20180529Technical Hearing Transcript Vol II.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSIONO
IN THE MATTER OF THE APPLICATION )
OF PACIFICORP DBA ROCKY MOUNTAIN )CASE NO.PAC-E-17-07
POWER FOR A CERTIFICATE OF PUBLIC )
CONVENIENCE AND NECESSITY AND )
BINDING RATEMAKING TREATMENT )
FOR NEW WIND AND TRANSMISSION )FACILITIES )
BEFORE
COMMISSIONER ERIC ANDERSON (Presiding)
COMMISSIONER KRISTINE RAPER
COMMISSIONER PAUL KJELLANDER
O
PLACE:Commission Hearing Room
472 West Washington Avenue
Boise,Idaho
DATE:May 10,2018
VOLUME II -Pages 3 -646
ORIGINAL CSB REPORTING
O Certified ShorthandReporters
PostOfficeBox9774 Reporter:Boise,Iddio 83707 Constance Bucy,[e-mail] CSR
Ph:208-890-5198 Fax:[phone]
1 A PPE A R A NCES
III 2
3 For the Staff:Mr.Brandon Karpen
Deputy Attorney General
4 472 West Washington
Boise,Idaho 83720-0074
5
For Rocky Mountain Ms.Katherine A.McDowell
6 Power:and M .Adam Lowney
McDowell Rackner Gibson PC
7 419 SW 11th Avenue
Suite 400
8 Portland,Oregon 97205
9 For Idaho Irrigation M .Eric L.Olsen
Pumpers Association:Echo Hawk &Olsen PLLC
10 505 Pershing Avenue,Ste.100
PO Box 6119
11 Pocatello,Idaho 83205
12 For Monsanto Company:Mk.Randall C.Budge
and Thomas J.Budge
0 13 Racine,Olson,Nye &Budge
201 East Center
14 PO Box 1391
Pocatello,Idaho 83204-1391
15
For PIIC:M .Ronald L.Williams
16 Williams,Bradbury,P.C.
1015 West Hays Street
17 PO Box 388
Boise,Idaho 83701
18
19
20
21
22
23
24
25
CSB REPORTING APPEARANCES
208.890.5198
1 I NDEX
2 WITNESS EXAMINATION BY PAGE
3 Joelle Steward Ms.McDowell (Direct)14
(RMP)Direct Testimony (Mr.Larson)17
4 Rebuttal Testimony 44
Supplemental Testimony 68
5 Second Supplemental Testimony 74
Supplemental Rebuttal Testimony 79
6 Ms.McDowell (Direct-Cont'd)86
Settlement Testimony 88
7 Ms.McDowell (Direct-Cont'd)113
Mr.Budge (Cross)118
8 Mr.Williams (Cross)127
Mr.Olsen (Cross)130
9 Mr.Karpen (Cross)132
Commissioner Kjellander 137
10 Commissioner Raper 140
Ms.McDowell (Redirect)142
11
Rick Link Ms.McDowell (Direct)146
12 (RMP)Direct Testimony 148
Rebuttal Testimony 237O13SupplementalTestimony301
Second Supplemental Testimony 376
14 Supplemental Rebuttal Testimony 436
Settlement Testimony 585
15 Ms.McDowell (Direct-Cont'd)601
Mr.Williams (Cross)602
16 Mr.Olsen (Cross)612
Mr.Karpen (Cross)619
17 Commissioner Raper 631
Ms.McDowell (Redirect)637
18
19
20
21
22
23
24
25
CSB REPORTING INDEX
208.890.5198
1 EXH I B I TS
2
3 NUMBER DESCRIPTION PAGE
4 FOR ROCKY MOUNTAIN POWER:
5 22.Wind Resources Premarked
Admitted 645
6
23.Nominal Henry Hub Natural Gas Premarked
7 Price Forecasts Admitted 645
8 24.SO Model Annual Results Premarked
Admitted 645
9
25.Estimated Annual Revenue Premarked
10 Requirement Results Admitted 645
11 26.Resource Tracking Mechanism Premarked
Admitted 645
12
13
27.TR eCombinedPerojectsEstimatned Pre arekedd
645
14 28.Combined Projects -Example Premarked
Monthly RTM Deferral Calculation Admitted 645
15
29.Capital Structure &Cost from Premarked
16 Docket No.PAC-E-15-09 Admitted 645
17 37.SO Model Annual Results Premarked
(Corrected)Admitted 645
18
38.Estimated Annual Revenue Premarked
19 Requirement Results (Corrected)Admitted 645
20 39.Confidential exhibit sponsored Premarked
by Rick Link Admitted 645
21
40.SO Model Annual Results Premarked
22 (Corrected)Admitted 645
23 41.Estimated Annual Revenue Premarked
Requirement Results (Corrected)Admitted 645
24
O 42.Resource Tracking Mechanism Premarked
25 Admitted 645
CSB REPORTING EXHIBITS
208.890.5198
1 EXH I B I TS (Continued)
