control expenditures
19 absent the incentives were 3.8 million, and I believe in 2009
20 that the incentives were approximately eight million.
21 Q.Okay. And then 81 percent of that is the
22 irrigation load component?
23
24
25
A.Yes.
Q.On page 8, you state that Mr. Lobb' s concerns --
you address Mr. Lobb' s concerns that the Idaho customers may
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1 not be receiving the full benefits of the program while paying
2 for the full cost of irrigation load control program, and then
3 you state that the Company is put in a difficult position with
4 respect to his proposal.
5 Do you agree with Mr. Lobb's analysis?
6 A.I would ask that you talk to Mr. McDougal
7 Q.Yeah.
8 A.-- on that issue.
9 Q.Not as to the -- oh, even with respect to the
10 inequity?
11 A.No, customer segment inequity I'm happy to talk
12 to.
13 Q.Pardon?
14 A.I'm happy to speak to the customer equity.
15 Q.In your testimony on page 9, you propose to
16 modify the irrigation load control program by increasing the
17 pump size required for participation, giving the Company sole
18 discretion over participation, reducing the amount of credit
19 paid.
20 When was the last time this program was modified?
21 A. Trying to remember the bottom, right-hand corner
22 of the tariff. If you just give me a moment, I can take a look
23 at it and --
24
25
Subj ect to check, I think it was in '08. I
really have to --
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1 Q.And do you know whether that was pursuant to
2 Application by the Company?
3 A.Yes, I believe it was.
4 Q.And have the changes that you proposed today have
5 been have they been previously or ever proposed to the
6 Company by the Company to the Commission?
7 A.We were -- we had asked our regulatory department
8 if we could file changes to Schedule Tariff 72A during the
9 control season because we were looking towards making some
10 changes, and we were asked to hold those changes until after
11 the control season; and by then, we had an Order on the
12 deferred account, asking us to review the program. So, you
13 know, no, we have not filed them, but it was our intent to file
14 some of these changes at that point in time.
15 Q.Okay. Because listening to some of the cross
16 from Mr. Olsen, and looking at Mr. Mickelsen's surrebuttal,
17 they seem to be taken -- have been taken by surprise by the
18 program changes that are being proposed. Is that fair?
19 A.We have had discussions with the Irrigation
20 Association.
21 Q.And is it your understanding that -- well, would
22 you agree that not all program participants are members of the
23 Idaho Irrigation Pumpers Association?
24
25
A.I would not have an opinion on that.
Q.Do you know the makeup of the Idaho Irrigation
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1 Pumpers Association?
2 I am informed that they have quite a few members.A.
3 I don't know the full extent of the membership. We don't -- we
4 do not, on an operational basis, work exclusively with the
5 Pumpers Association. We also work directly with the individual
6 customers, but we have not had this conversation with them.
7 Would you accept that perhaps this associationQ.
8 does not represent all the participants in the program?
9 A.Subj ect to check, yes.
10 And this proposal was made just 14 days prior toQ.
11 this -- prior to this hearing. Did you provide individual
12 Notice to all of the program participants of the proposed
13 changes?
14 A.No, we have not.
15 Would you support a Staff proposal for theseQ.
16 program changes being addressed in a separate proceeding?
17 A.Yes.
18 You proposed to discontinue the cost-effectiveQ.
19 agricul tural energy savers program as part of
20 Suggested that if, at the Commission'sA.
21 discretion, they want to reduce the investment in energy
22 efficiency in the state of Idaho, that would be an option.
23 Is the Company intending to make an ApplicationQ.
24 with that recommendation?
25 At this point in time, you know, the Company is,A.
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1 you know, assessing all of our programs in light of the
2 Commission's Decision regarding our tariff rider Application,
3 trying to ascertain whether we had received a signal through
4 that Order to reduce our expenditures; but at this point in
5 time, we've provided this recommendation. This is all the
6 farther we've gone.
7 Q.But your recommendations, you would agree, were
8 not part of the Company's initial Application in this case?
9 A.I would agree.
10 Q.And they were, therefore, not part of Notice to
11 the public that this Commission issued?
12 A.You would have to ask my attorney.
13 Q.Pardon?
14 A.I don't know the answer to that question. I
15 don't have the --
16 Q.Well, they weren't part of the Company's
17 Application, so we didn't Notice it. You would accept that.
18 Do you think that customers and interested
19 parties should have a reasonable opportunity to comment on the
20 proposed changes?
A.That, again, was I operate a program. I would
22 assume that would be so, but I do not generally partake of this
23 proceeding.
24
25
Q.But you would agree that they have not had a
sufficient or adequate opportunity in this case?
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1 A.To the degree they were not, you know -- to the
2 degree they were not involved in the Idaho Irrigation
3 Association, I would assume that would be correct.
4 Q. You recommend that with respect to your
5 Mr. Lobb' s proposal as far as treatment of costs, that 2011 be
6 treated as a transitional year?
7 A.Yes.
8 Q.But if the -- if the current allocation is
9 determined to be not fair or reasonable to Idaho customers,
10 where is the fairness in the Company's recommendation that, I
11 guess, we suck it up and continue to absorb the loss?
12 A.The Company, as you know, does not receive any
13 value from the demand-side management programs. Every
14 dollar -- so the way I -- the way we see it or I see it from an
15 operational level is we pay customers in Idaho approximately
16 $8 million to participate in the program. The Idaho customers
17 pay -- reimburse us for that $8 million through net power
18 costs. We have about three and a half to $4 million net
19 operating costs that are collected through the deferred
20 account, and at the same time we have eight million, if I
21 understand it correctly, coming into the state through the
22 allocation process. So I don't understand -- you know,
23 understand the issue and wouldn't be a good witness to answer
24 it. You need to talk to Mr. McDougal. You know, my view of
25 it's possibly different than it would be from a regulated
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1 standpoint.
2 Q.There's an inconsistency in your recommendations
3 as far as 2011 being treated as a transitional year and
4 thinking that the change would occur in 2012, because on your
5 ipage 9 recommendations, you state that you would then treat the
6 program as a system resource in 2012 subject to other states
7 agreeing to the allocation Agreement.
8 So, you're only proposing you're only agreeing
9 to this transition year, assuming that you get support from
10 other states and the standing committee as far as a change?
11 A.I would ask again that you talk to Mr. McDougal.
12 I'm not familiar with how the MSP process works, but I
13 understand that I do --
14 Q.This was your testimony?
15 A.Yeah. I understand I need revenue to cover the
16 cost of operations. I would hope that that would be resolved
17 through the MSP process in 2011.
18 Q.Yes.
A.So at this point in time, all I can speak to is
20 2011, provided that this Commission decides they want to look
21 at this as a MSP Application.
22 Q.Okay. But, your testimony says: Subj ect to
23 other states agreeing.
24 That's your language, I'm assuming?
25 A.Yes.
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1 Q.And it's -- what did you intend by that?
2 A.I would assume that if all the other states did
3 not agree to having this be included, then Idaho would be faced
4 wi th a decision or the Company would be faced with a decision
5 at that with respect to what would take place in 2012. I'm not
6 presupposing what that answer would be.
7 Q.Okay. In your proposed recommendations regarding
8 both NEEA and agricultural energy savers program, you indicate
9 the Company has no intention to make an Application on itself;
10 you're just throwing that out there for the Commission to
11 consider in making adjustments?
12 A.On the NEEA -- on NEEA, we were at a point
13 earlier this year where we were being asked by NEEA to sign a
14 mul tiyear Agreement for funding. The Company did not sign that
15 Agreement for Southeastern Idaho pending the results of these
16 hearings. So we are currently not participating in the NEEA
i 7 program for Southeastern Idaho, but we are, you know, providing
18 the recommendation on the energy agricultural energy savings
19 program to the Commission.
20 Q.Do you have separate Agreements for each state,
21 because I think you indicated Utah doesn't participate?
22 A.Yes. NEEA -- we participate in NEEA on behalf of
23 the states of Washington and Idaho typically. We've continued
24 our participation in NEEA in Washington. We have not, pending
25 the results of this proceeding, recontracted with NEEA.
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1 Q.And the -- I guess the existing participation fee
2 of 300,000, is that an Idaho-only number?
3 A.Yes, that is.
4 Q.Addressing the -- well, you state that to ensure
5 customers in one class are not paying for energy savings or
6 load control in another class, you could move to a separate
7 balancing account such as you have in Wyoming?
8 A.Yes.
9 Q.If this is a more equitable --
10 How long have you had that program in Wyoming?
11 A.We started the program in 2009 in Wyoming, so
12 we've just had, you know, about a year and a half's worth of
13 operation in that state.
14 Q.And have you found it to be a good program?
15 A.Wyoming has been a really rough market for us to
16 enter, so, you know, overall, we're -- we got a slower start
17 than we've anticipated, but the program is building.
18 Q.If it's determined to be a good way to avoid
19 interclass subsidies, I guess, a more equitable way, why are we
20 seeing it just here in your rebuttal testimony? Why hasn't the
21 Company been more proactive and recommend this change sooner
22 than later?
23 A.I, you know -- that decision to treat it in that
24 fashion is a decision that was made by the parties in the
25 Wyoming case and the Commission in Wyoming. I don't derive
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1 judgment as to whether or not it is a preferred approach or not
2 a preferred approach; it is an approach. And I believe that,
3 you know, we have different approaches for energy efficiency in
4 each of the six states we serve.
5 Q. You stated that you're not an expert on the MSP
6 process. Have you ever participated in the standing committee
7 or work group discussions?
8 A.No.
9 Q.Okay. Then your familiarity with how it operates
10 is through discussions with Mr. McDougal?
11 A.Mr. McDougal, Mr. Larsen.
12 Q.Okay. Thank you, Ms. Hunter.
13 MR. WOODBURY: Madam Chairman, I have no further
14 questions.
15 COMMISSIONER SMITH: Thank you, Mr. Woodbury.
16 Mr. Budge.
17 MR. BUDGE: No questions.
18 COMMISSIONER SMITH: Thank you.
19 Questions from the Commission?
COMMISSIONER REDFORD: None from me.
COMMISSIONER SMITH: Oh, good. Then it's time
22 for me.
23
24
25
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (X)
RMP
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1 EXAMINATION
2
3 BY COMMISSIONER SMITH:
4 Q.Ms. Hunter, you testified about the system
5 constraints that cause a problem with the irrigation load
6 control problem. My question is are these pretty localized
7 distribution issues or will any of them be alleviated by any of
8 the Gateway proj ects?
11
A.
Q.
A.
the issues
Q.
A.
Q.
A.
Q.
No, I'm not.
It's what we call lump-side problems. Some of
12
13 So Gateway won't help it?
14 No.
15 All right. You're not a lawyer, are you?
16
18 Commission's Notice about rate changes or program changes or
19 every component of any existing and proposed rate and charge
20 for all rates and charges is adequate Notice for whatever we
21 want to do. Right?
22 A. I am not.
23 Q.Okay. Finally, I just want to note -- one more
24 question:
25 On page 9, you went over your different changes
659
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (Com)
RMP
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1 that could be made to the irrigation load control program, and
2 your second one is the Idaho Power tariff language. Is that
3 correct?
4 A.Yes.
5 Q.If you had that language, why would you need to
6 do any of the others?
7 A.The first one has to do with cost effectiveness,
8 you know, increasing that from 30 to 50 horsepower.
9 Q.But what I'm asking is if you had the discretion
10 of the language that's in Idaho Power's tariff, why would you
11 need the others?
12 A.It appears we would not.
13 Q.Thank you. And, finally, I just want to say it
14 distresses me to no end to hear you say the Company gets no
15 value from demand-side measures. And this is not a question.
16 I'm just saying I can accept that this isn't a profit center; I
17 see that, I understand that. But to the extent that the
18 Company avoids or postpones acquisition of new resources, to my
19 mind, the Company 'is benefiting every bit as much as the
20 customer, and that's the basis of which I have always supported
21 these programs.
22 COMMISSIONER SMITH: So, with that, we're ready
23 for redirect.
24 MR. SOLANDER: Thank you, Madam Chair. You
25 actually stole my first redirect question. I was going to
660
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (Com)
RMP
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1 address your last point there.
2
3 REDIRECT EXAMINATION
4
5 BY MR. SOLANDER:
6 Q.But I'LL skip that and just ask, Ms. Hunter, did
7 the Company recently request an increase to the DSM rider?
8 A.Yes, we did.
9 Q.What was the Commission determination with regard
10 to that Request?
11 A.The Commission did not grant the Company the full
12 Request and deferred a number of issues to this hearing.
13 Q.And were the measures discussed in your rebuttal
14 testimony a result of the Commission determination on funding
15 of the DSM program?
16 A.Yes. After we received the Order from the
17 Commission, we took a look at the operation of the programs to
18 determine if we could improve the effectiveness and take
19 measures to -- what would be appropriate recommendations to
20 make to reduce expenditures if so asked to do so.
21
22
23
MR. SOLANDER: That concludes my examination
COMMISSIONER SMITH: Okay.
Q.BY MR. SOLANDER: And, Ms. Hunter, going back to
24 the point made by Madam Chairman, could you just clarify for
25 the record the benefits that the Company does receive from DSM
661
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (Di)
RMP
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1 programs?
2 A.The Company does receive the benefit of not being
3 required to invest in additional assets as we go forward. You
4 know, with respect to the load control program, the Company
5 does benefit from additional operational flexibility.
6 MR. SOLANDER: That concludes our examination of
7 Ms. Hunter.
8 COMMISSIONER SMITH: Thank you, Ms. Hunter.
9 THE WITNESS: Thank you.
10 (The witness left the stand.)
11 MR. SOLANDER: Cindy Crane would be the Company's
12 next witness.
13 COMMISSIONER SMITH: Mr. Woodbury.
14 MR. WOODBURY: Yes, I have a question for -- oh,
15 go ahead. I have a question for clarification regarding the
16 testimony of Ms. Crane, because our entire testimony filed --
17 filing -- is marked "confidential." Is that true? Was that
18 intended?
19 COMMISSIONER SMITH: Let's go off the record
20 momentarily to sort this out.
21 (Discussion off the record.)
22 COMMISSIONER SMITH: Yes, let's go back on the
23 record. The Company has called their witness Crane.
24
25
662
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
HUNTER (Di)
RMP
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1 CINDY CRANE,
2 produced as a witness at the instance of Rocky Mountain Power,
3 being first duly sworn, was examined and testified as follows:
4
5 MR. SOLANDER: Madam Chair, before I continue
6 with Ms. Crane, could I just also ask that Ms. Hunter be
7 excused from the proceeding?
8 COMMISSIONER SMITH: Is there any obj ection to
9 excusing Ms. Hunter?
10 Seeing none, she is excused.
11 MR. SOLANDER: Thank you.
12 COMMISSIONER SMITH: And just before you begin, I
13 would note that off the record we had a discussion of the
14 treatment of some confidential numbers that appear in witness
15 Crane's testimony, and so we will proceed with
16 cross-examination and hope not to have to close the hearing,
17 but if necessary, we will.
18 MR. SOLANDER: Thank you.
19
20 DIRECT EXAMINATION
21 BY MR. SOLANDER:
22 Q.Ms. Crane, could you please state your name and
23 spell your last name for the record?
24
25
A.Yes. Cindy Crane: C-I-N-D-Y, C-R-A-N-E.
Q.And by whom are you employed and in what
663
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
CRANE (Di)
RMP
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1 capacity?
2 A.I am employed by Interwest Mining Company, which
3 is a wholly-owned subsidiary of PacifiCorp. I'm the vice
4 president, with responsibility for the coal mining operations,
5 and the Company's coal fuel procurement and management.
6 Q.And are you the same Cindy Crane who filed direct
7 testimony on May 28, 2010?
8 A.Yes, I am.
9 Q.And did you also file rebuttal testimony on
10 November 16, 2010, and prepare Exhibit No. 64?
11 A.Yes, I did.
12 Q.Do you have any corrections or changes to your
13 testimony or your exhibit?
14 A.No, I do not.
15 Q.If I were to ask you the questions set forth in
16 your prefiled direct and rebuttal testimony, would your answers
17 be the same today?
18 A.Yes, they would.
19 MR. SOLANDER: I would move that the prefiled
20 direct and rebuttal testimony of Ms. Crane be spread upon the
21 record as if read, and Exhibit 64 be marked for identification.
22 COMMISSIONER SMITH: Without obj ection, it -- the
23 prefiled testimony of Cindy Crane will be spread upon the
24 record as if read with the confidential numbers there not
25 appearing in the public portion of the transcript.
664
HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
CRANE (Di)
RMP
.1 (The following prefiled direct and
2 rebuttal testimony of Ms.Crane is spread upon the record.)
3
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665
HEDRICK COURT REPORTING CRANE (Di)
P. O.BOX 578,BOISE,ID 83701 RMP
.1 Q.Please state your name, business address and present position with PacifCorp
2 ("Company").
3 A.My name is Cindy A. Crane. My business address is 1407 West Nort Temple, Suite
4 310, Salt Lake City, Utah 84116. My position is Vice President, Interwest Mining
5 Company and Fuel Resources for PacifiCorp Energy.
6 Qualifications
7 Q.
8 A.
9
10
11.12
13
14
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16
17
18
Briefly describe your business experience.
I joined PacifiCorp in 1990 and have held positions of increasing responsibilty,
including Director of Business Systems Integration, Managing Director of Business
Planning and Strategic Analysis and Vice President of Strategy and Division
Services. My responsibilties have included the management and development of
PacifiCorp's ten-year business plan, assessing individual business strategies for
PacifiCorp Energy, managing the constrction of the Company's Wyomig wind
plants and assessing the feasibility of a nuclear power plant. In March 2009, I was
appointed to my present position as Vice President of Interwest Mining Company and
Fuel Resources. In my position, I am responsible for the operations of Energy West
Minig Company and Bridger Coal Company ("BCC") as well as overall coal supply
acquisition and fuel management for PacifiCorp's coal plants.
19 Purpose and Summay
20 Q.What is the purpose of your testimony?
21 A.I explain the Company's overall approach to providing the coal supply for the
22 Company's coal plants.
.
666 Crane, Di - 1
Rocky Mountain PowerREDACTED
.1 Q.Please summarize your testimony.
2 A.My testimony:
3 . 'Explains 'the coal cost increases reflected in the filg and describes the primar
4 reasons for the increases;
5 . Provides background on the third-pary coal contract revisions that are drving
6 increases in coal costs in this case;
7 . Reviews the increase in the Company's affiliate mine coal costs and compares
8 them to other supply alternatives; and
9 . Demonstrates that customers benefit from the Company's diversified coal supply
10 strategy.
11 Overview of the Coal Supplies for the Company's Coal Plants
How does the Company plan to meet fuel supplies for its coal plants in 2010?
The Company employs a diversified coal supply strategy. For 2010, the Company
wil meet approximately 71 percent of its fuel requirements from third pary, multi-
year contrcts and the remaining 29 percent wil be supplied with coal from the
Company's affiiate mines.
What percentage of the Company's third party purchase coal contracts are fixed
and what percentage are indexed?
The percentage split is roughly 50/50. For 2010, approximately 37 percent of the
Company's third pary purchase coal supply wil be priced under fixed-price contracts
and 34 percent wil be priced under contracts that escalate/de-escalate based on
changes to producer and consumer price indices.
667 Crane, Di - 2
Rocky Mountai PowerREDACTED
.
5
6
7
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11.12
13
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22.23
1 Q.Please identify the afriliate mines which supply Company coal plants.
2 A.Coal production from the Company's Bridger mine is dedicated to the Jim Bridger
3 plant. Energy West's Deer Creek mine supplies a portion of the coal requirements for
4 the Carbon, Hunter and Huntington plants and the Trapper mine is dedicated to the
Craig plant.
Coal Cost Increases in 2010
Q. Do coal costs in the 2010 GRC reflect an increase from 2008?
A. Yes. On a system wide basis, the price related increase is approximately $104
milion. The Company's coal costs have increased from an average of $23.84 per ton
in 2008 to an average cost of $27.95 per ton in 2010, an increase of $4.11 per ton
overthe two-year period. This reflects increases in purchased coal under both fixed
and escalating contracts and increases in costs at the affiliate mines. These coal costs
are an input in the Company's GRID model used to produce normalized net power
costs as described in Dr. Hui Shu's testimony.
Q. What are the primary factors causing this increa in coal costs?
A. Overall, there are five prima factors contrbuting to the cost increase:
. Execution of a new coal supply and rail agreements for coal deliveries
from the Black Butte Mine for the Bridger Plant;
. Higher operating costs at BCC;
. A price increase pursuant to a contract price reopener provision with
Chevron Mining for the supply of coal from the Kemmerer Mine to the
Naughton Plant;
. Fixed contrct price escalation under the coal supply agreements with
668 Crane, Di - 3
Rocky Mountain PowerREDACTED
.1
2
3
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5
6
7 Q.
8 A.
9
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.12
13 Q.
14 A.
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For many years, BCC was able to extract coal at the surace mine through its dragline
operations and low-cost highwall mining. Now, the surace operation is the swing
coal supply for the Bridger Plant. The majority of the Bridger Plant requirments ar .
supplied by BCC underground operation. With the underground mine operating at
full production capacity, the surace operation provides the operational flexibility and
capacity necessar to assure a reliable and continuous fuel source for the Plant.
Are the BCC surface and underground separate operations?
No. Both operations share common assets such as conveyors, scrapers, dozers, light
duty vehicles, maintenance shops, administrative buildings, etc. Mine administration
personnel including purchasing, planning, engineering, environmental services,
information technology, safety, human resources, admnistration services,
government relations and surveying support both operations.
Please explain blending of surface and underground coals at the Bridger mine?
The surace operation provides the operational flexibilty and reliabilty for the
Bridger Plant. All coal, surface and underground, has an assigned coal quality. Mine
plans are developed on a monthly basis to ensure that the delivered coal product to
the Bridger Plant meets specific coal quality criteria. On a daily basis, surace
operation and deliveries are adjusted to meet specification. Blending is critical since
the underground operations are limited to a single coal seam. Without the surace
operation, BCC could not deliver a product that could meet the Jim Bridger Plant's
quality targets.
670
REDACTED
Crane, Di - 5
Rocky Mountan Power
.1 Q.
2
3 A.
4
5
6
7
8
9
10 Q.
11 A..12
13
14
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16
17
.
Please provide an overview of costincreases at the Bridger Mine reflected in this
filing.
Bridger Mine costs are increasing from _ per ton in 2008 to _ per ton in
2010 or, an overall increase of. millon. The overall increase in 2010 costs
reflects higher production taxes as well as increases in royalties, depreciation and
amortization expense. Additionally, in 2008, almost half of the surface coal was
produced utilizing low-cost highwall mining. Highwall mining has ceased at the
mine because those areas of the surace pits suitable for highwall mining have now
been depleted.
Please compare Bridger mine costs relative to other supply options.
Bridger mine costs remain considerably less than any available market alternative.
Though Kiewit Mining has _ tons of uncommtted Black Butte production
capacity though 2014, this amount is insuffcient to replace the coal supply from the
Bridger mine. In any event, the delivered cost of this uncommtted tonnage to the Jim
Bridger Plant is approximately. per ton in 2010, almost. per ton higher than
BCC costs in the test period. The projected delivered cost of Powder River Basin
("PRB") coal in 2010 is over. per ton,. per ton higher than BCC costs in the test
18 period without even considering the costs of capital modifications required for the
19 Bridger Plant to burn PRB coals.
20 Naughton Plant Coal Price Increase
21 Q.
22 A.
23
Please describe the price reopener related to the Naughton contract
The Company's long-term coal supply agreement with Chevron Mining's Kemmerer
mine extends though 2016 and contains several price re-openers. The next price re-
671
REDACTED
Crane, Di - 6
Rocky Mountain Power
.1
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3
4
5 Q.
6 A.
7
8
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11.12
13
14
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16 Q.
17 A.
18
19
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21
22
23.
opener was scheduled to occur on Januar 1,2011. However, due to_
, Chevron Mining requested that the Company advance the price re-
opener date to Januar 1,2010. The Company agreed to advance the re-opener date
provided there is an overall cost reduction over the remaining term.
Has the Company evaluate supply alternatives for the Naughton Plant?
Yes. The Company has evaluated alternative supplies.
Including transportation costs, the
Company estimates the average cost to replace the coal supplied by the Kemmerer
Mine would be in excess of. per ton.
Please explain what price is reflected in the 2010 GRC for the Naughton Plant.
After months of negotiations, the paries have conceptually agreed to a new contract
price of_ per ton, with an effective date of Januar 1,2010. While this price
represents an increase of. per ton over the 2008 test period costs or. millon
on a system-wide basis, the new contract price would provide significant savings for
Company ratepayers through the remainder of the curent term relative to the
Company's other supply options. Additionally, the agreement would allow the
Company to extend the coal supply with Chevron Minig for the Naughton Plant
672
REDACTED
Crane, Di-7
Rocky Mountain Power
.1 though 2021.
2 Coal Costs Related to the Utah Plants
3 Q.How do coal costs for the Utah plants compare to 2008?
4 A.Coal prices for the Uta plants are projected to increase by approximately _ milion
5 due to increases in costs under the Company's coal supply agreements with Arch
6 CoalS ales as well as increased Deer Creek mine production costs.
7 Q.Please describe the increase under the long-term agreement with Arch.
8 A.The Company has thee multi-year coal supply agreements with Arch CoalSales
9 Company. In 1998, the Company entered into a long-term coal supply agreement
10 with Arch for up to 4.5 millon tons of primarly Sufco mine coal through 2020. This
11 contract supplies the majority of the fueling requirements for the Utah coal plants. A.12 2007 price reopener established fixed annual price increases for 2008,2009 and 2010.
13 The price of coal has increased by .. per ton between 2008 and 2010 or_
14 milion. Additionally, the Company entered into thee-year supply agreements with
15 Arch for Dugout and Skyline coals as part of the Electric Lake settlement. These
16 agreements provide for a fixed price increase of _ per ton between 2008 and
17 2010 or_millon.
18 Q.What is the overall cost increase under the coal supply agreements with Arch
19 CoalSales Company?
20 A.Approximately _ millon of the overall price increase for the Utah plants is tied to
21 fixed price increases under the Arch agreements.
22 Q.Please explain the increases in Deer Creek Mine costs between 2008 and 2010..23 A.The Deer Creek Mine is located in Utah. Deer Creek Mine costs are projected to
673 Crane, Di - 8
REDACTED Rocky Mountain Power
.1
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5 Q.
6 A.
7
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11.12
13
14 Q.
15 A.
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.
increase to _ per ton from the 2008 price of _ per ton, an increase of
approximately. millon. While labor costs and major overhaul expense have
increased since 2010, a reduction in longwall production durng the last half of 2010
is the principal drver of the cost increase.
PI~ase explain why longwall production is reduced in 2010?
The curent longwall system was purchased and placed in service in August 1998
with an expected ten-year life. The longwall system is being reconstrcted during the
last half of 2010 while the mine transitions from the upper Blind Canyon seam to the
lower Hiawatha seam. Based on a risk assessment of the existig longwall equipment
by Joy Mining, the longwall system rebuild is necessar to facilitate the recovery of
the remaning longwall reserves in the Deer Creek mine. To maximize mine
production, the rebuild is scheduled to coincide with the lengthy move to the lower
coal seam.
How do Deer Creek Mine costs compare to Utah market alternatives?
Even with the cost increase in 2010, the Deer Creek mine is considerably less
expensive than any market alternative and remains the least-cost supply for the Utah
plants. Deer Creek Mine costs are considerably less than our market alternatives.
According to Argus Coal Daily, spot prices for Utah coal have ranged from. per
ton to. per ton during 2010. Similarly, Platts' Coal Outlook reflects Utah spot
coal prices hovering near. per ton. Based on discussions with other coal
producers, Deer Creek-equivalent quality coal is being transacted for approximately
$50 per ton for a multi-year arrangement.
674 Crane, Di - 9
Rocky Mountain PowerREDACTED
.1 Q.Please summarize the benefits of the Company's coal supply strategy to Idaho
2 customers.
3 A.The Company has pursued a diversifed coal supply strategy, relying on fixed
4 contracts, indexed contracts and affiliate-owned coal mines to meet the fuel needs of
5 its coal plants. This strategy has resulted in a long-term, stable and low-cost supply
6 of coaL. In paricular, the operating cost for each of the affiliate mines remains
7 considerably less than market alternatives. While mine production costs wil
8 typically fluctuate more than contract prices in a given year, the Company's afmate
9 mines are superior to other supply options and consistently provide benefits to
10 customers.
11 Q.Does this conclude your direct testimony?.12 A.Yes.
.
675
REDACTED
Crane, Di - 10
Rocky Mountain Power
.1 Q.Please state your name.
2 A.My name is Cindy A. Crae.
3 Q.Are you the same Cindy A. Crane who has tetified previously in this case?
4 A.Yes, I am.
5 Q.What is the purpos of your rebuttal testimony?
6 A.The purose of my testimony is to:
7
8
9
10
11.12
· Rebut the testimony of Idaho Public Utilties Commssion Staff ("IPUC")
witness Mr. Joe Leckie regarding IPUC's propose disallowance of the
Company's Fuel Stock; and,
· Rebut the testimony of PacifiCorp Idaho Industral Consumers ("PUC")
witness Mr. Randall 1. Falkenberg regarding fuel quality problems at the
Jim Bridger plant.
13 Fuel Stock Adjustment
14 Q.
15
16 A.
17
18
19
20
21
22.
Please summarize the adjustment that IPUC witness Mr. Leckie recommends
in regards to fuel stock.
Mr. Leckie proposes to limit the coal inventory level for each plant site to no
more than the actual tons as of December 2009. Mr. Leckie questions the
necessity of increasing the tonnage size of the stockpiles from 2009 actual to 2010
pro forma and believes that customers should receive the benefit of the
Company's ability to operate six coal sites at their reduced tonnage levels but
should not bear the cost of the increase tonnage at the other coal sites without just
and reasonable cause.
676
REDACTED
Crane, Di-Reb - 1
Rocky Mountain Power
.1 Q.Do you agree with Mr. Leckie's adjustment?
2 A.No, the Company believes that Mr. Leckie did not consider all the facts before
3 makng his recommendations.
4 Q.Please explain.
5 A.Firt, by limiting inventory levels to no more than the actual tons in inventory as
6 of December 2009, Mr. Leckie grossly overstates the increase in coal inventory
7 for the Uta plants. Mr. Leckie's analysis implies that coal inventory levels in
~Utah increased by 300,691 tons during the test period whereas the pro form test
9 period reflects only an increase of only 66,606 tons, see Exhibit No. 64. Second,
10 Mr. Leckie's analysis fails to recognize that the actual inventory levels as of
11 December 2009 for the Bridger, Naughton and Hayden plants were below.12 Company targets. The test period reflects inventory levels at these levels
13 conformng to established targets by year-end.
14 Q.Please explain Mr. Leckie's adjustment for the Utah inventories?
15 A.Mr. Leckie incorrectly assumes that all the Utah stockpiles are independent of
16 each other. For instance, Mr. Lekie assumes that stockpile reductions at the
17 Huntington plant, (228,206) tons, and Carbon plant, (5,879) tons are unrelated to
18 the increase in the Rock Garden of 246,400 tons.
19 Q.Are the Huntington and Rock Garden stockpiles interrelated?
20 A.Yes. All of the Deer Creek mine's production is delivered to the Huntington plant
21 via an overland conveyor. A minimal amount of coal is maintained in silo at the
22 Deer Creek mine. Dependig upon mine production levels and quality, Deer.23 Creek coal could be transferred from the Huntington plant to Carbon, Hunter,
677
Crane, Di-Reb - 2
REDACTED Rocky Mountain Power
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7 A.
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15 Q.
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Rock Garden or Prep Plant. The Rock Garden pile is located approximately 3
mies from the Huntington plant. The Rock Garden pile provides storage and
blending capabilty for the Uta coal fleet. Deer Creek coal production comprises
almost 95 percent of the Rock Garden inventory.
How much Deer Creek coal was transferred from the Huntington plant to
the Rock Garden?
The Company transported almost 228,000 tons of high British therml unit
content, low ash Deer Creek coal from the Huntington plant to the Rock Garden
durng the first half of 2010. Essentially, the increase in the Rock Garden
inventory is offset by corresponding decreases in stockpiles at the Carbon and
Huntington plants.
Does the test period reflect increases at other Utah sites?
Yes. As shown in Exhibit No. 64 the stockpiles at Hunter and the adjacent Prep
Plant increase by 2,755 tons and 51,035 tons respectively, or 53,790 tons in total.
Please explain the increase at the Prep Plant and Hunter plant.
The majority of the coal is supplied by Arch's Sufco mine under a long-term coal
supply agreement. The Arch contract provides for a price reset of the Sufco
contract in 201 1. Though the paries are stil in negotiations, the Company
projects the 2011 contract price wil increase by
_, if not more, over the 2010 price. The Company has prudently
minimized futue costs by purchasing and stockpiling the lower priced coal in
2010 and reducing the amount of Sufco coal purchased in 2011.
678
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Crane, Di-Reb - 3
Rocky Mountan Power
.1 Q.Is this consistent with the Company's inventory policy?
2 A.Yes. The Company's inventory policy contemplates increasing inventory levels if
3 there are opportnities to procure coal at below-market prices. This prudent
4 management benefits customers, the slight increase in coal inventory caring
5 costs is more the offset by the lower purchase price of the coal.
6 Q.Are any of Mr. Leckie's proposed adjustments to the Utah stockpiles
7 appropriate?
8 A.No. Clearly, the transfer of Deer Creek coal from Huntington to the Rock Garden
9 is causative of their large but opposite inventory swings. Increasing stockpiles at
10 ,both Hunter and the Prep Plant wil benefit customers: the savings in fuel costs
11 wil more than offset the increased carring charges. As shown in Exhibit No. 64,.12 Mr. Leckie's proposed adjustment of $15,970,759 (system) decreases to
13 $7,782,604 (system) after the erroneous Utah stockpile adjustments have been
14 removed.
15 Q.Are there other additional problems with Mr. Leckies' analysis?
16 A.Yes, the Company disagrees with Mr. Leckie's contention that the stockpile
17 increases at Bridger, Naughton and Hayden are not just and reasonable. The
18 stockpile levels at these plants were considerably below Company inventory
19 targets as of December 2009. The test period forecast reflects these stockpiles
20 reaching Company targets by the end of the test period. In fact, as of September
21 2010, actual inventory levels at the Bridger and Naughton plants were slightly
22 above year-end test period balances..
679
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Crane, Di-Reb - 4
Rocky Mountan Power
.1 Q.Please describe the available coal supplies in Southwest Wyoming.
2 A.There are only thee mines curently in operation in Southwest Wyoming: Black
3 Butte, Kemmerer and Bridger Coal. Total annual production from these three
4 mines is estimated at 14.5 millon tons, the Jim Bridger and Naughton plants
5 consume almost 80 percent of this production. The lack of a rail unloading
6 facility at the Naughton plant and the absence of other proximate supply
7 alternatives would severely hamper the abilty of Naughton and Bridger plants to
8 respond to production shortfalls.
9 Q.Please explain the Company's inventory target for the Naughton plant.
10 A.The Company has established a 45 - 55 day inventory target for the Naughton
11 plant. A cessation in production at the Kemmerer Mine would require the.12 Company to divert coal supplies from either the Bridger Mine or Black Butte
13 Mine to the Naughton plant. Such deliveries would be contingent upon the
14 Company's abilty to secure sufficient trcking capacity to support the 125 mile
15 hauL. Based on prior experience, the Company believes it could take upwards of
16 two months to mobilze a trcking operation that could sustain the plant.
17 Q.Does the Naughton plant's test period ending balance conform to the
18 Company's inventory targets?
19 A.Yes, the test year ending inventory balance of 350,267 tons is equivalent to
20 approximately 47 days of inventory which is slightly less than the midpoint of the
21 established inventory target. Furher, as of September 2010, there was 359,046
22 tons of coal stockpiled at the Naughton plant..
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Rocky Mountain Power
.1 Q.Please explain the Company's inventory target for the Bridger plant.
2 A.The Company has established a 50 - 55 day inventory target for the Jim Bridger
3 plant. The supply risk associated with underground mining is dramatically
4 different than a typical surace mine. Quality and mining conditions can var
5 creating both supply and blending challenges.
6 Q.What steps has the Company purued to increase the supply security at the
7 Bridger Plant?
8 A.In early 2009, the Bridger plant received a permt from the Wyoming Deparment
9 of Air Quality allowing the increase of its long-term (dead) storage from 500,000
10 tons to 1 million tons. When combined with the short-term storage,Jim Bridger
11 plant's inventory capacity wil eventually expand to 1.3 millon tons. Per permt,.12 this increase wil be accomplished over a thee-year period: 2009 though 2011.
13 The permt also limited the plant to increasing its long-term pile by no more than
14 200,000 tons per year.
15 Q.How much coal is now stored in the Bridger Plant's long-term storage pile?
16 A.At the end of September 2010, PacifiCorp'sshare of the long-term pile was
17 approximately 567,000 tons. PacifiCorp's share of the Bridger plant stockpile,
18 long-term and short-term, as of September 2010 was slightly above 800,000 tons
19 or 51 days.
20 Q.Do customers benefit from the increase in the long-term storage pile from
21 500,000 tons to 1 milion tons?
22 A.Yes. The Bridger Plant is the Company's largest generating source. Almost 50.23 percent of the plants' requirements are now supplied by the Bridger underground
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.1
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3 Q.
4
5 A.
6
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8
9 Q.
10 A.
11.12
13
14 Q.
15
16 A.
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18
19 Q.
20 A.
21
22.
mine. The increased inventory level minimizes the supply risk associated with
underground mining.
Has the Company engaged a third party consultant to review Bridger and
Naughton stockpile levels?
Yes, in early 2010, the Company retained the engineering firm of Pincock Allen
& Holt (PAH) to analyze inventory levels for the Company's Wyomig coal fired
power plants. The Company's inventory targets are consistent with PAH's
recommendations.
Please explain the increase at the Hayden Plant?
The majority of the coal is supplied by Peabody's Twentymile Mine, an
underground mining operation. Until the rail unloadig facility commences
operation in 2012, the Company has targeted approximately 60 day inventory
target.
Are there any plants whos inventory levels were above Company targets as
of December 2009?
Yes, inventory levels at the Cholla, Craig and Dave Johnston plants were above
target. The test period reflects the inventory levels at these plants reduced to
Company target by the end of the test period.
How doe Mr. Leckie treat these plants in his analysis?
Mr. Leckie readily accepts the Company's projected inventory reductions at these
plants while ignoring those plants whose inventory levels were increased to align
with prudent inventory target levels.
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Rocky Mountain Power
.1 Q.Does the Company expect to reduce inventory levels?
2 A.There are no plans to reduce plant inventory levels below test period ending
3 balances. The Company wil continue to seek opportnities to efficiently manage
4 fuel cost and quality though effective management of its inventory. Furher, the
5 Company may need to revise its inventory targets in Utah to even higher levels as
6 longwall mining operations continue to deplete and the Company faces uncertn
7 labor negotiations with the Deer Creek represented workforce.
8 Q.Can you pleae identify the primary driver of the Company's increase in test
9 period fuel stock?
10 A.Yes. Of the $24.6 millon system increase in fuel stock, $24.9 millon is drven
11 by price increases in the cost per ton coal, with $0.3 millon reduction due to.12 volume related costs as reflected in Exhibit No. 64.
13 Q.Did Mr. Leckie review the average price per ton per stockpile?
14 A.Yes, Mr. Leckie found the average cost per ton to be reasonable for valuing the
15 total value of stockpile.
16 Q.Pleas summarize the Company's position regarding the IPUC Staff's
17 proposed fuel stock disallowance.
18 A.The Company believes the Commssion should reject the IPUC Staff s proposed
19 $15,970,759 disallowance. Mr. Leckie adjusted inventory levels in Utah without
20 considering the interrelationship between stockpiles and the economic benefits of
21 the higher stockpile levels in Uta. Furer, Mr. Leckie's analysis ignores the
22 supply risks associated with maintaining adequate inventory levels, partcularly in.23 Wyoming.
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REDACTED Rocky Mountain Power
.1 Jim Bridger Fuel Deration
2 Q.Please explain PUC's, proposal related to the fuel at the Bridger Plant.
3 A.PUC argues that the quality of fuel at the Bridger Plant has resulted in an
4 unnecessary high number of derations at the plant. PUC argues that additional
5 costs resulting from fuel quality problems at the Bridger Plant be disallowed,
6 resulting in $800,037 (system) decrease in net power costs. PUC also proposes to
7 remove $1,660,000 (system) related to labor and benefits costs at Bridger Coal
8 from the test period expenses.
9 Q.Do you agree that the fuel quality at the Bridger plant resulted in additional
10 derations relative to other coal plants?
11 A.Yes. All coal plants are affected by changes in coal quality and their abilty to.12 blend coals. In coal mining, quality can var dramtically from seam to seam or
13 within a seam. Both Bridger Coal Company and the Jim Bridger Plant have
14 established coal quality targets for heat value, ash, sulfu, sodum, etc. Though
15 vigorous blending, both the Bridger mine and the Bridger plant minimize quality
16 varations that undermne optimal plant performance.
17 Q.Are there times when Bridger Coal deliveries have not met established
18 targets?
19 A.Yes. Although the Bridger mine does attempt to deliver a consistent product, at
20 times it is limited by the size and quality of the mine stockpiles and physical
21 logistics. Bridger mine's surface operation historically delivered a consistent coal
22 blend though mining of coal in multiple exposed seams. The development of the.23 underground mine and the scaling back of the surace operation has resulted in
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Rocky Mountain Power
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7 Q.
8 A.
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increased blending requirements, greater unpredictabilty in coal deliveries and
the potential for extended periods of high ash coal production.
For instance, if the longwall system is in an area in which the coal seam thickness
is less than the minimum cutting height of the longwall shearer, coal quality wil
be negatively impacted. Similarly, if the coal seam is diluted with in-seam
parings, coal quality wil be negatively impacted.
How has Bridger Coal quality changed with underground mining?
Bridger Coal Company's ash content is curently the critical quality characteristic.
As reflected in the char below, Bridger Coal Company and the Bridger Plant
have established 13 percent as the maximum ash content for optimal plant
pedormance. Prior to underground mining, the mine consistently delivered the
Jim Bridger plant coal with a maximum of 13 percent ash. With the advent of
underground mining, however, the calculated ash content has at times exceeded
13 percent ash.
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Rocky Mountain Power
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.1 Q.
2 A.
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r................................~~~~~~.~~;.~~;~~~;.~~~~~;;~~~.~~.~~.~~.¡~~~~~;~~~~;;~;.................................¡
1
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.,.1 ,. ¡19.00 .t...... .... ................ .............. ..........................................................................................................................
I! 17.00 .¡..... ..... ............. .... ......... .. ..........................................................................................................................1 i
! 15.00 (......... ..
1 13.00 l1 i
11:::: r:::::::::::::.:::::::~::::::::.:::::::~:::::::~:::::::::::::::::......,.......,.......,.......,.......,.......,.......,......,.......,.......,.......,.......,.......,..."""",.!!'" ø fj'l .J i$ ß I' ~ ~ i# '* ~ .sf sf SJo, ~ d' ß' ~a ~a §i §i §i#'~~ '' ",'l~ ..:11 #'~~ ,01 ",-r~ ~~~~~ '' ",-r~ ##.; ,~"".¡
Month/Year
-%Ash -PlantTarget ~ 13% Ash, .....................................................................................-...............................................................................................................
Does the Company routinely blend for ash content at its other locations?
All of the coal produced in Utah is curently from underground mining. All of
these mines, at times, produce coals that do not meet contract specifications. Coal
stockpiling and blending facilities at the Hunter and Huntington plants enable the
Company to mix these coals as necessar to provide the power plants with a
consistent coal quality. These facilities allow the Company to efficiently and
economically segregate, stockpile, and reclaim underground coal based on a
paricular coal quality. Without a similar facility at the Bridger Plant, both the
Bridger mine and the Bridger plant are potentialy limited at times in their abilty
to blend Bridger underground coal during periods of high ash and low heat
content.
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Rocky Mountain Power
.1 Q.Is Bridger Coal evaluating options to improve its blending capabilties?
2 A.Yes. The Bridger mine currently has stackig tubes adjacent to the underground
3 portal that partially alleviate the quality fluctuations. The mine modified the
4 stockpile footprint of one of its trck dump stations to fuer segregate coal
5 quality produced by the underground mine. The mine is evaluating enlarging the
6 footprint of this truck dump station to create an even larger inventory surface area
7 to accommodate the expected underground coal quality variabilty.
8 Q.Do you agree with PUC that costs associated with the additional derations
9 should be removed from NPC?
10 A.No. It is inappropriate to remove costs associated with "low-quality" coal from
11 the underground minè, but accept the lower coal costs that result from the.12 favorable economics associated with underground mining. In addition, PUC
13 incorrectly assumes that the total costs at the Bridger plant would not change from
14 what the Company has included in its fiing even though the generation at the
15 plant has increased due to removal of the outages due to "low-quality" coal.
16 Q.Are there coal quality advantages with the Bridger underground?
17 A.Yes, the lower sodium content allowed the Bridger plant to minimize potential
18 slagging issues from March 2007 though Februar 2009 when the Black Butte
19 mine delivered high sodium coaL.Due to limited production, Black Butte coal
20 deliveries average in excess of 4.5 percent sodium. The sodium content target is
21 less than 3 percent. Without Bridger's lower sodium coal, the Bridger plant
22 would have sustained deratings due to boiler slagging..
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Rocky Mountain Power
.1 Q.
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What impact would increasing the ratio of surface coal to underground coal
have on Bridger Coal deliveries?
Increasing surace production at the expense of the underground production
would likely result in lower ash coal content but higher fuel costs.
Why would Bridger plant fuel costs increase?
Increasing the ratio of surace production would likely require additional coal
production as the average heat content of the underground operation is typically
200 to 300 British thermat units per pound higher than the surace operation.
Additionally, the estimated incremental cost of the surace operation is greater
than the estimated decremental cost of the underground operation.
Please explain the nature of the $1,660,000 (system) PUC proposes removing
from test period net power costs as they relate to Bridger Coal?
Almost $1,616,000, or 97 percent, of this disallowance is associated with
management and union incentives at Bridger Coal Company. Each union
employee must meet specific safety goals to be eligible for the incentive, safety
incentives are $698,000 ofPIIC's adjustment. The remaining amount, $918,000,
is paid to management employees based on each individual's performance.
Management incentives ar an importt par of the compensation strctue.
Offering competitive total compensation, including wages and benefits, is critical
to Bridger Coal's efforts to attract and retain employees. Bridger mine
management employees are eligible for the same annual incentive program as
Rocky Mountain Power employees. Mr. Wilson discusses the Company's
incentive program in his rebuttal testimony.
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Rocky Mountan Power
.1 The remainder of this adjustment is primarily associated with meal expenses. The
2 majority of the meal expenses are incured durng mine safety training events for
3 surace and underground workforce as well as meal expenses associated with
4 business travel.
5 Q.Do you agree with PUC that these labor and benefit costs should be removed
6 from NPC?
7 A.No. PUC's proposed adjustment is arbitrar and is unrelated to coal quality issues
8 at the Bridger plant. PUC's disallowance of costs related to mine safety is
9 completely incompatible with the Company's mission to provide a safe working
10 environment. The Company has spent considerable time identifying quality
11 parameters that result in optimized plant performance for its thermal fleet..12 Bridger mine and Bridger plant personnel focus on coal deliveries and coal
13 quality. Since the majority of the coal blending occurs at the Bridger mine,
14 Bridger mine deliveries are often adjusted daily. Both the increase in Bridger
15 plant's long-term storage capacity and the Bridger mine's ongoing evaluation of
16 increasing surface storage capacity are indicative of the Company's focus on
17 pursuing economic options that maximize performnce.
18 Q.Does this conclude your rebuttl testimony?
19 A.Yes
.
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Rocky Mountain Power
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1 (The following proceedings were had in
2 open hearing.)
3 MR. SOLANDER: Thank you. Ms. Crane's available
4 for examination.
5 COMMISSIONER SMITH: Mr. Otto.
6 MR. OTTO: Thank you, Madam Chair. I have no
7 questions.
8 COMMISSIONER SMITH: Mr. Olsen.
9 MR. OLSEN: No questions, Madam Chair.
10 COMMISSIONER SMITH: Mr. Williams, Ms. Davison.
11 MS. DAVISON: Yes, Madam Chair. Thank you.
12
13 CROSS-EXAMINATION
14
15 BY MS. DAVISON:
16 Q. Good morning, Ms. Crane.
1 7 A. Good morning.
18 Q. I would like to refer you to your rebuttal
19 testimony on I'll be talking to you about your testimony
20 your rebuttal testimony -- on pages 9 through 14 which deals
21 wi th the Jim Bridger fuel deration issue. And on those pages,
22 do you respond to Mr. Falkenberg's proposed adjustment related
23 to the fuel quality at the Jim Bridger coal plant?
24 Yes, I do.A.
25 Q.And on page 9, lines 9 through 11 of your
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1 rebuttal testimony, you state, quote, that you -- I should say
2 that you, quote: Agree that the fuel quality at the Bridger
3 plant -- I'm going to insert the word "has" -- resulted in
4 addi tional deration relative to other coal plants. End of
5 quote.
6 Is that a correct statement?
7 A.Yes, that is a correct statement, and that
8 coincided with the transition period of time when the Bridger
9 mine was transi tioning from a surface operation to an
10 underground operation.
11 Q.So I take it that you agree that the coal quality
12 of the Bridger plant is an issue for the Company to resolve.
13 Correct?
14 A.It was an issue during that transition period.
15 The Company is managing and resolving that issue.
16 Q.And isn't it true then that Rocky Mountain Power
17 is evaluating populations on an ongoing basis to improve the
18 fuel quality situation at Bridger?
19 A.Yes, we are. We do that as a daily ordinary
20 course of business across all of our fleet.
21 Q.And do you expect that these efforts will result
22 in improvements in the fuel quality?
A.Yes, and they have.