2
3 NUMBER DESCRIPTION PAGE
4 FOR ROCKY MOUNTAIN POWER:(Continued)
5 43.The Combined Projects Estimated Premarked
Revenue Requirement Cost (Benefit)Admitted 645
6
44.Combined Projects -Example Premarked
7 Monthly RTM Deferral Calculation Admitted 645
8 45.Combined Projects -Capital Premarked
Structure,Income Tax Rate,etc.Admitted 645
9
54.Confidential exhibit sponsored Premarked
10 by Rick Link Admitted 645
11 55.SO Model Annual Results Premarked
(Corrected)Admitted 645
12
13
56.EReqarem nAnnRualRev errected)Pre arekedd
645
14 57.Confidential exhibit sponsored Premarked
by Rick Link Admitted 645
15
58.(Withdrawn)--
16
59.(Withdrawn)--
17
60.(Withdrawn)--
18
61.The Independent Evaluator's Premarked
19 Assessment of PacifCorp's Final Admitted 645
Draft 2017R RFPs
20
62.Revenue Requirement Overview Premarked
21 Admitted 645
22 63.Example Annual RTM Deferral Premarked
Calculation -Revenue Requirement Admitted 645
23
64.Example Annual RTM Deferral Premarked
24 Calculation -Revenue Requirement Admitted 645
25
CSB REPORTING EXHIBITS
208.890.5198
1 EXH I B I TS (Continued)
2
3 NUMBER DESCRIPTION PAGE
4 FOR ROCKY MOUNTAIN POWER:(Continued)
5 65.Capital Structure,Income Tax Rate Premarked
&Net Power Cost Description Admitted 645
6
67.Confidential exhibit sponsored Premarked
7 by Rick Link Admitted 645
8 68.Confidential exhibit sponsored Premarked
by Rick Link Admitted 645
9
69.Confidential exhibit sponsored Premarked
10 by Rick Link Admitted 645
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING EXHIBITS
208.890.5198
1 BOISE,IDAHO,THURSDAY,MAY 10,2018,9:30 A.M.
2
3
4 COMMISSIONER ANDERSON:Good morning.
5 Well,it's that time.It's 9:30 a.m.,May 10th,2018,
6 and we are set to begin our technical hearing in Case
7 No.PAC-E-17-07,further identified as in the matter of
8 the application of PacifiCorp doing business as Rocky
9 Mountain Power for a certificate of public convenience
10 and necessity and binding ratemaking treatment for new
11 wind and transmission facilities.
12 The hearing is taking place to consider
13 Rocky Mountain Power's request for application for a
14 certificate of public convenience and necessity to
15 construct or acquire four new wind projects with a total
16 combined capacity of 860 megawatts.The Company also
17 requests CPCNs for several transmission facilities,
18 portions of which are associated with the Company's
19 Gateway West transmission project.
20 My name is Eric Anderson and I'll be the
21 Chair of today's proceedings.To my right is Paul
22 Kjellander.To my left is Commissioner Raper,
23 Commissioner Kjellander,excuse me.We comprise the
24 Commission and we will ultimately render a final decision
25 in the matter.
CSB REPORTING 3 COLLOQUY
208.890.5198
1 We're going to have several little
2 housekeeping things to discuss.First of all,out that
3 door and down the hall,as you probably all know,the
4 bathrooms at the very end,and there's also water
5 available in the break room,and if you want the
6 wireless,it's pucwireless,all lower case.
7 We do anticipate a couple-day hearing
8 here,so if there's no objections,we'll break for lunch
9 as close to noon as possible,but only as testimony
10 allows.I don't want to break testimony if we don't need
11 to.In an effort to use our time efficiently,I don't
12 want to pre-schedule breaks,but we can take breaks as
13 necessary and trust me,our court reporter Connie will be
14 letting me know when that will be,so I'll take her
15 directive on that.