Q.I'd like to hand you an exhibit that we have
premarked as Exhibit 619, and this is a Response to one of our
691
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1 Data Requests, 141.
2 ( PIIC Exhibit No. 619 was marked for
3 identification. )
4 Q.BY MS. DAVISON: Do you recognize that Data
5 Response?
6 A.Yes, I do.
7 Q.And my question is will these improvements result
8 in improvements in the heat value and the ash coal quality?
9 A.Yes, they will.
10 Q.And should the Idaho Commission assume that the
11 Company's efforts at making these improvements will be
12 successful?
13 A.Yes, they should.
14 MR. DAVISON: I have no further questions. Thank
15 you.
16 COMMISSIONER SMITH: Thank you, Ms. Davison.
17 Mr. Woodbury, do you have questions?
18 MR. WOODBURY: No, I don't. Thank you.
COMMISSIONER SMITH: He said, "No," and I didn't
20 hear it?
21 MR. WOODBURY: Oh, I'm sorry. Yes, I did say,
22 "No. "
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24
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COMMISSIONER SMITH: Thank you.
Mr. Budge.
MR. BUDGE: No questions.
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1 COMMISSIONER SMITH: And I don't see Mr. Purdy,
2 so I guess he snoozed and he losed (sic).
3 Any questions from the Commissioners?
4 COMMISSIONER REDFORD: No.
5 COMMISSIONER KEMPTON: No.
6 COMMISSIONER SMITH: Nor I.
7 Thank you, Ms. Crane.
8 Any redirect?
9 MR. SOLANDER: No redirect.
10 COMMISSIONER SMITH: Thank you for your help.
11 THE WITNESS: You bet. Thank you.
12 MR. SOLANDER: May we also ask, Madam Chair, that
13 Ms. Crane be excused.
14 COMMISSIONER SMITH: If there's no obj ection, we
15 will excuse Ms. Crane.
16 (The witness left the stand.)
17 MR. HICKEY: Rocky Mountain Power would call as
18 its next witness Darrell Gerrard.
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1 DARRELL GERRARD,
2 produced as a witness at the instance of Rocky Mountain Power,
3 being first duly sworn, was examined and testified as follows:
4
5 DIRECT EXAMINATION
6
7 BY MR. HICKEY:
8 Q.Good morning, Mr. Gerrard. For the record, would
9 you please state your name and spell it?
10 A.Good morning, Mr. Hickey, and good morning,
11 Commissioners. My name is Darrell T. Gerrard: D-A-R-R-E-
12 double L; middle initial T; and last name, G-E-R-R-A-R-D.
13 Q.And by whom are you employed and in what
14 capaci ty?
15 A.I'm employed by PacifiCorp, and I'm vice
16 president of transmission system planning for Pacific Power and
17 Rocky Mountain Power, representing Rocky Mountain Power today.
18 Q.And are you the same Darrell Gerrard that filed
19 direct testimony on May 28th of this year, and prepared
20 Exhibits 37 through 39?
21
22
A.Yes, I am.
Q.And did you also file rebuttal testimony on
23 November 16th of this year and attach to it Exhibits No. 65
24 through 67?
25 A.Yes, I did.
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1 Q.Do you have any changes or corrections to any of
2 your testimony, Mr. Gerrard?
3 A.I do not.
4 Q.If I were to ask you the same questions that are
5 set out in your prefiled direct and rebuttal testimony, would
6 your answers be the same as are published in those documents?
7 A.Yes, they would be.
8 MR. HICKEY: Madam Chair, I would move that the
9 prefiled direct and rebuttal testimony of Darrell Gerrard be
10 spread upon the record as if it were read, and that Exhibits 37
11 through 39 and Exhibits 65 through 67 be marked for
12 identification.
13 COMMISSIONER SMITH: If there's no obj ection --
14 seeing no obj ection, it is so ordered.
15 (The following prefiled direct and
16 rebuttal testimony of Mr. Gerrard is spread upon the record.)
17
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19
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Please state your name, business address and present position with
PacifiCorp ("Company").
My name is Darell T. Gerrard. My business address is 825 NE Multnomah,
Suite 1600, Portland, Oregon 97232. I am Vice President of Transmission
System Planning.
6 Qualifications
7 Q.
8 A.
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23.
Briefly describe your education and business experience.
I hold a Bachelor of Science in Electrical Engineering (Power Systems Major)
from the University of Utah and Certifcate of Completion with Honors in
Electrcal Technology from Utah Technical College at Salt Lake. My experience
spans more than 30 years in the electrc utilty industr. I've had working
experience and management responsibilty for a number of functional
organizations at PacifiCorp including: Area Engineering; Area Planning; Region
Engineerig; transmission and distrbution ("T &D") Facilities Management;
Transmission, Substation and Distribution Engineerig; System Protection and
Control; T &D Project Management and Delivery; Asset Management; Electronic
Communications; Hydro System Engineering; Transmission Grid Operations;
and most recently, Transmission System Planning.
In my curent position, I am responsible for transmission planning
activities required to support PacifiCorp's existing and futue planned bulk
. transmission system. I am also responsible for the conceptual and detailed system
planning and architectue associated with the Company's comprehensive long-
term transmission expansion plan known as Energy Gateway.
696 Gerrard, Di - 1
Rocky Mountain Power
.1 Purpose and Overview of Testimony
2 Q. What is the purpose of your testimony?
3 A.The purose of my testimony is to provide additional details and technical
4 information, in support of the testimony of Company witness Mr. John A.
5 Cupparo, on the Company's decision to build the double-circuit 345 kilovolt
6 ("kV") Populus to Termnal transmission line (Phase I and II), which is par of
7 Segment B of Energy Gateway (See Exhibit No. 33). Specifically, my testiony:
8
9
10
11.12
13
14
15
16
17
18
. Provides an overview of the Populus to Termnal transmission line;
. Explains that the benefits of adding this transmission line are to meet
futue load and resource requirements for customers and to mantain
system reliability, consistent with the standads set by the Nort
American Electric Reliabilty Corporation ("NERC") and the Western
Electricity Coordinating Council ("WECC");
. Explains the analyses the Company pedormed that support the
decision to invest in this line;
. Describes the competitive procurement process used to make the
investment and how cost savings opportnities were identified; and
. Provides an overview of the constrction process.
19 Overview of Transmission Project
20 Q.Please describe the scale and size of the Populus to Terminal transmision
21 segment.
22 A.Populus to Termnal wil add 135 miles of new transmission line, over 8,600,000.23 linear feet of conductor and approximately 900 poles wil be installed on new
697 Gerrard, Di - 2
Rocky Mountain Power
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6 A.
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14 A.
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foundations. At the time of this fiing, the overall Populus to Termal project is
on schedule for completion in November 2010. The first phase of the project
extending 46 miles, from Ben Lomond Substation near Ogden, Utah to Termal
Substation in Salt Lake City, has been placed in service and is operational.
Please describe the transmission investment included in this rate case.
In this case, the Company is seeking cost reovery for the Populus to Termnal
transmission segment of Energy Gateway, described in more detail in the diect
testimony of Mr. Cupparo. A map showing the entire route of the Populus to
Termnal segment is shown in Exhibit No. 34. The Company estimates the costs
for the Populus to Termnal segment to be placed in-service in the test period of
this case are approximately $801.5 milion as shown in Exhibit No. 37, and
expects the line to be in service by November 30, 2010.
What is the purpose of the Populus to Terminal transmission segment?
In addition to the project benefits described in the testimony of Mr. Cupparo, the
purose of the Populus to Termnal transmission line is to:
. Increase the overall transmission capacity in the existing transmission
corrdor between southeast Idaho and northern Utah, where the existing
system has limited capacity and has demonstrated operational limitations.
. Meet the immediate need to: (1) improve system reliabilty in the area and
maintain compliance with national electrcal system reliabilty standads
by installing new transmission capacity to ensure the system can susta
transmission outages north of Termnal Substation without curtilng
loads, generation or impacting PacifiCorp's East Control Area and
698 Gerrard, Di - 3
Rocky Mountan Power
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neighboring transmission balancing authority areas; and (2) improve the
Company's abilty to perform maintenance on trnsmission facilities
between Populus and Termal by having alternative transmission paths
that allow facilities to be taken off-line and maintained.
. Meet the transmission capacity and reliabilty requirements necessar to
deliver resources to loads as specified in the annual Loads and Resource
plans submitted to PacifiCorp under requirements of its Open Access
Transmission Tarff ("OA IT").
. Provide PacifiCorp with options and greater flexibilty when considerig
futue planned resources to meet customers' growing demands for energy
while meeting current and future energy requirements that may be
mandated by state and federal regulation.
. Faciltate the integration of potential new energy resources in Wyomig,
Utah, Idaho and Oregon, and help support economic development in those
states.
. Integrate with futue Energy Gateway segments to increase trnsfer
capabilty between PacifiCorp's east and west control areas in order to
balance generating resoures and loads, and enable commercial energy
purchases or sales while allowing integration of new renewable generation
resources.
. In the long term, provide an incremental increase in transmission capacity
and reliabilty benefits for futue Energy Gateway trnsmission segments
planned between Wyoming, Idao, Utah, Oregon and Washington, and
699 Gerrd, Di' - 4
Rocky Mountain Power
.1 interconnect the region in general.
2 Need for and Benefit of Additional Transmission
3 Q.What information was used in determining the need and justification for this
4 investment?
5 A.PacifiCorp's OATT describes PacifiCorp's requirements and obligations to
6 provide transmission service.i Section 28.2 defines PacifiCorp's responsibilties,
7 which include the requirement to "plan, construct, operate and maintain the
8 system in accordace with good utility practice." Section 31.6 defines the
9 requirement for network customers to supply annual load and resource updates for
10 inclusion in planning studies. The Company solicits this data annually to
11 determne futue load and resource requirements for all transmission network.12 customers including PacifiCorp's network and third-pary customers. The
13 Company's retal loads comprise the bulk of the transmission network customer
14 needs including those in Idaho. Section 28.3 includes the requirement for
15 PacifiCorp to provide "firm service over the system so that designated resources
16 can be delivered to designated loads." These future requiements and needs wil
17 be met via Energy Gateway and its segments, including the Populus to Termnal
18 segment.
19 Q.Are other trnsmission performance requirements, besides growing
20 customer energy demand, driving the need for this system investment?
21 A.Yes. In meetig the currnt and future customer energy needs described above,
22 the Company must maintain a level of system reliabilty in order to provide
.1 PacifCorp's OA IT may viewed at
http://www.oasis.pacifcom.comfoasis/ppwIPACRE'STATEDOA1TASOFI -1 0-1 O.PDF
700 Gerrard, Di - 5
Rocky Mountan Power
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adequate transmission service. The NERC and the WECC have recently adopted
and enacted a significant number of standards and guidelines that specify in detail
the levels of system performance that entities like PacifiCorp must mantain
durng the planning, operation and ongoing maintenance of their bulk electrc
systems. NERC's reliability standards were approved by the Federal Energy
Regulatory Commssion ("PERC") and are mandatory for all PERC-jurisdictional
entities. These reliabilty standards are targeted at improving the securty and
reliabilty of the nation's electric infrastrctue and, specifically in PacifiCorp's
case, the WECC region. Investments made in Populus to Termnal wil help
PacifiCorp comply with these mandatory reliabilty requirements. Furter, the
investment wil provide reliabilty benefits to futue planned high-voltage
transmission additions interconnecting Wyoming, Utah, Idaho, Oregon and the
region.
Are there examples where these new reliabilty standards and guidelines
resulted in changes to the system and its operation, which drives investments
required in transmission?
Yes. In early 2008, PacifiCorp performed an operational analysis of the
transmission system nort of the Ben Lomond substation. As a result of this
analysis, and reflective of NERC and WECC standards and guidelines, the system
fir transmission capacity was reduced from approximately 775 MW to 430 MW
during heavy-load hours and reduced from approximately 900 MW to 620 MW
during light-load hours. This reduction in firm capacity was a result of NERC
and WECC standards and guidelines that require transmission capacity to be
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reduced due to potential outage risks associated with multiple transmission lines
being located adjacent to each other in common corrdors. The investment in the
Populus to Termnal segment is required to increase the fir capacity in this par
of the transmission system.
How did the Company determine that additional transmision capacity was
needed?
The Company utilzes the Integrated Resource Plan ("IRP") to review whether
additional transmission capacity is needed. The IRP uses a public process to
develop a framework for the prudent future actions required to ensure the
Company continues to provide reliable and least-cost electric service to its
customers. It must do this while also strng an expected balance between cost
and risk over the planning horion and takng into consideration environmental
issues and the energy policies of PacifiCorp's states. As stated in the 2008 IRP,
"PacifiCorp's IRP madate is to assure, on a long-term basis, adequate and
reliable electrcity sllpply at a reasonable cost and in a manner consistent with the
long-run public interest."i
Did the Company make any commitments to add transmission capacity?
Yes. During the MidAmerican Energy Holdings Company ("MEHC") acquisition
of PacifiCorp in 2006, the Company commtted to increase the transmission
capacity by 300 MW from southeast Idaho to nortern Uta. The objectives of
the trnsaction commtment were to:
. Enhance the reliabilty of the only high use commercial path between
Idaho and Utah;
22008 IRP at p. 19.
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. Provide for increased transfer capabilty between PacifiCorp's east and
west control areas; and
. Facilitate the delivery of future power from wind projects in Wyoming
and Idaho, and provide PacifiCorp with greater flexibilty and the
opportnity to consider additional options regarding futue planned
generation capacity additions.
Describe how the Populus to Terminal transmission segment complies with
the IRP andMEHC commitment.
The Populus to Termnal transmission line segment is designed to meet load
growth, futue customer energy service requirements and improve overall system
reliabilty. Based on the Company's 2008 IRP, PacifiCorp's network load
obligation is expected to grow durng the next 10 to 20 years. In addition,
operational reserve obligations requird to balance and maintain system reliabilty
wil increase over time as they are a function of load served. The existing
transmission capacity from southeastern Idao into Utah is fuly subscribed and
no additional capacity can be made available without the addition of new
transmission lines. The Populus to Termnal line wil add significant new
incremental transmission capacity p,400 MW planned) to this area of the system
and wil help integrate other future planned resources, market purhases and sales
as necessar to help control energy costs. The investment also improves the
system reliabilty as needed, which I discuss later in my testimony. All of the
above support PacifiCorp' s IRP and the commtments made by MEHC.
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.1 Q.Has the Company performed other studies and analyses that demonstrate the
2 need to improve the reliabilty of the transmission system in this area?
3 A.Yes. In addition to the long-term energy resource needs discussed in the
4 testimony of Mr. Cupparo, the Company,performed specific analysis in late 2007
5 and 2008 addressing several system distubance events that severely impacted
6 generation, customers, and the operation of the transmission system. These
7 events also impacttx other utilties interconnected to PacifiCorp's transmission
8 system. Additional details about these disturbances are given later in. my
9 testiony.
10 Q.Wil Populus to Terminal aid in preventing the recurrence of these types of
11 disturbances?.12 A.Yes. It is evident from these distubances and the resulting analysis that the
13 transmission system in this area does not have the necessar capacity and
14 reliabilty to meet all of the system operating conditions. NERC electric system
15 reliabilty standards require that the system demonstrate adequate performance for
16 all expected operating conditions including multiple contingencies. There were
17 five system distubances since September 2007 for which the Populus to Termnal
18 line diectly mitigates the risk of reoccurrence.
19 Q.Please provide further explanation of how Populus to Terminal will aid in
20 the prevention of these types of system disturbances.
21 A.Three of these disturbances occured on the system nort of Ben Lomond
22 substation and two occured south in the Ben Lomond to Termal section. These
23 disturbances resulted in system overloads, curtailments of schedules, repeated.
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curailments of interrptible loads, and generation reductions in Wyoming, Utah
and other surounding states. The three disturbances occured on September 27,
October 15, and October 21,2007, during periods of heavy flow nortbound from
the Termnal Substation towards Ben Lomond and into Idaho and on into the
nortwest. As a result, over 1,450 customers were afected by the first outage,
and some customer loads were either interrpted and/or reduced durng all thee
outages. Generation curtailments and adjustments of more than 1,000 MW had to
be requested for all thee incidents including reduced generation from Dave
Johnston and Naughton plants in Wyoming. Large industral customers like
Nucor Steel and Monsanto Corporations were impacted multiple times durng
these events and were required to reduce their electrcal demands to help bring the
transmission system back into reliabilty limits. Details and analysis of the
system performce durng the events and transmission limitations are detaled in
PacifiCorp System Distubance Report dated November 11, 2007, and
PacifiCorp's Abbreviated System Disturbance Report to WECC dated Januar 28,
2008.
On November 27 and November 30,2007, two disturbances occurred on
the Ben Lomond to Termnal section of the system causing overloads on three
WECC designated and monitored transmission paths. The disturbances impacted
more than 400 MW of PacifiCorp generation along with generation
interconnected to thee other utilties in surrounding states. These other
interconnected transmission providers, external to the states of Utah and Idaho,
also experienced overload conditions on their respective systems.
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Based on the system performance, studies and analysis, it is clear that the
existing system requires new capacity to meet expected operating conditions and
reliability requirements on both a short and long-term basis. The investment in
the Populus to Termnal line is the first step in providing the needed capacity.
What is the transmission capacity and limitations on this system today?
The existing transmission capacity in the area between Salt Lake City and
southeast Idaho is fully subscribed for fir service and has limted transfer
capabilty between several key transmission substations (Termnal, Ben Lomond,
and proposed Populus) connecting generation facilties in Idaho, Wyomig and
Utah. No new capacity wil be available until new transmission facilities are
constructed. The limitations and system performance deficiencies are discusse
later in my testimony. Theselimitations restrct the abilty to transfer firm energy
between PacifiCorp's Eastern Control Area to Western Control Area.
Does the investment in the Populus to Terminal line provide reliabilty and
capacity benefits to future planned transmission additions in the area?
Yes. The existing transmission in the corrdor from Termal to southeastern
Idaho has limtations. Without investment in the Populus to Termnal line, the
full transfer capabilty on both of the Gateway West and Gateway South
segments, which are described in Mr. Cupparo's testimony, would not be
possible. To obtain the full capacity of the Gateway West and Gateway South
segments, both segments must be electrically interconnected. This
interconnection is parially achieved by building the Populus to Termnal
transmission line as par of Gateway Central.
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What alternatives to the Populus to Terminal project did PacifiCorp
consider?
The Company considered but rejected four alternatives. The first alternative was
to not build the line or to upgrade other existing paths or sek additional
transmission corrdors into Utah. The Company rejected this alternative because
it did not improve existing system reliabilty or provide any new incremental
transmission capacity. New incremental transmission capacity is needed for both
load service and for contingencies.
The second alternative considered was to rebuild the majority of the
existing 138 kV lines interconnecting Utah and southeast Idaho and continue
operation of these lines at 138 kV. This alternative would have provided a smal
incremental increase of 300 MW or less in transmission capacity across the
curently constrained path between southeast Idaho and Uta. Italso would not
have provided adequate interconnection capacity between future Gateway West
and Gateway South segments or offer any additional capacity for the future. In
addition to the marginal increase in transmission capacity, this alternative had
serious constructability issues because it required large segments of the path to be
completely removed from service for extended periods (a year or more), while
these existing 138 kV facilties were rebuilt. This would have placed significant
reliabilty exposure on the transmission system serving the area to customers
during constrction. Additionally, this alternative did not allow the Company to
meet its current firm transmission obligations nor did it meet the long-range
resource plans and network load service requirements.
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The third option considered was to constrct a new single circuit 345 kV
transmission line from the futue Populus substation near Downey, Idao to the
Ben Lomond substation in Utah, which would have provided some capacity
increase from Idaho to Ben Lomond. This alternative included an upgrade of the
existing 138 kV line between Ben Lomond and Termnal to realize a minimum
increase in capacity of 300 MW from Ben Lomond to Termal substation.
However, this alternative would not have provided the necessar futue system
capacity between Gateway West and Gateway South and would have failed to
take advantage of maximizing transmission capacity installed in the new corrdor
and the existing Ben Lomond to Termnal transmission corrdor.
The four option considered was to build a new 500 kV line along the
route. The Company rejected this option because of its high cost, its potential for
significant siting and community impacts, its requirement for a completely new
corrdor between Populus and Termal substations, and its failure to use existing
vacant corrdors and property rights that the Company previously obtained.
Please explain any further considerations that inform the Company's
decision to select the Populus to Terminal line.
The Company selected this transmission line project based on several factors:
. It meets short-term and immediate reliabilty needs while prudently
planning for the futue.
. It adds significant long-term incremental transmission capacity (planned
rating 1,400 MW) across the curntly constrained transmission system.
There have been several transmission outages since 2007 along this
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corrdor that could have been mitigated with additional transmission
facilities. The risk of fuher unplanned distubances is considerable if the
curent facilities are not improved.
. It allows increased transfers of up to 1,400 MW of capacity between
southeast Idao and northern Utah that wil be required based on long-
term planning results.
. Construction benefits occur on a significant porton of the transmission
project due to existing corrdors that were acquired by the Company many
years ago just for this purose. The project optimizes use of limited
transmission corrdor lands by maximizing installed transmission capacity
in new corrdors.
. Construction could occur with minimum planned outages on' existing
facilties remaining in service without increasing reliabilty exposure to
the curent system.
. The Company's abilty to perform required mantenance wil be improved
without significant operational risk associated with tang existing lines
out of service.
18 Bid Process
19 Q.
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Please describe the Company's typical procurement proces used for major
transmission projects.
The Company uses a competitive blind-sealed bid process to contract for the
development of each project unless certain defined conditions apply, such as a
restrction in the supply of technology or design solutions that prevent an open
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competitive process. The form of contract tendered is a tuey, fixed-pnce, date
certain basis for delivery, referred to as an engineer, procure and constrct
approach. The Company identifies potential bidders that provide the capabilities
required to deliver the work scope within a boundar of project specific technical
specifications and commercial term. The tender process includes a question and
answer period to clarfy any outstanding issues and provides anonymity to the
requesting bidder, with responses of a non-confidential natue provided to all
bidders. Upon receipt of tender documents, the technical proposals are separated
from commercial proposals and a separate technical and commercial evaluation is
performed on all qualified bids using pre-established evaluation criteria (see
Exhibit No 38, summar of bidder evaluation). The technical evaluation is
assisted by external consulting firms who have been pre-contracted for such work
based on their industry expenence. Upon completion of technical and
commercial evaluations a recommendation is made to enter post-tender
negotiations to reach final term, conditions and pricing to support contrct
execution.
Was this typical procurement process applied to Populus to Terminal?
Yes. Specifically for the project, the Company adopted an open competitive
process where 75 vendors were identified and received an invitation to bid. The
competitive process began in October 2007 and provided two separate blind-
sealed bidding opportnities. During the October 2007 to May 2008 biddig
period, four communications were provided to bidders contaning additional
project-specific informtion. This information was intended to assist bidders to
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refine their submissions and specifically, to remove any bid qualifications
associated with contingent and non-firm pricing. All bid responses were initially
due in May 2008. After additional informtion was provided to bidders durng
May 2008 to July 2008, new or revised bids were due in July 2008 to allow a
furer refinement of previously submitted design solutions, terms and conditions,
including price. Thee qualified bids were received and evaluated resulting from
the May 2008 proposaL. Two competing bids were received in July 2008. Dug
the separate technical and commercial evaluations, the Company and its
consultants identified non-fixed price aspects of the bidders' proposals affecting
cost and schedule. The Company consultant computed a cost associated with
non-fixed price work scope submitted by each bidder, which ranged from
approximately $103 millon to $429 millon. The Company negotiated to remove
or cap the cost of non-fixed pnced work to mitigate post-contract award price
escalation and schedule change. The Company awarded the contract in October
2008 after negotiations that reduced the contractor's price. The original contract
costs associated with the Populus to Termnal investment to be placed in service
in 2010 are $567.6 millon.3 As shown on Exhibit No. 37, additional project costs
are associated with changes in the contractor work orders, materials purchased by
the Company, right of way acquisition costs, legal fees, internal labor and
purchased services.
3 The original contract alo includes costs associated with removing and replacing conductor on a
connecting transmission line that wil be completed in 201 1. These costs are not included in the reuest for
cost recvery in this case.
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1 Q.What process, if any, did the Company us to identify and implement cost
2 savings opportunities'during the procurement process?
3 A.Durng the tender evaluation process, bidders were requested to submit cost
4 savings opportnities for consideration. Each item was reviewed to assess
savings with respect to potential impact to operabilty, reliabilty and
maintainability that were included in the final contract price. In addition, post-
tender negotiations included a reduction' of $25 millon due to commodity price
reductions that occurred in the global market during the tender evaluation period.
Construction Process
Q., Please describe the construction proces.
A. The constrction process involves several major activities and numerous
subordinate tasks in order to engineer, procure and constrct transmission
facilities. The high-level tasks are:
. Preconstrction, which includes: planning and engineering; constrction
permtting; establishment of lay down yards; development of safety and
constrction plans; staging of constrction crews and materials; negotiation of
construction stipulation form with landowners; and public notification of
construction.
. Trasmission line constrction, which includes: initial access road
construction; foundation installation; tower installation; and installation of
conductor and optical ground wire.
. Substation constrction, which includes: access constrction; substation
grading; civil constrction; steel erection and control building instalation; and
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equipment installation.
. Testing and commssioning, which include individual line and equipment tests
and critical punch list resolution.
Exhibit No. 39 contains photographs of the constrction of the line and Populus
substation at varous stages completion.
What is the current status of construction of the Populus to Terminal line?
The first phase of the project between Ben Lomond and Termnal substation is
complete. The second phase of the project between Ben Lomond and Populus
substation wil be energized by November 30,2010.
Please state why you believe the second phase of the project wil be complete
and in-service by November 30, 2010.
Weekly project management status reports and field verification confir
construction is on schedule and wil be completed by November 30,2010, barng
unforeseen events.
Conclusion .
Q. Please summarize your testimony.
A. The existing transmission system capacity from southeastern Idaho into Utah is
fully utilzed, significant operational limitations exist on the system in this area,
and no additional capacity can be made available without the addition of new
transmission lines. The Populus to Termnal transmission line investment is
prudent because it meets immediate short-term reliabilty requirements and longer
term customer needs by adding significant incremental transmission capacity
between southeast Idaho and northern Uta.
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11.12 Q.
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Furer, the investIent facilitates a stronger interconnection to systems in
Idaho, Utah, and Wyoming and to the Northwest in general. The Populus to
Termnal transmission line, especially when integrated with the other proposed
segments of Energy Gateway, is fundamental to the development of new
renewable and other generation sources in Uta, Idaho and Wyoming. The
completion of the project wil be an important step in strengthening the western
grid's transmission infrastrcture, which is necessar based upon the projected
future energy service requirments of our customers including those in Idaho.
The project was bid out though a competitive bid process followed by
negotiations with the best bidders. The project is on schedule for completion and
to be placed into service by November 30,2010.
Does this conclude your direct testimony?
Yes.
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Please state your name.
My name is Darell T. Gerrard.
Are you the same Darrell T. Gerrard who has testified previously in this
case?
Yes.
What is the purpose of your testimony?
The purose of my testimony is to provide evidence in rebuttal to the Direct
Testimony of Mr. Dennis E. Peseau, on behalf of Monsanto Company and
rebuttal to the Direct Testimony of Mr. Randy Lobb, on behal of the Idaho Public
Utilties Commssion staff, in regards to the Company's Populus to Termnal
transmission project.
Would you please summarize your rebuttal testimony?
Yes. My testimony wil respond to the following items. First, statements by Mr.
Peseau that "most of the Gateway Central rate base wil not be use and useful at
the outset due to its over sizing,,,i and Mr. Lobb's statement that it is an
"undisputed fact that the project is oversized and wil not be fully utilze unless
or until Energy Gateway is completed."i The Company strongly disagrees with
both witnesses' conclusions that the project is oversized or overbuilt and does not
benefit customers and their recommendations that the project is not used and
useful and should not be fully allowed in rates. As explained in more detail
below, the project is designed to meet the current and futue electrcal needs of
the Company's customers and provides important and needed reliabilty benefits
.1 Peseau, Direct Testimony page 3, lies 6-7.
2 Lobb, Dirct Testimony page 27, lines 20-22.
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immediately while also addressing futue system needs in a prudent and
reasonable manner.
Second, the Company vehemently disagrees with Mr. Peseau's statements
that the Company's strategy for Energy Gateway is to "dominate transmission
services thoughout the western U.S." and provide "the 'highway' to California
and southern Nevada for sales of PacifiCorp's existing and developing wind
projects.,,3 This is a misstatement of the project and its intended purose, which
is to serve all of PacifiCorp' s electrc customers.
Third, the Company strongly disagrees with Mr. Peseau's statement that
"there is a real possibilty that Gateway South may be delayed or disapproved by
vire of other competing high voltage transmission line (sic) servicing simlar
markets.,,4 As explained more fully below, Energy Gateway is the only
transmission project proposed in the region that wil connect the Company's load
centers to the Company's existing and future resources. Reference to other
proposed projects in the region as being of potential benefit to PacifiCorp
customers is, therefore, irelevant.
Fourt, the Company disagrees with Mr. Peseau's statements regaring
project comparsons made between actual costs for Populus to Termnal and
conceptual cost estimates made regarding other "similar and competing" projects
planned for Nevada and elsewhere. As explained below, such comparsons are
overly simplified and do not take into account the specific cost characteristics and
requirements of the project.
3 Peseau, Direct Testimony page7, lines 5-10.
4 Peseau, Direct Testimony page U, lines 4-8.
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Finally, the Company refutes varous witness claims related to the impact
of the Populus to Termnal project on distubance events, system benefits of the
3 Populus to Termnal project for Path C capabilties, and the project as it relates to
4 MidAmerican Energy Holdings Company ("MEHC") transaction commtments.
5 In conclusion, my testimony and the evidence presented therein reaffis that the
6 Populus to Termnal project is properly sized to meet our customers' needs, both
7 current and futue, the specific project costs were justifed and prudent, and the
8 entire project is used and useful to the benefit of all the Company's customers.
9 Project Sizing
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Do you agree that the Populus to Terminal project is "over built" as alleged
by Mr. Peseau or agree that it is an undisputed fact that the project is
oversized as argued by Mr. Lobb in their respective testimonies?
No, I do not agree with either witness on this point. The project is sized and
constrcted as the best cost alternative for customers to properly meet current and
future electrical needs. The project addresses existing constraints across Path C,
eliminates the existing reliabilty concerns and constraints identified by the
Western Electricity Coordinating Council ("WECC") following distubances on
Path C and portions of the system directly south, and provides an immediate
increase in capacity necessar to meet existing customer load service and reserve
obligations. The Company has achieved an appropriate balance between building
transmission infrastructue to meet current servce and reliabilty needs while also
ensurng that futue needs are met which also support the transmission system as a
whole on a long-term basis. This "right-sizing" approach appropriately
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recognizes the inherent "lumpy" natue of transmission investment but limts the
impact by proceeding with the most reasonable, best cost alternative.
Please describe Path C and explain the reduction in constraints on Path C as
a result of ~he Populus to Terminal project.
Path C is a major transmission path that runs north/south between Idaho and Utah
and includes a mix of existing transmission lines at varous voltages. As noted,
the Populus to Termnal project facilitates improved performance and reliabilty
of the entire system, including Path C. Currently, Path C capabilty is limited in
the winter and summer seasons; scheduled or real time flows over this path may
not exceed these limits without violating reliabilty standards. Power flow
simulations used in planning and rating the project demonstrate that the addition
of the Populus to Termnal project wil result in the elimination of the curent
seasonal limitations for Path C, also allowing flows to reach as high as 2800 MW
during outages facilitating fir ratings for Gateway West or Gateway South.
Please refer to the Executive Summar (Section 1) of the October 6,2008 WECC
approved Phase 2 Study Report,S which describes the facilities that must be added
to obtain the necessar new capacity requirements for the Populus to Termnal
proj~ct. Also refer to Exhibit No. 65, in which Figure 1 depicts Path C operating
limits before the Populus to Termnal project and Figure 2 shows the new Path C
operating limits after project is in-service. I further discuss these items later in
this testimony.
5 Provided as Attachment ¡PUC 202b in response to ¡PUC Production Data Request 202.
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Does prudent planning require consideration of future system needs when
developing a project like Populus to Terminal?
Yes. It would be imprudent of the Company to only consider the current needs of
the system when makng such a significant investment. Please refer to the
September 2008 PacifiCorp Analysis of the Populus to Termnal Project,6 which
includes analysis and facts that clearly show this project and its planned capacity
are required in the futue. This project is sized and constructed to meet those
requirements, in addition to the requirement to provide a significant capacity
benefit to Path C. I furter discuss this matter later in this testimony.
Why build the project now for future capacity rather than build a smaller
capacity project now and add another project later to meet future needs as
suggested through the testimony of Mr. Peseau and Mr. Lobb?
The project as planned, designed and constructed has a lower cost to our
customers and lower impact on communities, the environment, and public and
private lands compared to an alternative proposing multiple projects. In order to
complete the project, a new transmission line corrdor was required between the
Populus and Ben Lomond substations and the use of an existing corrdor
previously established between Ben Lomond substation and Termnal substation.
There was significant public opposition and major challenges to overcome in
obtaining the required new corrdor to accommodate one transmission line. It was
made very clear by all stakeholders involved durg the siting and permtting
process that any additional or future corrdors wil not be tolerated or approved.
6 Prvided as Confidential Attachment Monsanto 1.1 1 -2 in response to Monsanto Data Request 1.1 1.
719
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Would it have been more cost effective for the Company to build a smaler
project at this time and to then build a future expansion?
No. Had the Company made the decision to build a single circuit 345kV lower
capacity line in the new corrdor, the only option available to the Company to
gain the required futue capacity would be to remove the line and replace it with a
higher capacity line, either 345kV double circuit or 500kV single circuit. The
Company estimates that, if it had pursued this option and had to replace the single
circuit 345kV line with a double circuit 345kV line in the futue, the cost to
customers would be $1.24 billon (see Exhibit No. 66), or 54 percent higher than
the total cost to date for the Populus to Termnal project. Additionally, the
Company had formally rejected a 500kV alternative due to its high cost and
inabilty to effectively site and operate that voltage in the existing corrdor
between Ben Lomond and TermnaL. The cost and environmental and public
impacts of building multiple smaller projects over time to gain incremental
capacity is significantly more than building a double-circuit 345 kV project once.
In addition to excess capital costs associated with multiple projects over time,
each would require extensive line outages for a constrction period of more than a
year and would reduce Path C capacity back to today's levels or lower. Under
such alternatives, the Company would have to build additional generation or
purchase energy, if any was available, to serve customers durng such
construction outages. The aforementioned alternatives were all evaluated and
rejected as more costly and obviously imprudent approaches to address the needs
identified for the Populus to Termnal project. Please refer to Sections 3 and 4 of
720
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the September 2008 PacifCorp Analysis of the Populus to Termnal Project,7
where alternatives are discussed in detaiL.
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Was Energy Gateway proposed as an "export highway to California and
southern Nevada," as claimed by Mr. Peseau?
No. The Energy Gateway project does not create any new transmission capacity
into California. The proposed Gateway South project provides a small increase in
new transmission capacity (approximately 300 MW) necessar to import energy
from Nevada into Uta required to serve customer load. The overall Gateway
project purose is to deliver resources as defined in PacifiCorp's Integrated
Resource Plan to PacifiCorp customers and to provide resource options over the
"".
long term as required for serving PacifiCorp's loads. Contrar to Mr. Peseau's
assertion, PacifiCorp is not in the merchant transmission or generation business
14 and is not seeking to build an export highway.
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Mr. Peseau states that ''there is a real possibilty that Gateway South may be
delayed or disapproved by virtue of other competing high voltage
transmission line servicing similar markets."s Is that true?
Absolutely not. A number of projects have been proposed in the region in and
around Energy Gateway; however, these projects do not connect the Company's
load centers to the Company's existing and future resources, and therefore are not
useful to the Company in serving its customers. These proposed projects are
7 Provided as Confidential Attachment Monsanto 1.1 1 -2 in response to Monsanto Data Request 1.1 1.
8 Peseau, Direct Testimony page 11, lines 4-8.
721
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neither similar to nor in competition with Energy Gateway. Please refer to my
Exhibit No. 67, which provides the "Foundational Projects by 2020" map from
the August 11, 2010 Subregional Planning Group Coordination Group's report to
WECC9 as par of its Regional Transmission Expansion Planning initiative. The
"Foundational Projects" list was developed through extensive planning and
collaboration effort among subregional planning groups throughout the Western
U.S., and wil be relied on heavily for WECC's Transmission Expansion Planning
Policy Commttee's efforts to develop plans for the entie western
interconnection. The projects shown on this map are those identified as having "a
very high probabilty of being in service in the 10-year timeframe. As the map
shows, the Energy Gateway projects are the only high voltage transmission lines
that connect to the Company's load centers in Idaho, Utah, Oregon and Wyoming.
Once again, the Gateway Project - and specifically Gateway Central - is
not being built to service external markets. It is totally inaccurate for Mr. Peseau
to state that "there is a distinct possibilty that Gateway Central would become a
largely stranded investment."
10 Gateway Central is needed to reliably transport
new and existing resources to the Company's customers to meet current and
future customer requirements. As stated above, no other projects proposed in the
region connect the Company's existing and future resources to the Company's
load centers in Idaho, Utah, Wyoming and the Pacific Northwest. More
specifically, no other project provides increased transmission capacity in the
9 Report avaiable at
http://www.wecc.bizicommittccsIODffPPC/SCG/Shared%20DocUlnentsfSCG%20Foundational %20Tra
nsmission%20Proicct%20List%20Report.pdf10 Peseau, Direct Testimony page 17, lines 2-4.
722
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, Rocky Mountain Power
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portion of the Company's transmission system in nortern Utah and southern
Idaho and between the Populus and Termnal substations, where additional
3 capacity is presently needed.
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Can you provide a justifcation as to why the cost per mile of the Populus to
Termnal project is higher than other projects sited by Mr. Lobb and Mr.
Peseau in their testimony?
Yes. A comparson was made by Mr. Lobb, stating that the Populus to Termnal
Project is nearly twice the cost per mile of the Company's Camp Wiliams to 90th
South 345kV transmission line ("Camp Wiliams line"). 11 Both witnesses
provided cost comparsons using a very simple calculation to show cost-per-mie
basis only and concluding, therefore, that a project with longer line miles wil
result in an overall lower cost per mile. Comparson of these two projects is not
valid due to several factors discussed in detail in the Company's response to
IPUC Production Data Request 277, including the following:
· the Camp Wiliams line was a small-scale project, constrcted on a low-
cost existing right of way and it is located in the city on flat and accessible
terrain that required few if any access roads. By contrast, the Populus to
Termnal line is a large-scale, mostly rural and remote project, with
significant hard-rock topography along the northern segment and soil
conditions along the southern segment that required foundations to be
drlled, on average, more than twice the depths requir for the Camp
Wiliams line foundations. The drllng depths along the southern segment
11 Lobb, Direct Testimony page 25, lines 8- 1 7.
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required larger and more expensive drllng equipment and drove a
significant difference in the volume of excavation and concrete required,
with an average volume of 134 cubic yards compard to an average of 53
cubic yards per foundation for the Camp Wiliams line; the Camp
Wiliams line is located in the Salt Lae City valley where materials and
supplies can be acquired, delivered, stored and staged for constrction
with great effciency. Constrction equipment is readily available such as
excavation equipment, erection cranes and cement trucks. Again by
contrast, the location of the Populus to Termnal project is far from
materials and supplies, requirng additional logistics storage facilities,
trucking costs and mobilzation/demobilzation from multiple sites in
remote locations;
the Camp Wiliams line did not require any new substations or sites to be
established, only modification of two existing substation facilties. The
requirement for substation interconnection to load centers and to resource
centers wil significantly influence the cost-per-mile of a transmission
project. The Populus to Termnal project has functional requirements
which necessitate the establishment of a totally new "green field"
substation at Populus where the project interconnects with several new and
existing high voltage lines. It also requires interconnection at the
Company's existing Ben Lomond substation load center and, fuher
south, interconnection to the existing Termnal Substation load center.
724
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In summ, Mr. Lobb and Mr. Peseau's cost-per-mile comparsons are overly
simplistic and provide no real basis to assess or quantify system functionality,
capacity, performance or benefit to the system or to customers. By way of
example, their simple analysis would be akn to comparng the cost of two
vehicles based on their wheel-base dimension without any regard to respective
capabilty, performce or abilty to meet customer need.
How did the Company ensure that the costs to build the project as scoped
were justifed and reaonable?
The Company employed an open competitive process to control costs where 75
vendors were identified and received an invitation to bid. The Company uses a
competitive blind-sealed bid process to contract for the development of each
project unless certain defined conditions apply, such as a restrction in the supply
of technology or design solutions that prevent an open competitive process. The
form of contract tendered is a turney, fixed-pnce, date certin basis fordelivery,
15 referred to as an engineer, procure and constrct approach. Furer detals on cost
16 controls are covered in my direct testimony.
17 Disturbance Events
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.23 the addition of the Populus to Termnal line directly mitigates reoccurence of
Mr. Lobb states that it is unclear what impact the Populus to Terminal Line
would have had, had it been in place during the disturbance events sited by
the Company in this cae.12 Can you please explain the impact?
Yes. The system disturbances and significant impacts are discussed in detail in
my Direct Testimony staring on page 9 line 1. As explained in that testimony,
12 Lobb, Direct Testimony page 22, lines 7-12.
725
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1 such distubances. Mr. Lobb points out in his testimony that, according to the
2 WECC Abbreviated System Disturbance Reports 13 the only customers curailed
3 durng the October 15, 2007 event were NUCOR and Monsanto, and no other
4 customers were impacted. It is tre that these two were the only customers
5 curailed durg this paricular event, but it is i;so tre that these customers faced
6 curtailments multiple times in 2007, and as documented in a PacifiCorp System
7 Disturbance Reportl4 and furher stated on page 10 of my direct testimony, more
8 than 1,450 additional customers were affected due to similar system outages in
9 this par of the system on September 27, 2007. In addition, several of the
10 disturbances had significant and detrmental impacts to other interconnected
11 utilties due to overloading of multiple transmission lines and curailment of on-
12 line generation stations. With the advent of new PERC-mandated reliabilty
13 standards for Bulk Electrc Systems transmission owners and operators, such
14 entities are subject to significant fines and sanctions if they do not plan and
15 operate their interconnected systems reliably. Path C operating capacity was
16 substantially decrease in 2008 subsequent to these events.
13 Provided as Confidential Attachments 6.6-1 and 6.6-2 in response to Monsanto's Data Request 6.6.
14 Provided as Confidential Attachment Monsanto 6.6 1st Supplemental.
726
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Mr. Lobb states that the system benefits of the Populus to Terminal projec
to improve Path C capabilties and meet North American Electric Reliabilty
Corporation ("NERC") WECC standards are "less than half of the 700 MW
currently provided by the project and less than 25 percent of the 1400 MW
capacity that the project could ultimately provide."ls Is this accurate?
No, Mr. Lobb's conclusion is not supported by the complete history and curent
capacity status of Path C. His statement does not fully reflect the capacity
contrbution to Path C provided by the Populus to Termnal project, as it only
considered path reductions due to reliabilty issues that occurred in 2008. Please
refer to my Exhibit No. 65 (Path C - Fin transmission capacity as a function of
ambient temperatue and loads). This figure, obtained from an Operational
Transfer Capacity study approved by WECC, shows Path C Fin transmission
capacity as a function of ambient ai temperatue and as a function of southeast
Idaho electrcal load prior to Populus to Termnal project in-service.
As set forth in the exhibit, the firm transmission capacity in summer is 575 MWat
100 degrees F prior to Populus to Termnal depicted on line "A". When Poplllus
to Termnal is placed in service, Path C capacity is no longer a function of
temperature or loads and this char is no longer valid. The Path C firm
transmission capacity increases to a set amount of 1600 MW. Therefore, the
capacity contrbution to the system, and specifically to Path C, is nearly 1000
MW of its planned 1400 MW rating and not 335 MW of 1400 MW as stated in
Mr. Lobb's testimony.
727
15 Lobb, Dirct Testimony page 22, lines 1 -6.
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transmission system requirements. In early 2007, the Company initiated its
annual load and resource study, required under its federal Open Access
Transmission Tarff ("OA IT"), which forecasts network customer loads and
resources for the next ten year. Compliance with the OA IT requires the
Company to respond to network customers' forecast needs by upgrading the
transmission system to deliver network resources to reliably serve loads. The
results of the study furter confirmed the need for additional long-term
transmission capacity and increased investment and upgrades in Path C well
beyond 300 MW. In addition, since 2005, several significant operational
disturbances occured which demonstrated that Path C was subject to significant
reliabilty limitations resulting from double line outage contingencies. Moreover,
operational events between Ben Lomond and Termnal substations occured that
demonstrated a clear need to improve capacity and reliabilty in the par of the
system south of Path C, as explained in my direct testimony, pages 9- 11. With
the announcement of Energy Gateway in 2007, the segment between Populus and
Termnal (Segment B) became an integral par of the Energy Gateway program by
providing a critical link that connects Energy Gateway West and Energy Gateway
South, and supports designed capacity ratings based onWECC and NERC
planning standards and criteria.
Can you please state how the project is "used and useful" and benefits the
Company's Customers?
As explained fully herein, my testimony provides clear evidence that the project is
not only fully used and useful but also the most prudent approach for all of the
729
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Company's customers based on its abilty to meet curent system electrical
demands and those forecasted in the futue. The project clearly provides
immediate reliabilty and capacity benefits to the system well in excess of the 700
megawatts suggested by both witnesses. The project and its resulting capacity is
required in order to reliably transport existing generation resources and those
included in the Company's curent and subsequent integrated resource plans, and
to deliver those resources to our Customers. The project's used and usefulness is
furer evidenced through the proceedings and supported though statements in
the Idaho and Utah Commssion Orders granting Certificates of Public
Convenience and Necessity ("CPCN") for the project in 2008. The Idaho
Commssion Order states:
"Thus, Staff believes that the necessity of the Project should be
viewed in conjunction with energy resources that are constructed,
under way or planned. PacifiCorp elected to undergo a
transmission upgrade as par of its preferred resource portolio of
an additional 2,000 MWs of renewable resources by 2013 in the
Company's 2007 IRP. A significant portion of these renewable
resources wil be located in Wyoming. Staff then listed more than
500 MWs of renewable resources that are either under constrction
or in the final stage of development. In response to a Staff data
request, PacifiCorp provided four alternatives that it rejected
because the Company did not believe that these would provide
sufficient capacity for the new resources. Staf agreed that the
Project was necessar in order for the Company to continue to .
provide reliable service from these new resources to growing load
centers." 17
In its order granting the CPCN for the Project, the Utah Commssion noted
several paries concured with the need for the project, includig the Division of
Public Utilties:
17 In the Matter of the Application of Rocky Mountain Power for a Certficate of Public Convenience and
Necessity Authoriing Constrction of the Populus-to- Teral 345 KV Transmission Line Project, Case
No. PAC-E-08-03, Order No. 30657 (October 10, 2008) at pp. 3-4.
730
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"The Division states it has examned underlying informtion upon
which a need for these additional trnsmission facilties may be
found and concludes it supports RMP's decision to build the
Transmission Line and confirs RMP's planned integration and
operation of the line with future utilty operations and activities.
The Division agrees with RMP's conclusions that there is a need
for the Transmission Line and the Company's futue utilty service
wil be more reliable and efficient with the Transmission Line's
addition." 18
I disagree with Mr. Lobb's reference to Idaho Code 61-502A regarding the "used
and useful" standard and the implication that the Project includes unnecessar
capacity. The capacity of this project is required and it is necessar to meet the
energy needs of our customers, including those in Idaho.
If a facilty is not fully subscribed, does that mean it is not "used and
useful?"
No. The only prudent approach to designing and building utility facilties is to
consider both curent and future requirements of that facilty.
Please summarize your tetimony.
The Idaho Public Utilties Commssion has aleady approved the need and
necessity of the Populus to Termnal project as recommended by Commssion
Staff. The Company planned, designed, engineered and constructed the line in a
cost effective and prudent maner. The Populus to Termnal line is fully used and
useful; it meets current nees and wil meet expected futue needs of our
customers, and it complies with the mandatory reliabilty standards and criteria
established by NERC and WECC entities. The project is properly sized and
.18 In the Matter of the Application of Rocky Mountain Power for a Certficate of Public Convenience and
Necessity Authoriing Constrction of the Populus to Termnal 345 KV Trasmission Line Project, Docket
No. 08-035-42, Report and Order Grting Certficate and Certficate of Public Need and Necessity,
(September 4, 2008) at p. 3.731
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constructed as the best cost alternative for customers to meet performnce
requirements and to function with the interconnected bulk electric system. The
project is used and useful to the benefit of all of our customers, including those in
Idaho, and should be fully included in rates.
Does this conclude your testimony?
Yes.
732
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1 (The following proceedings were had in
2 open hearing.)
3 MR. HICKEY: Thank you.
4 Q.BY MR. HICKEY: And, Mr. Gerrard, are you also
5 adopting the testimony of another witness in this proceeding,
6 John Cupparo?
7 A.Yes, I am.
8 Q.And just quickly, could you tell us who
9 Mr. Cupparo is and what his responsibilities are?
10 A.Certainly. John Cupparo is vice president of
11 transmission systems for PacifiCorp. He is my boss, and he is
12 responsible for all of the transmission aspects at PacifiCorp,
13 both Rocky Mountain and Pacific Power.
14 Q.And did you actually assist in the drafting of
15 that testimony?
16 A.I assisted in the review of that testimony, yes.
17 Q.Are you adopting the direct testimony of
18 John Cupparo that was filed on May 28, 2010, and the exhibits
19 accompanying it, 33 through 36?
A.I am.
MR. HICKEY: Madam Chair, I would move that the
22 prefiled direct testimony of John Cupparo be spread upon the
23 record as if read, and that Exhibits 33 through 36 be marked
24 for identification.