16 Some additional housekeeping issues as far
17 as the order of the parties and testimony,normal
18 procedure is to begin with the Applicant,intervenors,
19 and then the Staff and without objection,it's my intent
20 to utilize this order in today's proceedings,and you'll
21 notice we have note cards,I need a little extra help.I
22 haven't done too many of these big technical hearings,so
23 now I can look out there and it helps me identify.I'm
24 sorry if it seems a little collegiate,but that's what
25 I'm going to have today.
CSB REPORTING 4 COLLOQUY
208.890.5198
1 Also,without objection,in the interest
2 of efficiency,as witnesses come up,all prefiled
3 testimony sponsored by the witness is available for
4 cross-examination,that be direct,rebuttal,and
5 supplemental rebuttal,with the caveat being that all
6 parties will retain the opportunity to recall witnesses,
7 if necessary.
8 As far as testimony sponsored by the
9 witnesses,I'm aware that there will be two pieces of
10 testimony sponsored by witnesses that did not originally
11 draft the testimony.These are special circumstances and
12 not in the regular course of business.First,due to a
13 significant medical issue,Monsanto witness Kathryn
14 Iverson's testimony will be sponsored by another Monsanto
15 witness.All parties have informed the Commission that
16 they have no cross-examination of Ms.Iverson.Second,
17 due to his retirement,Staff witness Randy Lobb's
18 testimony will be sponsored by Staff witness Michael
19 Louis.Mr.Louis stands available for cross and anything
20 that relates to Mr.Lobb's testimony.
21 As far as the confidential information,
22 which we have a considerable amount of today,we have
23 that information available to us in prefiled testimony.
24 For purpose of efficiency,should any witness or attorney
25 cross-examining that witness require the use of
CSB REPORTING 5 COLLOQUY
208.890.5198
1 confidential information,we can deal with it in one ofO2threeways:We can describe the information as in the
3 projects referred to on page 4 and 5 of Exhibit 1 without
4 revealing the confidential information.The Company may
5 freely refer to the information publicly waiving its
6 confidential nature;and thirdly,you can notify me that
7 it is impossible to proceed without stating a piece of
8 confidential information.I will clear the Hearing Room
9 of all persons who have not executed the appropriate
10 non-disclosure agreements and that information can be
11 specified.For reasons of efficiency and rhythm,I would
12 prefer to avoid this last procedure,if at all possible.
13 I'd like to at this time take notice of
14 the appearances of parties and let's begin with the
15 Company.
16 MS.McDOWELL:Katherine McDowell here on
17 behalf of Rockey Mountain Power.With me today is my
18 partner Adam Lowney.
19 COMMISSIONER ANDERSON:Welcome.
20 Monsanto?
21 MR.BUDGE:Randy Budge on behalf of
22 Monsanto Company.Also appearing with me is my partner
23 T.J.Budge,and we have here with us as well Jim Smith
24 who is the energy manager for Monsanto,as well as our
25 witnesses Mr.Nick Phillips and Mr.Jim Dauphinais,and I
CSB REPORTING 6 COLLOQUY
208.890.5198
1 do want to thank the Commission for allowing Ms.Iverson
2 to have her testimony sponsored.She's got a medical
3 issue and we really appreciate that accommodation.
4 MR.KARPEN:Good morning,Brandon Karpen
5 on behalf of Commission Staff.
6 MR.WILLIAMS:Ron Williams on behalf of
7 PacifiCorp Idaho Industrial Customers.Here today with
8 me at my table is our witness Brad Mullins.
9 MS.OLSEN:Eric Olsen with Idaho
10 Irrigation Pumpers Association.With me is Tony Yankel,
11 our witness in this case.
12 COMMISSIONER ANDERSON:Well,welcome all.
13 Are there any parties that we've missed or forgotten?
14 Seeing none,I guess at this point before we begin,are
15 there any other preliminary issues that anybody would
16 like to bring up?
17 MS.McDOWELL:Yes,Commissioner,we do
18 have a few preliminary issues we would like to address
19 today.As you know,the Company executed and filed a
20 stipulation with Staff two days ago on Tuesday,May 8th,
21 and we do have copies of that if anybody doesn't have the
22 stipulation or the supporting testimony,but given that
23 development,we really have shifted our case today to be
24 presenting that stipulation,seeking approval of that
25 stipulation,and resolution of the one open issue in that
CSB REPORTING 7 COLLOQUY
208.890.5198
1 stipulation between the Company and Staff,so I just want
2 to tee up the fact that the case has shifted a little bit
3 and has done so quite recently,so as a result of that
4 change in the procedural status of the case,we are also
5 going to change up our witness order a little bit.