25 COMMISSIONER SMITH: If there's no obj ection, it
733
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P. O. BOX 578, BOISE, ID 83701
GERRARD (Di)
RMP
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1 Q.Please state your name, business address and present position with Rocky
2 Mountain Power ("Company").
3 A.My name is John A. Cupparo. My business address is 825 NE Multnomah, Suite
1600, Portland, Oregon 97232. My position is Vice President of Transmission.
Qualifications
Q. Please describe your educational and professional background.
A. I hold a Bachelor of Science degree in Computer Information Systems from
Colorado State University. My experience spans 24 years in the energy industry,
including oil, gas and electrc utilties. The majority of my experience has been in
information technology supportng natual gas pipelines, energy commodity
trading and end-to-end electric utilty operations. I have also provided support for
outage management, customer service, transmission scheduling and regulatory
issues. I joined PacifiCorp as Chief Information Officer in September 2000 and
assumed my curent position in August 2006. I am responsible for all aspects of
PacifiCorp's main gnd transmission investment strategy, customer service, main
grid planning, contract administration and tarf management. I am the co-chair
of the Nortern Tier Transmission Group ("NTTG"), which coordiates
transmission planning, transmission expansion, and project reviews with sub-
regional and regional planning organizations withn the Western Electricity
Coordinating Council ("WECC"). I am also an elected class one voting member
(transmission owner class) of the WECC Board of Directors. As a member of the
WECC Board of Directors, I paricipate with other WECC members in overseeing
WECC's activities, including defining standards and policies to ensure reliabilty
735
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.1 of the western electrc grid. I also hold a position on WECC's Transmission
2 Expansion Planning Policy Commttee and the Reliabilty Coordination
3 Commttee.
4 Purpose and Overview of Testimony
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What is the purpoe of your testimony?
The purose of my testimony is to provide informtion on the Populus to
Termnal trnsmission line, which is the first segment of the Energy Gateway
transmission expansion plan to be constrcted, and for which the Company is
seeking cost recovery in this case. The Populus to Termnal transmission line,
and subsequent investments within the Company's long-term, comprehensive
transmission expansion plan known as "Energy Gateway," satisfy multiple
objectives for efficiently operating a six-state transmission system. The
immediate benefit to PacifiCorp's customers in Idaho and elsewhere is a
significant investment to enhance reliabilty and improve transfer capabilty
within the existing system, followed over time by incremental capacity, which is
key to unlocking rich resource hubs. Specifically, my testimony:
. Provides an overview of the Company's trnsmission system;
. Outlnes the Company's transmission expansion plan and provides details on
the Populus to Termnal line segment of this plan;
. Demonstrates that the Populus to Termnal transmission investment is
beneficial to customers; and
. Describes how the Populus to Termnal transmission investment helps satisfy
a commtment the Company made as par of the MidAmencan Energy
736
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Holdings Company ("MEHC") transaction.
Company witness Mr. Darell T. Gerrard provides testiony with additional
details and technical information on the Populus to Termnal transmission
investment.
What investment related to the Populus to Terminal transmission line is
included in the revenue requirement of this rate case?
The estimated costof the Populus to Termnal transmission line to be placed in-
service in the test period of this rate case is approximately $802 millon. This line
is one of the first components of the Company's comprehensive plan related to
investment in the transmission system. The Populus to Termnal trnsmission line
is a new double-circuit 345 kilovolt ("kV") transmission line from the Populus
substation near Downey, Idaho to the Termal substation in Salt Lake City, Utah,
which wil be placed in service in two phases. The first phase from the Ben
Lomond substation (near Ogden, Uta) to the Termnal substation was placed in
service in March 2010, and the second phase from the Populus substation to the
Ben Lomond substation wil be in service by November 30,2010. The testimony
of Company witness Mr. Steven R. McDougal describes the revenue requirement
calculations associated with this transmission investment.
19 Overview of PacifCorp's Transmission System
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Please briefly describe PacifiCorp's transmission system.
PacifiCorp owns and operates approximately 15,800 miles of transmission lines
ranging from 46 kV to500 kV across multiple western states. As of December
31,2009, PacifiCorp's total-company net transmission plant in service was
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approximately $2.2 bilion. PacifiCorp is interconnected with more than 80
generation plants and 15 adjacent control areas at approximately 124 points of
interconnection. To provide electrc service to its retail and wholesale customers,
PacifiCorp owns or has interest in generation resources diectly interconnected to
its transmission system with a system peak capacity of approximately 12,131
MW. This generation capacity Ìncludes a diverse mix of resources including coal,
hydro, wind power, natural gas simple cycle and combined cycle combustion
turbines, and geothermaL.
Please describe the availabilty of exiting transmission capacity on the
system.
The Company's 2008 Integrated Resource Plan ("IRP"), which was filed with the
Idaho Public Utilties Commssion ("Commssion") in May 2009 and
acknowledged in September 2009, identifies the need for investment in major new
transmission facilities to provide ongoing reliability and to meet the forecast loads
ofPacifiCorp's customers. The IRP analysis is performed by evaluating loads
and resource requirements over a twenty-year period.
PacifiCorp's existing transmission system, as well as the transmission grid
across the western region, is severely constrained, and numerous regional study
groups have identified the pressing need for investment in new transmission
infrastrctu. These studies are described in more detail later in my testimony.
Additionally, new federal standards that mandate increased transmission
system reliabilty along with PacifiCorp' s recent operational experience requir
additional investments in PacifiCorp's transmission system to ensure the
738
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Company has the capabilty to provide reliable transmission service under
expected operating conditions, and to maintain the transmission system capacity
necessar to deliver network load service and contractual point-to-point
commtments.
Increasing PacifiCorp' s transmission capacity wil also provide the
opportnity for the Company to mae off-system energy purchases or sales,
which are used to reduce overall power supply costs. Lastly, additional
transmission capacity provides the Company added flexibilty in the location and
use of generating reserves and flexibilty to perform routine maintenance on
transmission lines with minimal risk, all of which reduce operating costs to
customers.
Please generally describe how PacifiCorp's transmision expansion plan
became a component of IRP.
As par of MEHC' s acquisition of PacifiCorp, the Company performed a review
of the IRP process. From that review, the Company determned there was a need
for a long-term transmission investment strtegy to support the long-term resource
needs of customers. Historically, IRPs were relatively silent on transmission
investments, assuming transmission would follow generation investments. Given
the long-term needs of customers and load growth, existing transmission system
constraints, the time required, and the challenges associated with designing,
permtting and constrcting transmission lines, transmission is now a key element
of the Company's IRP. This shift in focus is evidenced by the inclusion of
Energy Gateway in PacifiCorp's 2008 IRP.
739
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.1 Overvew of Energy Gateway Tranmission Expansion
2 Q.Please generaly describe Energy Gateway.
3 A.Energy Gateway is a comprehensive transmission plan based on takig immediate
4 actions while keeping long-term needs in focus. Energy Gateway wil enhance
5 reliabilty, reduce transmission system constraints and improve the flow of
6 electrcity to PacifiCorp's customers. The Energy Gateway plan is comprised of
7 eight interrelated and interdependent transmission segments as outlied in Exhibit
8 No. 33. The eight line segments withn Energy Gateway are grouped and labeled
9 as par of Gateway Central, Gateway West, Gateway South and the Westside.
10 The Populus to Termnal line segment is within Gateway Central. When fully
11 implemented, Energy Gateway wil traverse six states, numerous communities,.12 counties and significant areas of federally-admnistered lands and wil add
13 approximately 2,000 miles of new transmission lines to PacifiCorp's transmission
14 system. Due to the interconnected nature of PacifiCorp' s transmission network,
15 investments may be required at other facilities in order to maximize the
16 effectiveness and efficiency of the network. For Energy Gateway, the eight
17 identified transmission segments provide specific capabilties, but they also
18 support other transmission segments to enhance the benefits of Energy Gateway.
19 Q.Please desribe Gateway Central relative to the overall Energ Gateway
20 plan.
21 A.Gateway Central includes the Populus to Termnal, Mona to Oquirh and Oquirh
22 to Termal transmission lines that wil improve reliabilty and trnsfer capabilty
23 to the existing system and also establish the necessar electrcal interconnection.
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between Gateway West and Gateway South. The Gateway West and Gateway
South segments, when complete, wil be the first 500 kV lines to be installed in
Wyoming, southeast Idao and Uta. Gateway Central wil provide an essential
reliabilty backbone allowing Gateway West and Gateway South to operate at a
higher reliability and at an overall higher capacity than would otherwise be
possible without the Gateway Central interconnection. This investment wil not
only add incremental transmission capacity, but wil also strengthen PacifiCorp's
overall system while supporting futue generation resource development to
benefit all PacifiCorp customers.
As described earlier in my testimony, the Populus to Termnal
transmission segment is comprised of two smaller sections, which in total extend
135 miles from the new Populus substation near Downey, Idao, south to the
existing Termnal substation near the Salt Lake International Aiort west of Salt
Lake City, Utah. The Populus to Termnal trnsmission segment is a key element
of the Energy Gateway's Gateway Central. Populus to Termnal is designated as
"Segment B" within Gateway Central in Exhibit No. 33.
17 Populus to Terminal Transmission Investment
18 Q.
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Please describe the Populus to Terminal transmission investment in more
detail.
Exhibit No. 34 is a map of the Populus to Termnal trnsmission line segment.
Ben Lomond to Termnal is the southern section and is highlighted in red on the
map. Populus to Ben Lomond is highlighted in yellow, green and blue on the
map. Phase I from Ben Lomond to Termnal was the fist section of the Populus
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to Termnal line to be completed and became operational in March 2010. Phase II
from Populus to Ben Lomond is scheduled to be complete and in service by
November 30,2010.
Please describe the findings of the regional transmission studies related to
Energy Gateway and specificaly the Populus to Terminal segment
Over the past decade, numerous studies were completed documenting the need for
new transmission in the western United States. As early as 2002, the Deparment
of Energy National Transmission Grid Study identified the Wyoming-Idaho
interface as a major constrained interface. The study also found that under
optimal conditions, the Wyoming-Nortern Utah interface is congested during 50
percent or more of the hours during the year. 1
In 2004, the Rocky Mountain Ara Transmission Study reached simlar
conclusions and recommended expansion of the 345 kV transmission lines
connecting the Company's Bridger substation to points south and west as
critically needed improvements.2 In addition, the U.S. Deparent of Energy's
2006 National Electrc Transmission Congestion Study ("DOE Congestion
Study") identified several constrained transmission paths in the west as shown in
Exhibit No. 35, including lines used to deliver electricity from generation plants
in Wyoming to loadsin the west.3 Specifically, the DOE Congestion Study
.
1 National Transmission Grid Study atpp. 15, 18. A full copy of this report is available at
http://www.pi.energy.gov/documentsflransmissionGrd.pdf.
2 Rocky Mountain Area Ttansmission Study at Chapter 3-2, which shows the Bridger expansion as a
critical expansion area from Wyoming to Nortern Utah and Wyomig to Idaho. The full rert is available
at htt://psc.state.wy.us/tdocslsubregionaleports.htm.
3 See DOE Congestion Study at pp. 31-35. The trsmission constraints identifed in this study were
identifed by reviewing recent transmision studies such as those conducted by WECC and Seams Steering
Group-Western Interconnection. The full repor is available at
http://nietc.anl.gov Idocuments/docsiCongestion_Study _2006-9MB.pdf.
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ilustrated that expansion of the Bridger West transmission facility is critical for
relieving congestion from Wyoming to northern Utah, and Wyoming to Idaho.4
Similarly, the Western Interconnection 2006 Congestion Assessment
Study, which was issued by the DOE Western Congestion Analysis Task Force,
identified areas of congestion in the Rocky Mountain States and projected that
based on 2005 load and resource forecasts and a production model, many of the
paths associated with the varous segments of the Energy Gateway Project would
be heavily congested.5
Reports initiated by the Western Governors' Association ("WGA") also
show certain paths inPacifiCorp's service terrtory (including the Populus to
Termnal segment) as constrained.6
In addition, the DOE sponsored a study through Idaho National
Laboratories to assess the economic impact of not building transmission. While
the report focused on assessing the economic impact on the Pacific Northwest, it
also provides discussion and support for the "hub and spoke" design which is
similar to the Energy Gateway model for connecting resource areas to load. The
report also describes the interconnected natue of transmission as being
geographically dispersed, yet interdependent. 7
4 Such expansion is addresse by the Segment E porton of the Project.
5 A full copy of this study is available at htt://www.oe.energy.gov/DocumentsandMedial
DOE_Congestion_Study _2006_ Westem_Analysis.pdf.
6 The full report is available at http://www.westgov.org/wgalinitiatives/cdeacflransmissionReport-
fmal.pdf.
7 See The Cost of Not Building Transmission: Economic Impact of Propose Transmission Line Prjects
for the Pacifc Nortwest Economic Region. Full report is available at
http://www.pnwer.orglPortls/0IPesentations/2008%20summtlCost%200f%2Onot%20building%20trsm
ission.pdf.
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Existing NTTG sub-regional transmission planning studies, conducted in
accordance with the Federal Reguatory Energy Commssion's ("PERC") Order
890-A, show overall benefits to the region as a result of PacifiCorp' s proposed
Energy Gateway.
PacifiCorp filed for incentive rates with PERC on July 3, 2008, which is
analogous to a need determnation. FERC granted the Company incentive rate
treatment, and of equal importance, PERC issued a 4-0 decision stating:
(W)e find that PacifiCorp has adequately demonstrated that the
Project (with the exception of segment A) wil ensure reliabilty
and reduce trànsmission congestion... We find that segments B
through H of the Project would establish for the first time a
backbone of 500 kV transmission lines in PacifiCorp's Wyomig,
Idaho and Utah regions. This would provide a platform for
integrating and coordinating future regional and sub-regional
electrc transmission projects being considered in the Pacific
Northwest and the Intermountain West, connecting existing and
potential generation to loads in an effcient manner, thus reducing
the cost of delivered power. Also, the Petition cites the 2006 DOE
National Electric Transmission Congestion Study and the 2004
Rocky Mountain Area Transmission Study in stating that that
proposed Project wil reuce congestion or maintain reliabilty in
the Western Interconnection. Additionally, the project would
establish a direct link between PacifiCorp's east and west control
areas, providing numerous benefits including increasing transfer
capabilty, reducing the need for curtailments, and reducing
transmission congestion.8
.Commssioner Suedeen Kelly echoed PacifiCorp's Petition in her concurence
statig,
". . . while Segments Band C provide a varety of benefits when considered in
isolation, they also enable PacifCorp to achieve the planed transfer capabilty
8 PacifCor, 125 FERC l) 61,076 (2008) at p. 10, (Exhbit No. 36).
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rating of subsequent segments." 9 A complete copy of the report is provided as
Exhibit No. 36.
As noted in Exhibit 33, Segment B is Populus to Termnal and Segment C
is Mona to Oquirh.
What factors does the Company consider before building new tranmission?
The Company considers several factors before building new transmission
facilities including:
. Current and future forecasts for demand and energy required from existing
and new resources to new and existing loads. These considerations are
addressed in the Company's 2008 IRP including demand-side management
and energy conservation programs.
. Alternatives, including building local generation near load, and/or energy
market purchases.
. The Company's abilty to use existing land rights, existing rights-of-way, and
corrdors.
. The use of upgrades to increase operabilty and reliabilty of existing.
transmission lines and substations.
. The Company's ability to maximize the capacity and capabilties of existing
facilities.
Because prudent transmission investments are typically large scale to maxize
efficiencies and gain economies of scale, the benefits are realized over the long
term.
9 Exhibit No. 36, p. 25.
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Once the decision is made to invest in new transmission, what is the process
for getting it built?
Once the decision is made to invest in new transmission, capacity sizing of the
transmission line is taen into consideration to balance curent and futue needs.
Constructing long, linear facilities such as trnsmission lines requires a long lead
time and is an extensive process. Siting, permtting and constrcting new
transmission can tae up to seven years and potentially involves acquirng new
rights-of-way and permts from local, state and federal agencies. Maximizing the
transmission capacity placed in approved corrdors is a critical consideration to
minimize disruption to communities and landowners. The Company also
considers design and routing to minimize the environmental, visual and human
impacts.
What land rights and permits were acquired for Populus to Termnal?
The Company holds all of the necessar land rights, either in easements or fee
ownership, between the Populus substation and the Termal substation.
However, the Company was required to secure numerous permts and approvals
from federal and state entities, such as:
. The U.S. Ary Corps of Engineers required permts for constrction withi
jurisdictional wetlands.
. The Federal Aviation Admnistration required aviation permts for
constrction of Populus to Termnal near Salt Lake International Airort.
. The Uta and Idaho Departments of Transporttion required permts from
railroad companies for roadway crossings, overhangs and easements.
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. The U.S. Bureau of Reclamtion required a crossing permt for the Ogden-
Brigham canal.
. The Utah Deparent of Wildlife Resources requird a permt for crossing
Wildlife and Waterfowl Management Areas, with a separate agreèment
required for constrction with the Legacy Natue Preserve.
. The U.S. Fish & Wildlie Service, U.S. Forest Service and Utah State
Historical Preservation Office also required varous wildlife & environmental
habitat permts.
What permits were required by local governmental authorities for the
construction of Populus to Terminal?
The Company holds a franchise agreement with each municipality and county
within the route that grants the necessar rights for the constrction of the
Populus to Termnal transmission line. In addition, the Company secured
conditional use and/or special use permts from all Idaho and Utah cities and
counties, based on each community's requirments. The Uta Public Service
Commssion ("Utah Commssion ") and the Idao Public Utilties Commssion
("Idaho Commssion") issued Certificates of Public Convenience and Necessity in
2008. The Idaho Commssion Order states:
Thus, Staff believes that the necessity of the Project should be
viewed in conjunction with energy resources that are constructed,
under way or planned. PacifiCorp elected to undergo a
transmission upgrade as par of its preferred resource portfolio of
an additional 2,000 MWs of renewable resources by 2013 in the
Company's 2007 IRP. A signifcant portion of these renewable
resources wil be located in Wyoming. Staf then listed more than
500 MW s of renewable resources that are either under constrction
or in the final stage of development. In response to a Staff data
request, PacifiCorp provided four alternatives that it rejected
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because the Company did not believe that these would provide
sufficient capacity for the new resources. Staf agreed that the
Project was necessar in order for the Company to continue to
provide reliable service from these new resources to growing load
centers. 10
In its Order, the Utah Commssion noted several paries concurrd with the need,
including the Division of Public Utilties:
The Division states it has examined underlying informtion upon
which a need for these additional transmission facilities may be
found and concludes it supports RMP's decision to build the
Transmission Line and confirms RMP's planned integration and
operation of the line with future utity operations and activities.
The Division agrees with RMP's conclusions that there is a nee
for the Transmission Line and the Company's futue utility service
wil be more reliable and efficient with the Transmission Line's
addition. 11
Please describe the bidding process the Company used to award contracts for
the construction of the new transmision.
The Company initiated a competitive tendering process to receive blind, sealed
bids for the project work scope to be delivered on a tuey, fixed-price,
guaranteed completion-date basis using an engineer; procure and construct form
of contracting. The competitive tendering process began in October 2007 and
provided two separate blind, sealed bidding opportnities. All bid responses were
due for submittal in May 2008 and again in July 2008 after the Company provided
additional informtion to bidders allowing a refinement of previously submitted
design solutions, and term and conditions, including price. The Company
10 In the Matter of the Application of Rocky Mountain Power for a Cerficate of Public Convenience and
Necessity Authoriing Constrction of the Populus-to- Terminal 345 KV Transmision Line Project, Case
No. PAC-E-08-03, Order No. 30657 (October 10,2008) atpp. 3-4.
1 1 In the Matter of the Application of Rocky Mountain Power for a Certficate of Public Convenience and
Necessity Authoriing Constrction of the Populus to Termnal 345 KV Trasmision Line Prject, Doket
No. 08-035-42, Report and Orer Grnting Certficate and Certficate of Public Need and Necessity,
(September 4, 2008) at p. 3.
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received and evaluated thee qualified bids resultig from the May 2008 proposal
submissions. Durg the evaluation period one of the bidders withdrew its
paricipation. The Company received two competig proposals in July 2008 with
qualified prices of $609 millon and $528 millon, respectively. After extensive
evaluations of bidder proposals and review of exceptions to work scope and base
terms and conditions from each bid proposal, the Company ultimately awarded
the contract in October 2008, details of which are provided in Mr; Gerrard's diect
testimony. The scope of the bidding process included the Populus to Termnal
segment, which includes the sections outlined in Exhibit 34. The bid process is
described in more detail in Mr. Gerrard's testimony.
Why did the Company use the engineer, procure and construct approach?
The engineer, procure and constrct ("EPC") solicitation isa common form of
contracting for large constrction projects like the Populus to Termnal
transmission segment and is regarded as a prudent approach for cost control and
managing design, procurement and constrction risks. This approach: (1)
provides certainty relative to schedule and cost outcomes for the benefit of
customers; (2) caps potential cost escalations where possible based upon the
occurrence of defined risks; and (3) ensures more timely delivery to support
system needs and transmission reliabilty.
Please explain what you mean concerning capping costs based upon the
occurrence of identifed risks.
The fixed-price EPC approach has minimal provisions for cost and schedule
varances. Where cost and schedule variances were not included in the fixed price
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for certain contingent aspects of the work scope, these items were identified as
risk items and a contingent capped price and schedule allowance was agreed upon
prior to contract execution should any of these risk items materialize. Contingent
risk items were limited to defined occurrences such as weather delays,
environmental impacts and sub-surface ground conditions.
How wil the Populus to Terminal transmision line benefit PacifiCorp
customers?
The Populus to Termal transmission line and subsequent investments within
Energy Gateway satisfy multiple objectives for effciently operating a six-state
transmission system in the long term. The initial benefit to PacifiCorp customers
is a significant investment to enhance reliabilty-and improve transfer capabilty
within the existing system. In the futue, this investment wil also provide
benefits of incremental capacity to deliver generation resources within the
Company's 2008 IRP.
Reliabilty is fundamental to effectively and efficiently managing the
Company's six-state transmission system. As a federally-regulated transmission
provider, the Company must comply with reliabilty standards mandated by
FERC though the Nort American Electrc Reliabilty Corporation ("NERC")
and WECC. By meeting these standards the Company continues to maintain a
stable and reliable system durg a varety of operating conditions, which
minimizes potential outages to all customers and financial impacts of having to
deliver higher-cost resources if required. Populus to Termnal increases overall
reliabilty, benefiting all PacifiCorp customers.
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Populus to Termnal also increases transfer capabilty from nort to south
and south to north across the Company's transmission system. By doing so, the
Company addresses a key constraint (Path C), 'meets an MEHC transaction
commtment and improves the Company's abilty to import and export lower-cost
resources depending on seasonal needs and operating conditions. The benefit to
all PacifiCorp customers is the abilty of the Company to, use the least-cost
dispatch of resources to serve loads and manage power costs by sellng excess
energy off-system or importing lower-cost market energy to serve load. Also, by
providing incrementa transmission capacity though this trnsmission segment,
the Company has more flexibilty in locating reserves on PacifiCorp-owned
generation, and mang full use of the Nortwest Power Pool reserve-sharng
program. This program allows the Company to cover reserve requirements
without having to build additional generation. Increasing the import capabilty
allows better access to those reserves, thereby reducing costs for all customers.
Reliabilty and transfer capabilty provide benefits based on the existing system.
Populus to Termnal also establishes incremental capacity to provide long-
term benefits to customers. Populus to Termnal is the first step within the
Energy Gateway strtegy to access resources at their source of production.
Benefits wil accrue to energy consumers and energy producers by allowing
economic resources, new and existing, to be developed and delivered across the
Company's service terrtory.
.
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1 MEHC Transaction Commitments
2 Q. Did MEHC and PacifiCorp make specific commitments related to investment
3 in PacifiCorp's transmission system as part of the acquisition approval
4 process?
5 A.Yes. The regulatory commssions in all six states in the Company's service
6 terrtory approved the Company's capita commtments specifcally in
7 transmission and distribution as par of the acquisition of the Company by
8 MEHC. MEHC made specific commtments and developed plans for a significant
9 capital expansion program across the system to support futue demands and
10 growt of its customers. As par of the acquisition approval process, MEHC
11 commtted to increase transfer capacity on a constrined path known as Path C by
300 MW.12 Populus to Termal improves the capacity on Path C and has a
planned increase in transfer capacity of 1,400 MW when combined with other
segments of Energy Gateway. As such, the Populus to Termnal transmission
segment wil significantly improve a point of constraint on the system that
currently affects numerous transmission customers, wil strengthen reliabilty and
wil enable the Company to achieve the planned transfer capabilty rating of
subsequent Energy Gateway segments.
Conclusion
Q. Please summarize your conclusions.
A. New transmission is essential to enhance trnsmission system reliabilty, provide
capacity to integrate resources for the long-term benefit of customers and meet
load growth. Populus to Termnal is the first step to increase transmission
12 See Order No. 29998 at Page 6 (Commtment No. 34).
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capacity within PacifiCorp's six-state transmission system. This investment and
subsequent investments in Energy Gateway are prudent, cost effective and
beneficial to customers.
Is the inclusion of Populus to Terminal in Idaho rates in the public interest
and if so, why?
Yes. The Populus to Termnal and subsequent investments within Energy
Gateway satisfy multiple objectives for efficiently operating a six-state
transmission system. The initial benefit to PacifiCorp' s customers is enhanced
reliabilty and improved transfer capabilty within the existig system. In the
futue, it wil also provide incremental capacity for delivery of resources within
the Company's 2008 IRP, which is a key to unlocking rich resource hubs for the
benefit of all PacifiCorp customers and ultimately the western interconnect.
Does this conclude your direct testimony?
Yes.
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1 (The following proceedings were had in
2 open hearing.)
3 BY MR. HICKEY: Now, you were here yesterday,Q.
4 were you not, Mr. Gerrard, when Mr. Walj e was examined over the
5 course of the morning and some of the afternoon?
6 A.Yes, I was present.
7 And do you recall that there were several areasQ.
8 of examination relating to the Populus to Terminal investment
9 and transmission resources that is a part of the revenue
10 requirement in this case?
11 A.Yes.
12 And were some of those issues referred to you orQ.
13 deferred to you, Mr. Gerrard?
14 Yes, I noted four issues that Rich asked me toA.
15 speak to.
16 Okay, let's take those up. Could you pleaseQ.
17 identify the first of those issues, address it, please?
18 Certainly. Rich -- Rich Walj e left four itemsA.
19 for me to discuss in further detail today. His testimony was
20 accurate, in my opinion. I think I can add a little bit more
21 clarity and information to those for this Commission, so I'll
22 do that as briefly as I know how to do.
23 The first one is around the status of Populus to
24 Terminal in our rate case proceedings in all of the states.
25 Rich did mention accurately all of the states. He failed to
754
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GERRARD ( Di)
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1 mention the Pacific-side states of Oregon and California. And
2 in Oregon, the Populus-Terminal proj ect has been 100 percent
3 accepted in rates and a all -party Settlement is in place. I
4 believe we're still pending the Order from the Commission in
5 Oregon.
6 The same is in California. The Populus-Terminal
7 proj ect has been included into California rates 100 percent and
8 that proceeding is closed. I don't believe we have an Order,
9 but that's subj ect to check. I didn't have an answer to that.
10 Q.Okay. And how about the second area that was
11 deferred?
12 A.The second area -- and I'd like to address the
13 next three. There was an area on the FERC incentive rate
14 filing. There was some questions from the Commissioners --
15 Mr. Redford, I believe -- of Rich about how we do planning,
16 continued planning, replanning, and assessing not only Gateway
17 but other proj ects, and how we go about that and the prudency
18 of doing that. Like to talk about that a little bit.
19 And then the last item I'd like to talk about is
20 some discussion about the changes in the footprint of Gateway.
21 There were two exhibits produced yesterday with differing
22 footprints. I like to shed the light on why that's changing
23 and how we arrived at where we are today.
24 Q.Yes.
25 A.So those are the three other items left that I
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1 would like to discuss.
2 Q.Okay. Well, let's take up the second of those
3 items and please discuss it, Mr. Gerrard.
4 A.Okay. The second item that I'd like to discuss
5 is in Exhibit 30 -- check on the exhibit right here. I believe
6 Mr. Budge was talking to this yesterday, is Cupparo' s -- John
7 Cupparo' s Exhibit No. 36. This is the F-E-R-C -- Federal
8 Energy Regulatory Commission -- exhibit on incentive rate
9 Orders that was issued to PacifiCorp. And the question that
10 was being posed to Rich was the treatment of abandoned costs
11 for the proj ect, and those are covered the verbiage is
12 covered on page 4 of this Order.
13 And PacifiCorp was allowed in this rate case to
14 recover all prudently-incurred costs in the event of project
15 cancellation or abandonment that were -- those costs were
16 outside of PacifiCorp' s control.
17 Q.Okay, I want to just slow you down a little bit
18 here, please, Mr. Gerrard, and I'm looking at Exhibit 36 to
19 Mr. Cupparo's testimony, and page 4 of the Order of 29 pages is
20 the page you are specifically referring to, sir?
A.I am, Paragraph 8.
Q.Okay. Under "Requested Incentives"?
A.That is correct.
Q.Well, let's just take a minute here. Am I
correct that the requested incentives would apply at the
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1 F-E-R-C level and potentially to wholesale customers?
2 A.Yes, that's correct, and that was -- I was going
3 to get to that second point, Mr. Hickey. Any incentive rate
4 revenues that were a result of Gateway would be credited back
5 to the retail customers of the states that we serve, and that's
6 further stated on page 5 of 29 where it states PacifiCorp will
7 compensate retail customers by crediting all
8 transmission-related revenues, inclusive of any incentives
9 granted by the Commission. So that's where I was referring to.
10 Abandonment costs are held at the Federal level,
11 and our open access transmission tariff and incentive rates
12 only apply to the portions of Gateway that don't serve our
13 retail customers.
14 Q.Are there any other comments that you wish to
15 make regarding Exhibit 36?
16 A.I do not have any more.
17 Q.Okay. Does that take care of the second issue
18 that was deferred to you, sir?
19 A.Yes, it does.
20 Q.Let's continue then to the third issue, and
21 remind us what it was and what you would like to say about it.
22 A.Yeah, the third issue was in response to the
23 Company's ability to plan transmission in this case, and
24 resources for that matter, and the need or the desire to -- the
25 requirements, I should say to review those plans on a
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1 regular basis, and so I thought I would speak to that.
2 There are two statutory requirements that the
3 Company has in regards to planning its facilities and reviewing
4 those plans, and I covered those in my direct testimony on
5 pages -- on my direct testimony on page 5. And the first of
6 those regulatory requirements is that PacifiCorp, under Federal
7 registration, is a registered transmission provider with an
8 open-access tariff. That tariff, I think, not to get into it
9 because people are probably familiar with it, defines the rules
10 in which people engage us to buy transmission service.
11 As part of that open-access tariff, Section 28
12 says that the Company will plan, construct, operate, and
13 maintain an adequate transmission system to serve its
14 customers. So we are obligated to do that under our tariff and
15 we do do that.
16 In Section 31 of that tariff, we're also
17 obligated to collect a annual load and resource plan from all
18 of our network customers; not just Rocky Mountain Power and
19 Pacific Power, but all of the customers we serve on our
20 transmission system, wholesale or retail. So that means
21 Western Power Administration, that means BPA -- Bonneville
22 Power Administration -- that means UAMPS, Deseret. All of
23 those companies provide us an annual L&R -- load and
24 resource -- plan, which we review annually and we adjust our
25 transmission plans to serve those.
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1 So those are statutory obligations under the
2 tariff that compel us to re-look at our plans, including
3 Gateway, annually.
4 The second area that I'd like to touch on quickly
5 is the NERC standards. There are over 125 new NERC mandatory
6 regulatory standards. I see Marsha's nodding, Madam
7 Commissioner is nodding. We're bound by those and I've
8 mentioned those in my testimony on page -- pages 5 and 6, and I
9 listed all of those that are applicable today under the Data
10 Requests from the Idaho PUC under Data Request 208, so you can
11 refer to those. The most important ones there are transmission
12 planning standards, of which there are four, and those tell me,
13 as a system planner the levels of reliability, redundancy, and
14 system adequacy, the minimum levels that I need to provide to
15 these customers under my tariff.
16 Two key points in that: Requirement 1.1 of the
17 national standards state that I must plan a transmission system
18 that can handle the expected demand of my customers under all
19 conditions. Doesn't say "some conditions" or when I feel like
20 it; it says under "all conditions." And that's the first
21 requirement in that standard.
22 Another important requirement in that standard is
23 it says we will do an annual transmission assessment on our
24 entire transmission grid above 100 kV, and through that
25 assessment -- and they give you a minimum of ten years, longer
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1 if you have to -- we do an annual assessment, we identify any
2 deficiencies or potential violations of these standards, and if
3 we find those we have to do mitigation to make sure those
4 violations don't occur. That could be capital proj ects or
5 operational.
6 The last part of that standard in Section 2.1,
7 which I think is very important for this Commission to be aware
8 of and why we're pursuing our proj ects vigorously, is that that
9 standard says that we need to pursue our mitigation plans and
10 our action plans with sufficient lead time and sufficient
11 prudency that we don't find ourselves in a violation for lack
12 of planning. That's basically what that says.
13 Gateway -- so we have an annual assessment on
14 file with NERC. We have that annual assessment on file with
15 W-E-C-C, which is the Western Electric Coordinating Council.
16 Sorry for the acronym. That plan, a large part of that, is
17 Gateway. Wi thout Gateway and its elements, we would not be in
18 compliance with that standard.
19 The last thing, Mr. Hickey, I'd like to say about
20 that standard is the stakes went up in June 2007 when NERC was
21 allowed to -- or FERC, for that matter -- to allow fines and
22 sanctions for noncompliance with these standards. And I think
23 the risk to our customers and our Company by noncompliance is
24 that if the planning isn't done adequately, appropriately, the
25 deficiencies we have move into the operating horizon, which
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1 means daily operation and the system can be put at risk. The
2 fines that can be levied by NERC for operational issues in the
3 daily operations are up to a million dollars a day for every
4 day you're in noncompliance. That's the extreme one. But as
5 we move, lack of planning translates into daily operations, we
6 up the risks to our customers and financially to the Company.
7 Q. SO just as a segue then, Mr. Gerrard, to your
8 next area, is it a fair observation that there are regulatory
9 requirements on the Company, as a provider of interstate
10 transmission services, that require it to meet anticipated load
11 demands of the customer?
12 A.That is correct under all expected conditions.
13 Q.And that there are also penal ties and fines and
14 compliance standards upon the Company, as an interstate
15 transmission provider, that help ensure that those customer
16 loads are effectively and efficiently delivered across the
17 system. Is that true?
18 A.That is true. I would add to that not only are
19 the loads served, but the PacifiCorp' s transmission system
20 doesn't disrupt its interconnected parties. That's as big of a
21 requirement.
22 Q.So if we kind of move out of this Federal
23 regulatory environment and get to a board table or a
24 decision-making table at PacifiCorp, are these the
25 circumstances that were surrounding the Company's decision to
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1 build Energy Gateway?
2 A.Energy Gateway was proposed in 2007 just before
3 these stanòards were in place, but Energy Gateway is a big part
4 of complying with those. So the genesis was before, but they
5 are part of our standards.
6 Q.Okay. Now, there was talk about how the
7 footprint, if you will, of Energy Gateway has changed, and
8 Mr. Budge had a couple of exhibits that showed different maps,
9 different areas of the West that Energy Gateway South actually
10 ran to. Do you recall those exhibits?
11 A.I do. One was Exhibit No. 33 for Mr. Cupparo.
12 Q.And I have the ones that were marked sequentially
13 for Monsanto.
14 A.Yeah, that one I didn't get the number on.
15 One was Exhibit 239. It actually -- I'm holdingQ.
16 it for you, Darrell, if you have it; if you don't, I'll bring
17 it up to you.
18 A.I do not have that in front of me.
19 Q.And the other was an Exhibit 240.
20 MR. HICKEY: May I approach the witness, please?
21 COMMISSIONER SMITH: Yes, you may.
Q.BY MR. HICKEY: Handing you first what was
23 recei veò yesterday or marked yesterday as Exhibit 240. Does
25
24 that have the original configuration of the Energy Gateway
project?
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1 A.That exhibit is the original footprint, yes.
2 Q.And as shorthand way of identifying it, that's
3 where the
4 COMMISSIONER SMITH: Mr. Hickey, did you mean 240
5 or did you mean 239?
6 MR. HICKEY: I meant 239. If I said "240," I
7 misspoke. Thank you, Chairman.
8 Q.BY MR. HICKEY: So, Exhibit 239 would show us
9 where the original Gateway South line was running to Crystal,
10 Nevada?
11 A.Yes.
12 Q.The specific question was were you building that
13 line in order to access the California market?
14 A.We were not.
15 Q.Why did the line originally show Crystal, Nevada,
16 as the most western and southern terminus on that segment?
17 A.In our integrated resource plan in 2007, there
18 was a requirement to import up to 600 megawatts into Utah from
19 Crystal to serve our customers.
20 Q.Okay. Then I'm going to hand you Exhibit 240,
21 which shows a different footprint for Energy Gateway. Am I
22 correct that there is a difference between the two maps in
23 those two exhibits?
24
25
A.There are differences, yes.
Q.Okay. Tell us why Exhibit 240 depicts a
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21
i different proj ect than the one you just described.
2 A.And you're referring to Gateway South, I assume.
3 Q.Yes.
4 A.The Exhibit 240 shows a different configuration
5 for Gateway because the purchase of the requirement for 600
6 megawatts to be imported from Crystal to Utah was no longer in
7 the IRP -- integrated resource plan -- from Crystal. That
8 requirement changed.
9 Q.So in addition to those observations, are there
10 any other points that you would like to make regarding the
11 configuration of either Gateway South or the Energy Gateway
12 project?
13 A.Yes, I would, if I may.
14 Q.Please.
15 A.The other, I'm referring to Exhibit 240 now for
16 those folks who have this. There are dashed lines that show a
17 line from Hemingway, Idaho, to Captain Jack, which was named
18 three or four different things yesterday but correctly it is
19 Captain Jack, for the record.
Q.We hope he's a happy captain.
A.Yeah. There's also a dashed line from Hemingway
22 to Boardman which is up near the Columbia River in Oregon, and
23 then there's another dashed line that goes over to a place
24 called Bethel, Oregon. These are projects under review for
25 let me back up for a minute.
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1 The Hemingway to Captain Jack line, it was on the
2 original exhibit that I showed you as designated as Section H.
3 At the time we announced Gateway in 2007 and I architected it,
4 the dashed line you see on Exhibit 240 from Hemingway to
5 Boardman did not exist. That's an Idaho Power power proj ect
6 that Idaho has proposed subsequent to Gateway. I think it came
7 out in 2008. And so we're now working jointly with Idaho to
8 see if we can partner up, if you will, or share that project to
9 lower costs to both of our customers. We have a Memorandum of
10 Understanding; we're working closely with Idaho on that. So
11 that can be an option to the Hemingway to Captain Jack.
12 The second dashed line from Boardman to Bethel is
13 another line that's in the regional planning process by
14 Portland General Electric, and we are discussing with Portland
15 General the ability to share in the construction of that
16 proj ect to lower our costs to our customers for that.
17 Q.Let me just try to digest some of this with you,
18 because there's a lot here, Mr. Gerrard. Are you telling us
19 that even though the Company arguably could have built the
20 entire system itself , it was looking to share portions of this
21 to reduce costs?
22 A.Yes, we were.
23 Q.Who's the beneficiary of that cost savings?
24 A.That would come back to our OATT customers under
25 our tariff and our retail customers through that tariff.
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1 Q.How many partnerships do you expect will develop
2 wi th other utili ties in order to avoid some of these costs?
3 A.I would say we're actively participating in two,
4 and my hope would be that at least two of those come to
5 frui tion. I think there's a good likelihood, if you want my
6 opinion.
7 Q.Please continue.
8 A.Okay. I think -- let me check my notes here real
9 quick.
10 I think that's all that I had to say about the
11 footprint of Gateway. Well, I did have one more point: On
12 Exhibit 249, which was the original Gateway footprint, the
13 Company was very active --
14 COMMISSIONER SMITH: Excuse me. 239?
15 THE WITNESS: I'm sorry. Pardon me. 239. Got
16 too many numbers here. Excuse me. 239, which was the original
17 Gateway proj ect.
18 At the time this was architected and a few years
19 later, there was a large interest -- I'll call ita large
20 groundswell -- in increasing the size of these transmission
21 lines for several reasons:
22 One, to take into account or take advantage of
23 economies of scale when we build these large infrastructures.
24 There was interest in reducing the number of new
25 corridors that we had to have and to maximize the amount of
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1 capaci ty that we put down these new corridors to minimize
2 environmental impacts , community contacts, and to lower the
3 cost.
4 At the time we announced Gateway, just so you
5 understand how we evolved, we announced Gateway and we received
6 over 13,000 megawatts, 13 gigawatts, of transmission requests
7 into our open-access tariff queue to process for people who are
8 interested in participating in Gateway. So we were listening
9 to not only the governors of the states because they were
10 interested -- most of them -- in I'll call it "supersizing"
11 even though the word I don't care for much but it's used a lot,
12 to make these proj ects as large --
13 COMMISSIONER SMITH: It's changed now.
14 THE WITNESS: Okay. Thank you.
15 COMMISSIONER SMITH: "Rightsizing. "
16 THE WITNESS: Oh, okay.
17 (Laughter. )
18 THE WITNESS: I will get to "rightsizing"
19 momentarily here, believe me.
20 So, we were listening. And when we architected
21 Gateway, we made it so we could actually double-circuit
22 portions of this and double its capacity if third parties
23 wanted to pay for it.
24 So we spent the next two years -- and I'm
25 summarizing the end here -- we spent the next year and a half
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1 or so working through all of those 13,000 or so transmission
2 requests. We put contracts in front of third-party requesters
3 to participate and finance Gateway, and they were declined. No
4 one was able to make a business well, they all have their
5 own decisions, but they weren't in a position to participate in
6 Gateway.
7 So, where we are with the latest map, which is
8 Exhibit 240, is we're building half of Gateway, which is what
9 is needed for our retail customers and to serve our loads. We
10 are not building to markets or for third parties at this point.
11 Q.BY MR. HICKEY: Do you believe that the facility
12 is used and useful as it is now built, the Populus to Terminal
13 segment of that proj ect?
14 A.Yes, I do.
15 Q.Why?
16 I would like to turn to my Exhibit No. 65, and ifA.
17 it's okay with the Commission, I guess I've got -- my
18 experience has taught me that using some visuals here helps
19 with some of the more technical aspects of this, so I made some
20 blowup sizes of these exhibits, if that
MR. HICKEY: With your indulgence, Madam Chair, I
22 think Mr. Gerrard
23 THE WITNESS: Yeah, I would ask you if that would
24 be beneficial. Sometimes it helps to walk through those. I
25 don't intend to do a technical deep dive on you.
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1 COMMISSIONER SMITH: We don't want a technical
2 deep dive, and we do have the exhibits in front of us.
3 THE WITNESS: Okay. Let me
4 COMMISSIONER SMITH: If you think a larger view
5 would somehow enhance the discussion, I'm not opposed.
6 THE WITNESS: Let me try it with the exhibits,
7 and then if that doesn't --
8 MR. HICKEY: I think I heard the Chair say she
9 wasn't opposed to it if the larger view added to the dialogue.
10 I think --
11 COMMISSIONER SMITH: Will that make it go faster?
12 THE WITNESS: I think it may, yes.
13 (Laughter. )
14 THE WITNESS: So I would ask my colleague Dan
15 here to put up the -- yeah, the first, that one would be fine.
16 This is
17 COMMISSIONER SMITH: So, for the purposes of the
18 record, let's just reflect that the figures being displayed are
19 exhibits that parties have, Exhibit 65, page 1 and 2.
20 Q.BY MR. HICKEY: Yes. And, Darrell, when you
21 refer to the blowups, please call them by the number that
22 they're assigned in your testimony.
23 A.I'LL do that.
24 Okay, if I may, it was answering the question
25 from Mr. Hickey as why I am of the opinion this proj ect
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1 Populus-Terminal is used and useful, and the first point I
2 would make on that is the proj ect is in service, it is
3 electrified. It was put into service in November of this year,
4 on the 19th. It is in service.
5 The capacity of the proj ect has been called into
6 question, and so I'd like to demonstrate the used and
7 usefulness of the proj ect with the following charts that you
8 have in front of you. And, again, I'm referring to Exhibit 66,
9 and there's two figures there: There's Figure 1 and Figure 2.
10 COMMISSIONER SMITH: I think it's 65.
11 THE WITNESS: Oh, excuse me. Yeah. I'll get
12 this right. It is 65. Thank you, Madam Chairman. And there
13 are two figures: Figure 1 and Figure 2.
14 What I've put in front of you here is this is an
15 operating nomogram, an operating requirement out of our grid
16 operations center, and they're responsible for making sure that
17 the grid is scheduled in advance and it is operated wi thin the
18 limi ts that we're allowed under W-E-C-C. So to operate a
19 proj ect like Gateway, we have to obtain a rating; I call ita
20 license. It's a rating to interconnect and operate reliably,
21 and there are limits set on the system when we do that.
22 This is the current operating nomogram for
23 Path C. Path C is the only large commercial transmission path
24 between Idaho and Northern Utah. That path has had a number of
25 disturbance events and reliability issues that I have covered
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1 in my testimony in quite a bit of detail, and the path capacity
2 has been reduced over time significantly.
3 So as it currently sits, Path C has a firm
4 transmission capaçi ty in the southbound direction, which is
5 shown on this line right here. This is Line A, and there's a
6 li ttle dot there. That transmission capacity firm is at 575
7 megawatts.
8 Q.BY MR. HICKEY: And for the benefit of the
9 record, you're on Figure 1 on Exhibit 65, Mr. Gerrard, and
10 you'll need to continue to make those references.
11 Okay. I am on Figure 1 of Exhibit 65.A.
12 So, our grid operators now have to limit the
13 capacity of Path C to 575 megawatts firm. That means we cannot
14 enter into long-term firm contracts or short-term firm
15 contracts above that, because they're subj ect to curtailment.
16 It's a nonfirm product.
17 Okay, when we add Gateway to that, our Gateway
18 project was rated at a planned capacity of 1,400 megawatts, and
19 that's a pretty simple industry standard number of 700
20 megawatts per line. When you add that to -- when we place
21 Populus to Terminal into service, the capacity of this path
22 goes up to 1,600 megawatts.
23 The other thing I would say about Figure 1 in
24 Exhibi t 65 is that the capacity -- the firm capacity that we
25 can provide on Path C is a function of the ambient temperature
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1 and it's a function of the Southeast Idaho load. That's why
2 you see a complex operating arrangement. It's very difficult
3 to manage, but it's subj ect to those parameters what its
4 capaci ty is.
5 With the addition of Populus-Terminal, that new
6 capacity again goes to 1,600 megawatts, and I've shown that as
7 a straight line on Figure 2. That's a firm capacity. We're no
8 longer dependent on temperature -- ambient temperature -- and
9 we're no longer subj ect to the size of the Southeast Idaho
10 loads. In that regard, I've said in my testimony on -- in my
11 rebuttal testimony on page 14 that the contribution to Path C
12 is about a thousand -- it's actually 1,040 megawatts of
13 capacity increase, which is 73 percent of the 1,400 megawatt
14 planned capacity of Gateway.
15 And I share that number as there was claims by
16 the Intervenor, I believe Mr. Lobb and Mr. Peseau, that
17 Mr. Lobb indicated about 24 percent of the project capacity was
18 going to be used. That is incorrect. It's 73 percent in the
19 southbound direction.
20 And I believe Mr. Peseau said that a large
21 portion of Gateway would be not useful in its initial going in
22 service, and that is not true.
23 What is the additional part is that the
24 remaining capacity of Populus to Terminal will be used, a
25 portion of it, when Gateway West is built and interconnected,
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1 and the remainder of the 1,400 will come in when Gateway South
2 is connected, and I've covered that in my testimony.
3 Q.Snre, and that's already into the record. I have
4 just one final question for you unless there was anything else
5 that you had, Mr. Gerrard.
6 A.No, I don't believe so.
7 Q.Okay. You're also responding to the rebuttal --
8 or, answer and surrebuttal testimony of Mr. Falkenberg. Isn't
9 that true?
10 A.Yes, I am.
11 And, actually, I think this was inQ.
12 Mr. Falkenberg's answer testimony, Intervenor testimony. He
13 was raising issues, among others, for adj ustments to net power
14 costs, and one of those related to line losses. Is that
15 true?
16 A.That is true.
17 Just to frame the issue in hopes of helping theQ.
18 Commission and the parties, what was the proposed adjustment
19 and what is your response to it?
20 Mr. Falkenberg proposed in Table 1 of hisA.
21 testimony on page 3 an adjustment for line loss savings, a
22 revenue reduction based on line loss savings, for this specific
23 project, and
24 Meaning Populus to Terminal?Q.
25 Meaning Populus-Terminal, yes, that's correct,A.
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1 just for this individual segment of Populus.
2 I don't believe that the assumptions, the
3 analysis, or the data that Mr. Falkenberg has used is a
4 reasonable basis for determining the energy -- or, the energy
5 loss savings impacts to our system based on Populus-Terminal,
6 and I think if you -- I know if you follow his logic and his
7 analysis a little further, it sets the precedent for our
8 Company and for this Commission that we would consider
9 indi vidual energy loss adj ustments for every transmission and
10 distribution asset that's added to the system or removed. And
11 I would recommend or suggest to this Commission that that's not
12 practical nor feasible to do that, it's very complex, and that
13 the actual power system losses occurring are not reflected by
14 looking at each proj ect individually.
15 Another point I would make is that Mr. Falkenberg
16 used a discrete energy demand number that he obtained from a
17 Data Request, Data Request 66.2 of the Idaho Data Requests.
18 And he used that discrete energy demand quantity as a one-hour
19 number -- it was for one hour of 80,760 hours of the year --
20 and extrapolated that into a energy loss savings calculation
21 that was supposed to I believe he thought it was supposed to
22 recogni ze the energy the energy loss savings of this proj ect
23 over its lifetime, and that is not correct.
24 The other thing I would point out is that in
25 Mr. Falkenberg's testimony on page 4, he refers to that Data
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1 Request; and I actually wrote that Data Request and said that
2 the formula that he was using to do his calculation was not
3 applicable to an interconnected transmission system. It is
4 applicable to a single transmission line operating in
5 isolation. And I recommended that that was not appropriate.
6 He did recognize that in his testimony that it was not
7 appropriate for an interconnected system, but went on to use it
8 in his calculation for some reason.
9 Q.Does that near the conclusion of your surreaction
10 to the rebuttal testimony?
11 A.The last point I would like to make is a
12 recommendation that we continue, as our Company does, to do
13 periodic system-wide loss analyses to determine our system loss
14 factors, and that those are part of operating -- those go in as
15 part of our operating costs in our general rate increase.
16 They're done on a system-wide basis. We will be performing one
17 in 2011 for our FERC rate case that we're preparing for.
18 Thank you, Mr. Gerrard. Does that conclude theQ.
19 additional items that you intended to address?
20 Check my notes here. I believe it does.A.
21 Yes, I think we have hit them.
22 MR. HICKEY: Madam Chair, Mr. Gerrard's available
23 for cross-examination.
24 COMMISSIONER SMITH: Thank you very much.
25 Mr. Otto.
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1 MR. OTTO: Thank you. I do have just a few
2 questions.
3
4 CROSS-EXAMINATION
5
6 BY MR. OTTO:
7 Q.Mr. Gerrard, I'm going to ask you a couple
8 questions about Mr. Cupparo' s testimony and specifically
9 Exhibit 36, which is the FERC Order on ratemaking treatment.
10 Have you had a chance to review that Order? Are you familiar
11 with it?
12 A.I have read it, yes.
13 Q.Okay. And what I want to ask you about is it's
14 on page 36 of that exhibit -- or, no, sorry, Exhibit 36 but
15 page 18, and it's Paragraph 48 that's on that page. The middle
16 part of that paragraph talks about -- well, let me back up one
17 minute.
18 Is it correct that this Order grants what's
19 called incentive ratemaking treatment for the Gateway line?
A.For portions of the Gateway line, yes.
Q.And that incentive is a bonus-approved rate of
22 return for wholesale transactions?
23
24
25
A.It's a return on equity.
Q.Okay. And that's for wholesale transactions.
Correct?
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1 A.It would be for third-party usage of the
2 transmission system. It does not serve our retail customers.
3 Q.All right. And so do retail customers benefit
4 from those that kind of situation?
5 A.Yes, I believe I just stated that. We will
6 credi t back to our retail customers any incentive revenues that
7 we receive off Gateway.
8 Q.Great. Thank you. So, turning back to
9 Paragraph 48 here at the bottom, the paragraph discusses how
10 PacifiCorp had made some commitments for what's called
11 Sections A, B, and C; and correct me if I'm wrong, but I
12 believe Section A is in the McNary area in the Columbia River,
13 and Band C are in the Populus to Terminal sections?
14 A.That is not quite correct. B is the Populus to
15 Terminal section.
16 Q.Oh, okay. What is Section C?
17 A.Section C is the second part of Gateway Central,
18 and refer to that as our Mona-Oquirrh proj ect.
19 Q.Okay. Thank you.
A.Yeah, just for clarity.
Q.And it says here that -- let's see -- Segments B
22 and C represent significant expansions. And then the
23 Commission goes on to say that circumstances have changed since
24 those commitments were made.
25 And am I correct in interpreting that that
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1 circumstances have changed because of possibly load growth or
2 demands on the system?
3 A.Both, yes.
4 Q.But now thank you. That's all on that
5 paragraph, and I just want to step back a minute.
6 So, this -- the Gateway system and maybe
7 specifically Populus to Terminal, there's a potential to have
8 wholesale transactions on this line. Correct?
9 A.That would be correct.
10 Q.And so some of this capacity could be used for
11 those wholesale transactions?
12 A.That is correct.
13 Q.Great.
14 MR. OTTO: Thank you. That's all I have.
15 COMMISSIONER SMITH: Mr. Olsen.
16 MR. OLSEN: Yes, thank you, Madam Chair, just
17 have a -- potentially a couple of questions.
18
19 CROSS- EXAMINAT ION
21 BY MR. OLSEN:
22 Q.On page 3 of your rebuttal testimony,
23 Mr. Gerrard, down there beginning on line 20 and it carries
24 over to page 4 as well, you talk about the need for rightsizing
25 the transmission system and the lumpy nature of that
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1 investment. If you could tell me what that means in layman's
2 terms?
3 A.Yeah, in layman's terms, what we did was
4 prudently and adequately planned the system to provide our
5 customers with the lowest-cost option that meets both our
6 long-term and our short-term needs.
7 Q.Now -- so when you say "lumpy," that means excess
8 capaci ty, in light of current needs?
9 A."Lumpy," in my definition, means that we put it
10 in in the most economical increments that are available to us,
11 and we do that in many cases.
12 Q.But isn't a fact of that potentially you might
13 have some excess capacity?
14 A.Yes.
15 Q.Okay. Now, when you have this, I guess,
16 additional capacity in the system to move power back and forth,
17 do you have any knowledge how that affects the Company's need
18 for demand-side management programs?
19 A.I'm familiar with the demand-side management is
20 included in our integrated resource plans, so to the extent we
21 use demand-side management, again, it's reflected in the
22 resource plans that we periodically do for the Company.
23 Q.But do you have any understanding if it would
24 make demand-side management not as great a priority or you
25 don't need it as much, for lack of a better term?
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1 A.No, I don't.
2 Q.Now -- so let me talk a little bit about this,
3 this lumpy nature and rightsizing. You're saying the most cost
4 effective way to build this transmission line was at this point
5 in time to anticipate the needs of the future, look at our
6 current needs, and build what you think is the most cost
7 effecti ve. And the result of that is there's a little bit of
8 excess capacity or there's excess capacity at this time. Is
9 that a fair statement?
10 A.That is correct.
11 Q.Okay. So I would like to, if possible, analogize
12 this over to a demand-side management program. You heard
13 Ms. Hunter here earlier in the morning say that the irrigation
14 load control program has been successful and they have a lot
15 of, I guess, people signed up for it; and I'd equate that to
16 capacity to have a load control event and take megawatts off
17 the system. Is that a -- are you following me on that?
18 A. It does take megawatts off the system, yes.
19 Q.Okay. So if for some reason they think that it's
20 too much megawatts at this point in time, can't we analogize
21 that it's a little lumpy but it doesn't mean we wouldn't need
22 it in the future?
23 A.I don't have an opinion on that. I guess I'm not
24 qualified to assess the demand-side lumpiness.
25 Q.Okay.
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1 MR. OLSEN: No further questions.
2 COMMISSIONER SMITH: Ms. Davison.
3 MS. DAVISON: Thank you, Madam Chair.
4
5 CROSS-EXAMINATION
6
7 BY MS. DAVISON:
8 Q.Mr. Gerrard --
9 A.Yes, good morning.
10 Q.-- good morning.
11 A.Trying to see you here.
12 Q.I'll try to find a path. Thank you. There we
13 go.
14 A.That's better.
15 Q.Now we have eye contact.
16 A.Yeah, thank you.
17 Q.This morning, you testified about the nature of
18 the Oregon Stipulation as it relates to the Populus to Terminal
19 project. Is that correct?
20 A. Yes.
21 Q. Were you involved in those settlement
22 negotiations?
23
24
25
A.I was not.
Q.Have you actually read the Stipulation in Docket
UE-217?
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1 A.I have not.
2 Q.So you don't actually know then that there is, in
3 the Stipulation Order, I would refer to Paragraph lOB, a
4 $500,000 revenue requirement reduction in the total cost of
5 Populus to Terminal, do you?
6 A.I am not aware of that. That would be a question
7 for our regulatory folks.
8 Q.And so you're also not aware then that in this
9 Stipulation, there is an agreement that the actual costs, which
10 were represented to be lower than what was filed in the case,
11 will be reflected in rates, plus the $500,000 reduction.
12 You're not aware of that?
13 A.I am not.
14 Q.And you also indicated that this was in Oregon
15 rates. But that's not really accurate, is it, since the
16 Commission has not approved this Stipulation?
17 A.Yes. And I thought I stated that it was in
18 proceedings still and an Order hadn't been issued, so I didn't
19 mean to maybe misstate; but I didn't say it was in rates, I
20 don't believe. I stand corrected if I did.
21 Q.All right. Thank you. And since you were not
22 involved in the settlement talks, you don't know whether there
23 was a quid pro quo to give on this issue and take on another
24 issue, do you?
25 A.I do not.
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1 MS. DAVISON: No further questions. Thank you.
2 COMMISSIONER SMITH: Mr. Purdy.
3 MR. PURDY: I have none, thanks.
4 COMMISSIONER SMITH: Mr. Budge.
5 MR. BUDGE: Thank you.
6
7 CROSS-EXAMINATION
8
9 BY MR. BUDGE:
10 Q.Mr. Gerrard, Exhibit 239 was what we've referred
11 to now as supersized Gateway, and if my understanding is
12 correct, that was the Gateway that was part of the filing in
13 this proceeding up until the November 10th reduction to the
14 right size, I guess, shown in Exhibit 240?
15 A.Could you rephrase your question -- I'm not sure
16 I got it -- for clarity, please?
17 Q.Yeah. Looking at Exhibit 239, that was the map
18 wi th the original Gateway that we had in the filing.
19 Correct?
A.That is correct.
Q.Some have referred to that as maybe that's the
22 supersized Gateway. Correct?
23 A.That's the footprint we laid out for Gateway with
24 twice the capacity that our Company needed.
25 Q.And then if you turn to Exhibit 240, that is now
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1 the rightsized Gateway, correct, and it shows that the Red
2 Butte to Crystal segment in Nevada has been deleted and all of
3 those lines that went from Hemingway, Idaho, into Oregon and
4 into Washington, those are now just under consideration and so
5 they're out?
6 A.No, that's not correct. We still have in our
7 plan to build a connection between Hemingway and to Oregon
8 somewhere. It will be one of these -- likely, it will be one
9 of these options that are in dashed lines. It's still part of
10 the proj ect.
11 Q.So I may have misheard your testimony. I thought
12 you said that we were now building about half of Gateway
13 because that was all that was needed to serve the customers.
14 Did you make that statement?
15 A."Half" in a capacity sense, yes.
16 Q.Okay. And so then up until we went to the
17 rightsized Gateway, what was the who was being served by the
18 original supersized Gateway?
19 A.Half of Gateway, which was a single circuit
20 500 kV circuit for Gateway West and Gateway South, and Segments
21 Band C were serving our retail customers, were part of the
22 original footprint of Energy Gateway.
Q.So if you compare the original footprint on 239
24 with the current footprint on Exhibit 240, how many miles have
25 we taken off by deleting the Red Butte to Crystal segment and
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1 deleting all of those segments in Oregon, Washington, that are
2 now under consideration? How many of the 2,000 miles?
3 A.As far as serving PacifiCorp customers, we did
4 not take any miles off the proj ect. The line from Crystal
5 to -- the line from Crystal to Mona that you're referring to
6 that's been removed was not in our $ 6 million number and it was
7 not in our mileage calculation. That was there for third-party
8 use.
9 Q.What about the lines in Oregon, were they in your
10 cost number and your mileage number?
11 A.Which lines are you talking about in Oregon,
12 please?
13 Q.All of the ones in Oregon and Washington that are
14 now reflected in Exhibit 240 as under consideration.
15 A.The only one that was included was the Hemingway
16 to Captain Jack line, which was in the original footprint.
17 Q.So were those miles and costs now removed?
18 A.Those miles and costs are not removed. They are
19 still in the original proj ect because we've not taken the
20 projects off the table. We're just looking at different
21 options.
22 Q.So from a ratepayer standpoint, just help me
23 understand, am I getting a supersized Gateway for a supersized
24 cost, or am I getting a rightsized Gateway for a supersized
25 cost?
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1 A.We're building Gateway to serve the future needs
2 of our customers at the lowest cost that we can, and it's sized
3 appropriately for our long-term needs.
4 Q.If you would, please, let's look at Exhibit 36 of
5 Mr. Cupparo, and specifically, if you would turn to --
6 This exhibit is the FERC Order, and the
7 background provided on page 1 states, quote: According to
8 PacifiCorp, the proj ect is one of the most ambitious electrical
9 infrastructure proj ects planned in the Western United States in
10 the past two decades.
11 Do you follow that?
12 A.I see what you're referring to, yes.
13 Q.Okay. And then let's go over to page, if you
14 would, please, page 4 -- or, excuse me, page 6. There is a
15 section titled Risks and Challenges. And I think you were
16 present when I cross-examined Mr. Walj e yesterday on the issue
17 of transmission proj ects being builtin advance of when
18 associated generation resources are decided, as opposed to at
19 the same time?
20 A.I was present, yes.
21 Q.You were present?
22 A.I was present, yes. Excuse me.
23 Q.And I went to ask him some questions on this
24 Exhibit 36 and he deferred those to Mr. Cupparo, and now you
25 have adopted his testimony?
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1 A.That, I have.
2 Q. SO do you recall when I asked Mr. Walj e if under
3 this approach meaning building the transmission prior to the
4 time you build the generation of resources -- if that did not
5 enhance the risk to the shareholders, and to which he answered,
6 "No"? Do you recall that?
7 A.I do.
8 Q.Okay. And I also then asked him the follow-up
9 question did that enhance the risk to the ratepayers, to which
10 he answered, "No." Do you recall that answer?
11 A.That's correct.
12 Q.Now, I'd like you to read, if you would, please,
13 on page 6 of Exhibit 36, the last sentence of Paragraph 3 --
14 well, actually, the last two sentences that starts with
15 "PacifiCorp asserts with this approach," that last -- the last
16 two lines, Paragraph 13, the last line?
17 A.Paragraph 13?
18 Q.Yeah.
19 A.Yeah, I see them.
Q.Read the last sentence of Paragraph 13.
A.It says: PacifiCorp asserts that this
22 approach -- with this approach -- PacifiCorp faces greater
23 risks for transmission investment.
24
25
Q.And now go down to -- or, Paragraph 14
immediately below that and read the first full sentence of
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1 Paragraph 14.
2 A.PacifiCorp explains that it faces significant
3 financial and regulatory risks in pursuing this proj ect.
4 Q.And the next sentence, please?
5 A.PacifiCorp cites the estimated $6 billion cost,
6 comparing that to the average 111 million that is spent on
7 their capital expenditures annually between 2002 and 2007, and
8 noting that the total cost is more than three times its current
9 transmission rate base at 1.8 billion.
10 Q.Would you also read the last sentence of
11 Paragraph 14, and then continue on and read the first sentence
12 of Paragraph 15?
13 MR. HICKEY: Madam Chair, I'm going to object.
14 The exhibit speaks for itself, unless there's a follow-up
15 question letting Mr. Gerrard express his view as to what that
16 language meant. It seems like we're just reading, duplicating
17 the record by having it read in.
18 COMMISSIONER SMITH: Mr. Budge.
19 MR. BUDGE: I can paraphrase it to speed this up.
COMMISSIONER SMITH: And I would note,
21 Mr. Hickey, there's always redirect.
22 So, Mr. Budge, go ahead.
23 Q.BY MR. BUDGE: Then go ahead, if you would, and
24 could you read the last sentence of Paragraph 14 and the first
25 sentence of 15?
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1 A.Its financial risk is also affected by the fact
2 that it will be siting transmission lines ahead of new
3 generation resources, as noted above, and the fact that the
4 development costs are likely to increase over time. PacifiCorp
5 asserts that its proj ect faces significant regulatory risks
6 because it must garner approval of various State and Federal
7 authori ties, including six states, the Bureau of Land
8 Management, and the United States Forest Service.
9 Q.And then read the first sentence of the
10 Paragraph 16.
11 MR. HICKEY: I'm sorry, I thought Counsel said he
12 was going to paraphrase some of this to move us along. We're
13 just actually reading the same language.
14 MR. BUDGE: I'll go ahead and do it.
15 Q.BY MR. BUDGE: The first sentence of Paragraph 16
16 also states that there will be uncommon technology-related
17 risks because it contemplates investing in several
18 advance-transmission technologies that have been widely
19 deployed.
20 Now, with that background, this FERC Order that
21 we've simply read here seems to describe in considerable detail
22 numerous significant risks associated with Gateway. Now, my
23 question to you is simply just one: What is accurate? Is this
24 FERC representation that there are significant risks associated
25 wi th Gateway accurate, or is the testimony of Mr. Walj e
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1 yesterday that there are no substantial risks associated with
2 Gateway accurate?
3 A.In my opinion, there are significant risks with
4 si ting a proj ect, any transmission proj ect. Gateway is a large
5 one and it transverses a lot of states and a lot of areas.
6 There are risks associated with that, but they're manageable.
7 And we've demonstrated that by being able to move ahead on
8 Populus-Terminal at a very brisk pace and a controlled cost
9 pace, and we've demonstrated that we can manage those costs.
10 Q.If I understand your answer, you agree then with
11 the risk assessment that is set forth in Exhibit 36 that we
12 discussed?
13 A.I could not state that there were no risks with
14 Gateway. That would not be accurate.
15 Q.Maybe you didn't hear my question. I didn't ask
16 if there were no risks. I said do you agree with the
17 assessment of risks set forth by PacifiCorp in Exhibit 36 as
18 you just read and I just read?
19 MR. HICKEY: I'll obj ect to the form of the
20 question. This is a FERC Order; it's not PacifiCorp's work.
21 It's the work of --
22 MR. BUDGE: They are referring to every sentence
23 started: PacifiCorp states, PacifiCorp explains, PacifiCorp
24 asserts.
25 I think this is PacifiCorp' s
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1 COMMISSIONER SMITH: Excuse me. I think the
2 witness can give his opinion on whether this accurately
3 reflects the filing that PacifiCorp made to FERC.
4 THE WITNESS: And my opinion is that this Order
5 applied to the upsizing, larger-scale Gateway, and there are
6 significant risks in entering into partnerships with other
7 enti ties to upsize Gateway. And this incentive Order only
8 applies to that larger, upsized portion. That's what the FERC
9 Commission is referring to, and that's all the incentive rates
10 apply to. So, I think there are significantly different risks
11 in upsizing it for third-party use than there are for building
12 for our native load customers, which we know how to do very
13 well.
14 Q.BY MR. BUDGE: So you would disagree with
15 Mr. Walj e' s testimony yesterday that there are not significant
16 risks to the ratepayers or to the shareholders in building it,
17 if I understand what you've just been saying?
18 A.I believe there are risks in building it.
19 MR. BUDGE: That's all I have. Thank you very
20 much.
21 COMMISSIONER SMITH: Mr. Woodbury.
MR. WOODBURY: Thank you, Madam Chair.
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1 CROSS-EXAMINATION
2
3 BY MR. WOODBURY:
4 Q.Mr. Gerrard, how are you?
5 You know, I'm looking at three sets -- three sets
6 of testimony, I guess -- your testimony and then Mr. Cupparo' s
7 and then earlier testimony of Mr. Walj e -- with respect to the
8 Energy Gateway transmission proj ect and how it has changed, and
9 both you and Mr. Cupparo, I guess, cite the Commission's
10 Certificate Order as a finding of need. And that Order was in
11 PacifiCorp, the E-08-03 case, and the Commission issued its
12 Order on September 16th of '08.
13 Which proj ect was under consideration by the
14 Commission at that time as far as we are looking at
15 Populus-Terminal, but how was the project sized? Was it the
16 big size back in '08, or had it already been reduced in size?
17 A.This was the Idaho -- is this the Idaho --
18 Q.Certificate?
19 A.-- CPC?
20 Q.Yes.
21 A.We actually have the reduced size of Gateway
22 footprint was what was applied for. And I'll further clarify
23 that.
24 That Segment B does not change in its size
between the upsized Gateway and the lower-sized Gateway.
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1 Q.You cite language from that that Staff believes
2 the necessity of the project should be viewed in conjunction
3 wi th energy resources that are constructed, under way, or
4 planned; and cite some of those resources, and actually the
5 same language was cited by Mr. Cupparo.
6 But would you agree that the Commission's Order
7 had additional language which stated Staff's position that it
8 did not evaluate the overall prudency of the Company's resource
9 plan or the construction of the proj ect which constitutes a
10 good portion of the plan? Then the Commission cites Staff's
11 posi tion that Staff goes on to note that recovery of actual
12 costs for Idaho ratepayers will not be assessed until
13 construction of the proj ect is completed, full disclosure of
14 the proj ect expenses is provided, and proj ect utilization is
15 fully quantified.
16 And that was in the Order cited by you on page 4.
17 Did you look at the Order when you prepared your testimony?
18 A.I did not read it, no.
19 Q.Who provided you with that excerpt?
20 A.That was in Mr. Cupparo' s testimony.
21 Q.And you're Mr. Cupparo today?
22 A.Yeah. I believe that came from our proj ect team
23 who has the -- who obtained those permits, our construction
24 team.
25 Q.The Populus-Terminal had a online date of
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1 November 30th. Is that online?
2 A.It came online November 19th, this month.
3 COMMISSIONER SMITH: Last month.
4 Q.BY MR. WOODBURY: And the initial
5 THE WITNESS: Excuse me?
6 COMMISSIONER SMITH: Last month.
7 THE WITNESS: No, it was November 19th.
8 MR. WOODBURY: Excuse me.
9 COMMISSIONER SMITH: This is December.
10 THE WITNESS: Oh, I'm sorry. See how long we've
11 been here.12 (Laughter. )
13 THE WITNESS: Yes. I don't know what day it is,
14 so thank you.
15 COMMISSIONER SMITH: December 1st.
16 Q.BY MR. WOODBURY: In your testimony in your
17 direct, I think, page 16, you state that the original cost
18 estimate for that proj ect was 567
19 A.Could you slow down just a second, please, let me
20 catch up with you? Would you tell me where you're looking?
21
22
23
Q.Yeah. Page 16, line 17.
A.In direct?
Q.In your direct. It's just the original cost
24 estimate which you can accept subj ect to check, but it's
25 567.6 million. And then you indicate there were additional
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1 proj ect costs which are reflected in your Exhibit 37, and that
2 the estimated cost increased to $801.5 million.
3 Are the -- I mean, this was just recently online.
4 Are the actual or final costs available to you now?
5 A.There are still some proj ect close-out costs that
6 have not been fully allocated or fully booked just yet.
7 Q.And is the proj ect coming in under or below?
8 A.The project is under budget and ahead of
9 schedule.
10 Q.What do you anticipate the proj ect cost will
11 be?
12 A.Our proj ect forecast -- let me check that right
13 now. I have that here; I want to be accurate.
14 Yeah, the proj ect -- the proj ect cost estimates
15 for closure are now at -- let's see, let me make sure I've got
16 the right line here are forecast to be eight hundred
17 thirty-three million, five hundred -- 833,500,000.
18 Q.Okay. You would accept that in Response to
19 Commission Production Request 277, the Company showed cost per
20 mile for Populus to Terminal transmission to be $3. 7 million
21 per mile?
22
23
24
25
A.I'm looking at the Data Request.
Q.Oh?
A.Was that a question?
Q.It was 277.
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1 A.Yeah, I have that.
2 Q.Would you accept that that's what the Company
3 responded?
4 A.Yes, I'm sorry.
5 Q.And would you agree that that is the cost with
6 associated substation costs removed?
7 A.No, that includes substation costs.
8 Q.So then the -- what is the higher $5.9 million
9 per mile as far as costs, which I believed was including the
10 substations?
11 A.Let me back up here for a minute. Can you tell
12 me which figures you're looking at?
13 Q.Well, the 5.9 is --
14 A.I don't have those numbers in front of me, so I'm
15 a little confused on what you're referring to.
16 Q.It's 801 divided by 135.
17 MR. HICKEY: Is there a Data Request,
18 Mr. Woodbury?
19 MR. WOODBURY: No, that's a mathematical
20 calculation.
21 MR. HICKEY: Well, I understand that, but I
22 wanted to see if there was a Data Request we could get in front
23 of him to help aid the examination.
24
25
THE WITNESS: I have the Data Request 277, which
is the one I refer to, in front of me.
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1 Q.BY MR. WOODBURY: Well, if you were to take the
2 $801.5 million, which was the initial estimated cost not the
3 ini tial cost or updated cost that was used in the filing,
4 Exhibit 37, and divide that by the 135 miles, would it give you
5 a rough cost per mile?
6 A.That would be a cost --
7 MR. HICKEY: Do you have a calculator, Darrell?
8 THE WITNESS: I don't.
9 MR. HICKEY: Can we get you one?
10 Q.BY MR. WOODBURY: Subj ect to check, would you
11 believe that it's $5.9 million? Should we get you a
12 calculator?
13 A.I'm looking at Mr. Lobb' s testimony. I believe
14 he did that calculation and I was trying to refer to it. I
15 just don't have it at my fingertips here.
16 MR. HICKEY: In the interest of time, I think the
17 "subj ect to check," Mr. Gerrard, is a reasonable reply.
18 THE WITNESS: Okay. Yeah.
19 Q.BY MR. WOODBURY: In preparing your rebuttal
20 testimony, you had Mr. Lobb' s testimony in front of you. Is
21 that correct?
22
23
A.I do have it.
Q.And that -- I think that -- and that number is
24 reflected in Mr. Lobb' s testimony?
25 A.I remember reading it. I can't point you to it
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1 right now.
2 Q.Okay. Are you aware of a proj ect cost per mile
3 for new 345 kV double-circuit transmission capacity equivalent
4 to or exceeding the cost of the Populus to Terminal line?
5 A.Could you rephrase that again? I didn't get your
6 question.
7 Q.Are you aware of any proj ect that costs more than
8 $5.9 million per mile?
9 A.I'm not aware of any that PacifiCorp has done.
10 Q.Not any that PacifiCorp has done. Are you aware
11 of any proj ect in the country that has equivalent costs for a
12 345 kV double-circuit line?
13 A.I'm not.
14 Q.Did you -- okay. Are you familiar with the
15 Lawrence Berkeley National Lab's report entitled Cost of
16 Transmission for Wind, a Review of Transmission Planning
17 Studies, issued in February of 2009?
A.I'm vaguely familiar with that. I think
19 Mr. Cupparo refers to that in his testimony, if I recall.
20 Q.And did you review that report in preparing your
21 rebuttal testimony?
22
23
A.I did not.
Q.Did Mr. Cupparo review that report in preparing
24 his rebuttal testimony?
25 A.I can't vouch for whether he did or did not.
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1 Q.Looking at your direct testimony, page 7,
2 line 17, you speak of the MEHC PacifiCorp transaction. Do you
3 see where I'm starting?
4 A.I'm on page 7, yes.
5 Q.Yeah. And then looking ahead at -- on page 12 of
6 your testimony, other al ternati ves considered, particularly
7 line 11, is the al ternati ve that you cite on page 12 which
8 states that this al ternati ve would have provided a small,
9 incremental increase of 300 megawatts or less in transmission
10 capaci ty across the currently-constrained path between
11 Southeast Idaho and Utah, is that what -- is that altern-
12 would that al ternati ve have satisfied the transaction
13 commi tment number 34?
14 A. At the time it was made, it would have satisfied
15 it, yes. That was 2005.
16 And did youQ.and in considering these
17 al ternati ves, did you pencil out a dollar amount for that
18 particular alternative?
19 A.Yes, there were estimates provided by MidAerican
20 in making those commitments of $78 million.
21 Q.Seventy-eight million?
22 A.That's correct.
Q.Pursuant to I guess you indicated changed
24 business requirements or whatever, the proj ect grew beyond that
25 as far as the Populus-Terminal line. How much additional
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1 usable capacity is available now with completion of that
2 line?
3 A.The line capacity that I just pointed out is
4 1,600 megawatts.
5 Q.And that's presently available right now,
6 today?
7 A.That is posted on PacifiCorp' s OASIS, which
8 stands for Online Same-time Information System, which is a
9 requirement by FERC that we publish all transmission access and
10 transmission availability to the public on time. It's listed
11 on there, and it's used and useful for third parties to use or
12 for a merchant to use to serve load. So that's a long answer
13 to "yes" to your question. It is available.
14 Q.With respect to your rebuttal testimony and you
15 address Mr. Lobb' s discussion of disturbances -- system
16 disturbances -- and you referenced a report that you provided
17 to the parties as a subsequent -- I think it was to a Monsanto
18 Production Request, and you made a supplemental filing
19 providing that report, what was the date of that report that
20 you subsequently provided?
21 A.Let me check the date of that. I have it here.
22 Just give me a moment, please.
23 2007.
24
25
Q.Pardon? And it was a Monsanto Production
Request 6.6, which was submitted July 26th?
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1 A.The date of that report is September 27, 2007,
2 according to my records.
3 Q.And is there a reason that that wasn't provided
4 to Monsanto prior to the prefile of testimony?
5 A.There was a reason. We had included it in other
6 rate cases for this proj ect, and when it was mailed out it was
7 asked for -- the Request was for all W-E-C-C disturbance
8 reports. This one was not a W-E-C-C report. But we did not
9 intentionally omit it; we just didn't send it to you. So it
10 was supplemental, sent out later.
11 Q.Wasn't their Production Request: Please provide
12 a copy of 2007, 2008 Company-specific analyses on several
13 disturbances that severely impacted generation referenced on
14 page 9 of your direct testimony; and all correspondence,
15 papers, and documents regarding the conclusion of the
16 studies?
17 A.That was the Data Request, yes.
18 Q.And you indicate that that September 27th report
19 was not provided because you didn't feel it fell wi thin the
20 Request?
21 A.No. We didn't -- it didn't fall in the Request
22 because when it was sent, it was assumed it was just the WECC
23 disturbance -- the WECC sanction disturbance reports.
24 I found that discrepancy during my rebuttal
25 testimony and we immediately mailed that to Monsanto.
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1 Q.When was the report actually mailed out to the
2 parties?
3 A.I don't have the date. Fairly recently, but it
4 was -- I don't have a date.
5 Q.You would agree that it was provided after the
6 date of the prefile of direct testimony?
7 A.I can't confirm that.
8 Q.You can't confirm that. Did it go out under your
9 signature?
10 A.It did not. It went out as a Data Request
11 through our regulatory group.
12 Q.Who brought it to their attention that that
13 was -- had not been provided?
14 A.I brought it to our staff's attention who handles
15 all of our Data Requests wi thin transmission, and we
16 immediately provided that.
17 Q.Would you accept that it was -- the Supplemental
18 Response was filed on November 11th?
A.I'll take your word for it subj ect to check. I
20 don't have the date, like I said.
21 Q.Mr. Walj e in his direct testimony on page 12 gave
22 the sort of status report of the Energy Gateway project and
23 proposed that -- well, I guess delays that have occurred. As
24 the proj ect architect, are you aware of any impending delays
25 that will affect the proj ect?
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1 A.Are you asking me that question for the entire
2 project or the Populus-Terminal?
3 Q.Yes. Well, you know, I'm looking at also
4 Mr. Cupparo' s
5 A.And I'm j ust striving for clarity here. I
6 apologize.
7 Q.Yeah. I'm looking at Mr. Cupparo's testimony on
8 page 6, and he states that Energy Gateway is comprised of eight
9 interrelated and interdependent transmission segments, and
10 those are reflected in his Exhibit 33. And he says: Each
11 segment provides specific capabilities, but also support their
12 segments to enhance the benefits of Energy Gateway.
13 And so I'm looking at his description of the
14 proj ects and then Mr. Walj e' s indicating of the delays that
15 have already occurred pushing this thing out, at least for
16 Gateway South, as far as 2020, and I'm wondering whether you
17 envision there will be any further delays based upon opposition
18 to transmission siting or anything else.
19 A.What I would say is we have published on our Web
20 site and in other forums a date range, so if you look at
21 Gateway West, for example, it says 2014 to -18. The reason
22 we've published a date range is there are construction seasons
23 yet to be dealt with. It could be two years under
24 construction, it could be three, for example. There's still
25 permi tting to be done. So we reflect that in a date range, but
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1 we're not anticipating anything outside those date ranges at
2 this point.
3 Q.At this point. Would you agree that changes to
4 Energy Gateway may impact the ability of the Company to fully
5 realize the capability of the Populus-Terminal line?
6 A.I don't believe we would not fully utilize it.
7 My plan is to fully utilize Populus to Terminal.
8 Q.That is your plan, but if there were changes in
9 Energy Gateway, is it possible it would affect the full
10 capabili ty realization of Populus-Terminal?
11 A.Changes in Gateway could affect the capacity of
12 Populus to Terminal, that's correct.
13 Q.In your rebuttal testimony, you -- and speaking
14 to the disturbances -- you don't identify any transmission
15 limitations due to system disturbances since November of 2007.
16 Is that correct?
17 A.Not of a scale that would require an inquiry and
18 a report such as you have in front of you.
19 Q.Well, yeah, not of a scale. Then we could
20 conclude that over the last three years, there have been no
21 noteworthy transmission limitations to system disturbances that
22 would justify an upgrade of the transmission line?
23 A.No. I think my basis for Populus-Terminal is not
24 solely on the purpose of disturbances or disturbance
25 mi tigation. That is one benefit -- a large benefit -- we get
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1 out of Populus-Terminal.
2 The other significant portion and justification
3 for Populus-Terminal is again to provide long-term transmission
4 service to move our resources to our customer load center.
5 So, you have to look at those two together. It
6 wouldn't be prudent planning to look at those in isolation.
7 Q.Wi th respect to your testimony as to the used and
8 usefulness, you understand that "used and useful" is perhaps a
9 term of regulatory art that is reflected in Commission Statutes
10 and Supreme Court Decisions?
11 A.I'm aware of the term, yes.
12 Q.And so did you review all of those prior to
13 submi tting and preparing your testimony?
14 A.Did I review all of what, specifically?
15 Q.The Statutes and the case authority --
16 A.No.
17 Q.-- that applied?
18 A.No, I did not.
19 Q.Did you review any Commission Orders dealing with
20 used and useful?
21 A.I did not. I would suggest though and would
22 state that I am familiar with the term and I've done a number
23 of projects that have been determined used and useful, and I
24 can give you a lot of examples of those. I would state I have
25 information on our Bridger system
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1 Q.I'm asking about your familiarity with Idaho.
2 A.Okay, I did not review that.
3 Q.And your answer was, "No." That's fine.
4 A.Okay.
5 Q.On page 17 of your rebuttal testimony, you state
6 you disagree with Mr. Lobb' s reference to Idaho Code 61-502A
7 regarding the used and useful standard, and the implication
8 that the proj ect includes unnecessary capacity.
9 By -- I didn't know that that was you state
10 that was the implication of his testimony. But he didn't state
11 that, did he, that the capacity was unnecessary?
12 A.Give me a moment here. I don't recall his exact
13 words, but I'll find them.
14 Q.And so
15 COMMISSIONER SMITH: Mr. Woodbury, let's let the
16 witness find the answer to your previous question before you
1 7 start more.
18 THE WITNESS: I believe his statements were that
19 the project would be mostly not utilized upon going into
20 service, something to that effect.
21 I'm looking for his testimony here. Excuse me
22 for a minute.
23 Q.BY MR. WOODBURY: Do you think he was making
24 reference to present and future benefit?
25 A.That's not what I'm referring to.
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1 Q.What were you referring to?
2 A.Excuse me just a minute here. I'm getting there.
3 Thank you.
4 Yeah, I've found it. Thanks for your patience.
5 On page 27 is what I was referring to in my
6 rebuttal, that his recommendation -- Mr. Lobb' s
7 recommendation -- is justified on the undisputed fact that the
8 proj ect is oversized and will not be fully utilized unless or
9 until Energy Gateway is completed. That's the statement I was
10 referring to.
11 Q.And the distinction there, again, is perhaps the
12 difference between present and future benefit, full realization
13 of benefit, for Idaho customers?
14 A.I assume that's what Mr. Lobb was referring to.
15 I would also clarify that on page 28 of his
16 testimony, Mr. Lobb states that Populus-Terminal was
17 constructed in large part to provide the potential future
18 benefits that only the completion of Gateway can ultimately
19 ensure.
20 And I've just demonstrated, I believe, with my
21 exhibits that 73 of Populus-Terminal is capacity, is used and
22 useful, and is available for the market for our customers at
23 this time. That's much more than potential benefits for future
24 need.
25 Q.Is Populus-Terminal fully subscribed right now?
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1 A.It is not, in both directions.
2 MR. WOODBURY: Madam Chair, Staff has no further
3 questions.
4 Thank you, Mr. Gerrard.
5 COMMISSIONER SMITH: Thank you, Mr. Woodbury.
6 Questions from the Commissioners? Commissioner
7 Redford.
8
9 EXAMINATION
10
11 BY COMMISSIONER REDFORD:
12 Q.Yes, I just have a few questions.
13 A.Certainly.
14 Q.Have you recently reviewed all of the testimony
15 of Mr. Walj e, including the direct and the rebuttal?
16 A. I looked at some early drafts of Mr. Walje' s
17 testimony. I did not see the finals.
18 Q.Okay. So you haven't -- I guess I'll take it at
19 that. You've seen drafts; you haven't seen the final.
But you were here yesterday and heard the
21 testimony of Mr. Walj e. Is that correct?
22
23
A.That's correct.
Q.I asked a few questions, and if I recall
24 correctly, my questions dealt with the impact of recession
25 of our recession -- upon capital improvement and capital
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1 investment proj ects. Do you recall that?
2 A.I do.
3 Q.And I believe that I -- my testimony and also --
4 or, my questions -- also dealt with the date, or if it
5 didn't maybe I'll just back up a little bit.
6 When was the date that the Energy Gateway project
7 was downsized to reflect the Hemingway removal and I believe
8 that there was a point in Nevada or Utah where it was on, I
9 believe, Schedule -- or, on Exhibit -- the map.
10 MR. HICKEY: 239 would be the one that you're
11 referring to, Chairman Redford, and Crystal, Nevada, is the
12 town that we talked about.
13 COMMISSIONER REDFORD: Yes, that's correct.
14 Thank you very much.
15 THE WITNESS: Yeah, I do understand your
16 question.
17 We've been entertaining prospects from people who
18 want a partnership in Gateway since its inception, and since we
19 haven't been able to secure any contracts or funding by third
20 parties, in March of this year we made the decision that we
21 were going to move ahead with the -- I'll call it the downsized
22 Gateway. It's the Gateway that we need, has started in March
23 of this year, and we've been progressing towards that.
24 The most recent change which I think is important
25 for you to know is we recently changed the maps and -- the maps
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1 that I showed you -- because we filed our SF2 99, which is the
2 form that you file with Bureau of Land Management, start -- to
3 continue the EIS environmental impact process on Gateway South.
4 When we filed that, we had to make sure we were filing for the
5 exact proj ect
6 Q.BY COMMISSIONER REDFORD: All I wanted was the
7 date it was downsized.
8 A.Oh, okay. We started in March internally to
9 make that.
10 Q.2010?
11 A.2010.
12 Q.And we had been in the -- recession was
13 full-blown at that time?
14 A.I would agree. It's still in place, yes.
15 Q.Was there any part of the downsizing decision,
16 any part of that had to do with the economy, US economy?
17 A.No, not directly. It did show up in our load
18 forecasts and our resource forecasts that are currently in the
19 plan.
Q.Did you fully -- do you have any question with
21 regard to Mr. Walj e' s testimony or do you agree with the --
22 entirely with his testimony?
23 A.Yes, I do. I think he stated things pretty
24 clearly yesterday.
25 Q.So you would adopt pretty much his testimony?
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1 A.I would.
2 Q.Are you on the committee that Mr. Walje was
3 speaking about yesterday that reviews the capital investments,
4 especially during a recession period?
5 A.I am not.
6 Q.So did you have any input into the -- to that
7 committee to make the decision to downsize?
8 A.I had input into the executives, as Mr. Walj e
9 stated, based on Gateway's load forecasts and resource
10 forecasts which I planned for and I described earlier, so that
11 was my input was through technical -- the technical planning
12 site.
13 Q.And I believe a great deal of Mr. Walj e' s
14 testimony was that notwithstanding the recession, that the
15 planning for Energy Gateway had not changed -- has not
16 changed -- as a result of the recession?
17 A.I would say that's accurate, as a direct result
18 of the recession.
19 Q.Okay.
COMMISSIONER REDFORD: I have no further
21 questions.
22
23
COMMISSIONER SMITH: Commissioner Kempton.
COMMISSIONER KEMPTON: Thank you, Madam Chairman.
24 I have one question or a couple, depending.
25
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1 CROSS-EXAMINATION
2
3 BY COMMISSIONER KEMPTON:
4 Q.In the original planning for the Populus to
5 Terminal line, would that capacity have served the needs of
6 Eastern Idaho in terms of the service obligation of Rocky
7 Mountain Power?
8 A.Yes, it would, absolutely.
9 Q.And so is it your position that because there was
10 additional capacity, the rightsize capacity so that you could
11 run a line for the purposes that you now anticipate, that you
12 should drag Eastern Idaho along for the additional cost
13 compared to what they would have had to pay for the original
14 line?
15 A.I'm not making a distinction between the original
16 line. I'm sorry, I missed your question. Could you try that
17 one more time for me?
18 Q.Well, the first proposal from Populus to Terminal
19 was priced at what value?
A.Are you referring to the MidAerican transaction
21 commitment or
22
23
24
25
Q.Yes.
A.-- when you say, The first line?
Q.Yes, the MidAerican commitment.
A.Oh, yeah, that -- okay, catching up with you,
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1 sorry.
2 That was committed at $78 million to perform a
3 300 megawatt upgrade.
4 Q.Right. Would that have served the needs of
5 Eastern Idaho that you serve?
6 A.At the time that we proposed that, it did.
7 Q.Would it meet it now?
8 A.No, it would not.
9 Q. How much extra capacity if you -- just maybe a
10 little you may not have the data for this:
11 How much extra capacity beyond the MidAerica
12 planning in the early stages -- 2005 stage, I think you said it
13 was -- and now had to be added to the system in order to serve
14 Eastern Idaho?
15 A.I don't have the resource number. That would
16 have to come from our resource planners in IRP. I don't have
17 that.
18 Q.You're probably aware of the debate that's going
19 on nationwide as to whether areas that aren't served by a
20 particular line, even though it may cross their service area,
21 should be obligated to help pay for that line. It's sort of an
22 analogy to the highway systems in the United States. Correct?
23 Do you believe that there should be any
24 consideration of pro-rata share when you have a rightsizing
that increases the capacity so far beyond what the needs of
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1 Eastern Idaho contingent line have, that they should be
2 obligated to pay equally with others who are buying into that
3 line if there is such purchases -- if there are such purchases?
4 A.Well, I think my knowledge of our multistate
5 process is not vast, but it does recognize the amount of usage
6 and the need for proj ects; and then any credits that would come
7 through retail wheeling or through other revenue generation in
8 the Company that's not retail would come back to those states
9 as a credit. So, I believe MSP does recognize projects on
10 their usage.
11 Q.Okay.
12 COMMISSIONER KEMPTON: My only other question
13 comes back to used and useful, and that was covered by
14 Mr. Woodbury. So, that's all the questions I have, Madam
15 Chairman.
16 COMMISSIONER SMITH: Thank you.
17
18 EXAMINATION
19
20 BY COMMISSIONER SMITH:
21 Q.I just have one. I want to be sure the
22 conclusion I came to from your discussion of system line losses
23 is correct. And you made the assertion that actual system line
24 losses are not reflected by individual segment assessments,
25 which I reduced to the sum of the parts don't equal the total.
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1 A.That is correct.
2 Q.Good.
3 COMMISSIONER SMITH: That's all I had. Any
4 redirect?
5 MR. HICKEY: I do. Thank you, Madam Chair.
6
7 REDIRECT EXAMINATION
8
9 BY MR. HICKEY:
10 Q.Going back to the discussion that eventually led
11 to Energy Gateway, Mr. Gerrard, am I correct that it wasn't
12 just the Company that thought the West, including the states of
13 your six-state service terri tory, needed additional
14 transmission?
15 A.Yes. There's a number of indicators to that,
16 yes.
17 Q.And if you look at page 8 of Mr. Cupparo' s
18 testimony, did he detail some of the State and Federal
19 governments and agencies that were encouraging the development
20 of more transmission resources throughout the West?
21 A.Yes, there's quite a number of documents and
22 exhibi ts there that speak to transmission capacity needs.
23 Q.Wi thout reading all of them, would you agree that
24 the Department of Energy National Transmission Grid Study was
25 identifying the Wyoming-Idaho interface as a major constraint
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1 interface?
2 A.Yes, they did, multiple times.
3 Q.And was there additional study by the United
4 States Department of Energy in the 2006 National Energy
5 Transmission Congestion Study that was a part of the government
6 backdrop, if you will, that ultimately played a part in the
7 development of this resource?
8 A.Tha tis correct, and the re 's an exhibi t
9 Mr. Cupparo has with a map in there.
10 Q.And is it accurate that the Western Governors'
11 Association was also actively encouraging the development of
12 addi tional transmission resources in this part of the
13 country?
14 A.Yes, there's been at least three studies that I'm
15 aware of and participated in that the Western Governors have
16 helped sanction and drive forward with transmission needs in
17 the West.
18 Q.And from your perspective of being intimately
19 involved in both Gateway and the Populus to Terminal segment in
20 this case, was that government encounter significant or of any
21 impact in the decisions that were made about additional
22 transmission resources that would be planned and ultimately
23 built by PacifiCorp?
24
25
A.I think, certainly, there was a large influence.
Q.Okay. So then a proj ect went before the FERC.
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1 Correct?
2 A.That's correct.
3 Q.And the proj ect that was before the FERC is a lot
4 different than what we're talking about in this rate
5 proceeding. Isn't that true?
6 A. Yes.
7 Q.All right. And the proj ect that was before the
8 FERC had a component that third-party merchants would become
9 shippers for wholesale markets. Isn't that true?
10 A.That's correct. Half of Gateway was to serve
11 markets in that situation.
12 Q.And that would have allowed some intertie,
13 interconnection, in Crystal, Nevada. Correct?
14 A.It would require interconnection with markets.
15 Q.And then that piece of the proj ect walked away,
16 correct, or we'll let you tell us how it happened; but in any
17 event, that piece of the proj ect no longer exists. Correct?
18 A.That's correct.
19 Q.How did that happen? What caused that to
20 happen?
21 A.As I mentioned earlier, we have to take requests
22 for transmission in a nondiscriminatory way, so those requests
23 came through our tariff and we did contract for people who
24 wanted to go to that step and asked them to sign a contract and
25 subscribe to the upsized Gateway, and no one has chosen to do
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1 that.
2 Q.So from the perspective of some of the
3 examination by Commissioner Redford, for example, did the
4 economy, in your view, have an impact on this proj ect getting
5 reduced to the size that's reflected in Exhibit 240 and the map
6 that's contained in Exhibit 240?
7 A.Yeah, absolutely. I think that from that
8 perspecti ve, available capital and the pressures on the credit
9 markets definitely put people in a different position that
10 wanted -- that may have wanted -- to participate in Gateway in
11 the beginning.
12 Q.Okay. And there's a lot of talk about Energy
13 Gateway and the different routings, that of transmission
14 resources to different parts of the West, but what's involved
15 in this case is a segment that's already energized. Isn't that
16 true?
17 A.And Populus-Terminal is already energized, yes.
18 Q.And let me ask you this
19 MR. BUDGE: I'm going to interj ect if I might.
20 COMMISSIONER SMITH: Mr. Budge.
21 MR. BUDGE: I think we've asked and answered --
22 these questions have been asked and answered by Mr. Gerrard and
23 Mr. Cupparo in their testimony, and we're simply inviting the
24 admonishment of the Chair that these questions be
re-answered.
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HEDRICK COURT REPORTING
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GERRARD (Di )
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1 MR. HICKEY: I'm almost finished, Madam Chair.
2 COMMISSIONER SMITH: Please finish.
3 MR. HICKEY: I promise you -- well, this hasn't
4 been asked, but I think it's embedded in some of the
5 cross-examination that came out.
6 Q.BY MR. HICKEY: Could you have, in your view,
7 prudently built a 345 kV line from Populus to Terminal and then
8 met all of the current and future needs of your customers that
9 are benefited by this transmission resource?
10 A.Not with a single line, we could not have.
11 Q.Is it possible to come in and say í well, we'll
12 build a 345 kV for these 18 months or these four years, and
13 then we'll take it up to 345 -- and then we'll take it up to
14 500? Did you look at these incremental steps of further
15 developing that resource?
16 A.I did, and, quickly, in my rebuttal testimony on
17 page 6 and my Exhibit 66, I showed the cost of coming in and
18 building a single circuit 345 transmission line from Populus to
19 Terminal and then coming back and tearing it out, because we'd
20 only have one right-of-way, building Populus-Terminal back in
21 its place, and it's 54 percent more expensive than this project
22 is today or $1.2 billion to do that.
23 Q.So then, finally, would it be prudent, in your
24 opinion, Mr. Gerrard, to build a transmission resource that
25 only meets the current demands of your customers?
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GERRARD ( Di)
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1 MR. BUDGE: Same objection: Asked and
2 answered.
3 MR. HICKEY: Hasn't been asked and answered.
4 THE WITNESS: It is not prudent, and I think it
5 would result in higher costs for our customers.
6 Q.BY MR. HICKEY: And do you believe that it's
7 necessary to have capacity beyond that current need?
8 A.Absolutely.
9 MR. HICKEY: That's all I have.
10 COMMISSIONER SMITH: Thank you, Mr. Hickey. You
11 can tell I'm hungry and tired --
12 MR. HICKEY: Yes.
13 COMMISSIONER SMITH: -- and getting old, and not
14 actually cutting you off.
15 MR. HICKEY: You haven't been.
16 COMMISSIONER SMITH: So we are at our lunch hour.
17 I would like to start up again at 1: 30 if possible. So we're
18 adjourned for the lunch hour.
19 (The witness left the stand.)20 (Noon recess.)
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25
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HEDRICK COURT REPORTING
P. O. BOX 578, BOISE, ID 83701
GERRARD (Di )
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