6 Instead of beginning with our policy
7 witness,which we would traditionally do,Ms.Cindy Crane
8 who is with us today,we're going to go ahead and present
9 through our witnesses Joelle Steward and Rick Link who
10 presented testimony in support of the stipulation,we'll
11 put them on first and present the stipulation,so that
12 we --everybody has a sense of what the --how the case
13 has shifted,and then we will resume our normal witness
14 order;go to Ms.Crane and the other witnesses who
15 prefiled testimony in this proceeding,so I just wanted
16 to propose that as our witness order.
17 When I do call Ms.Steward,I would ask
18 for leave to ask just a couple of direct questions just
19 so she can introduce the stipulation and provide that
20 context to the Commission,so maybe I'll pause there.I
21 have a couple of other minor procedural issues,but I
22 just want to pause there and ask if the Commission has
23 any questions or concerns about that procedure.
24 MR.KARPEN:If I could also weigh in,
25 Staff has no objection to that and we plan on presenting
CSB REPORTING -8 COLLOQUY
208.890.5198
1 our witnesses in a similar fashion.In fact,we will beO2supplyingsomedirectwrittentestimonyfromTerri
3 Carlock,our utility administrator,this morning,
4 hopefully at break,in support of that stipulation.We
5 also plan on calling Ms.Carlock as our first witness in
6 support of that stipulation and to deal with the
7 remaining issue of a cap.
8 MR.WILLIAMS:Mr.Chairman,because of
9 the late nature of the stipulation and testimony still
10 being handing out,until we have an opportunity to read
11 it,we're not sure what it's going to say and we would
12 like to reserve the opportunity when Mr.Mullins takes
13 the stand to be able to do a few questions in response to
14 the stipulation and the stipulated testimony.
15 COMMISSIONER ANDERSON:Noted.
16 Commissioner.
17 COMMISSIONER RAPER:Is there a party in
18 the room that's been a party to the proceedings that was
19 not part of the settlement negotiations?I appreciate
20 that it was only entered into by PacifiCorp and Staff.I
21 appreciate your request,Mr.Williams,and it's not my
22 ruling to make on how procedurally it's handled,but I'm
23 curious for purposes of the record,was everyone in the
24 room involved in the settlement negotiations,they just
25 simply chose not to sign the agreement?
CSB REPORTING 9 COLLOQUY
208.890.5198
1 MR.WILLIAMS:Mr.Chairman,Commissioner,O 2 I was involved and my client was involved in the
3 settlement negotiations and we chose not to sign the
4 settlement.
5 MR.BUDGE:Yes,Monsanto was involved all
6 up until the last few days,I suppose,when they got down
7 to the final agreement,but we were involved from the
8 outset and when we reached the point that we were not
9 able to sign on,we didn't participate in the final terms
10 as we see here,but we also have no objection to the
11 request made by the Company and Staff to proceed with
12 their witnesses and ask some questions relative to the
13 settlement stipulation,and we would just simply ask the
14 similar right to reserve the opportunity to have our
15 witnesses address some of that when we put them on.
16 We have seen the stipulation itself and
17 the Company's testimony in support.We haven't yet seen
18 Staff's,so as long as --
19 COMMISSIONER RAPER:Me neither.
20 MR.BUDGE:--we have the right to look
21 at that at some point in the proceedings,we're fine with
22 it.
23 MS.OLSEN:Yes,Chair and Commissioner,
24 we participated in the settlement discussions as well up
25 to the point where we couldn't come to terms as to a
CSB REPORTING 10 COLLOQUY
208.890.5198
1 particular point and then did not participate thereafter,
2 and so the final culmination was not part and parcel of
3 our participation.
4 COMMISSIONER RAPER:I appreciate the
5 comments.I just wanted to make sure there was not an
6 element of surprise to the other parties in the case.It
7 didn't appear from the record that there was,but thank
8 you,Mr.Chairman.
9 COMMISSIONER ANDERSON:Thank you.Anyone
10 else?Ms.McDowell,just to be aware,the Commission did
11 receive these and we have had an opportunity to review
12 and I'm certainly more than willing to let you put your
13 witnesses on any way you wish,so you have that
14 privilege,but let's not stray afield.We have a lot of
15 things to do.I don't want to spend too much time on
16 this component.Let's just move forward,let everybody
17 have the opportunity to ask the questions they need,but
18 we have read it and I think it's perfectly fine for you
19 to change your order.
20 MS.McDOWELL:I appreciate that,
21 Commissioner.The only other procedural issues I have
22 are minor.I wanted to let folks know,first of all,
23 that I have handed out an exhibit list just to help
24 people keep track of the exhibits that we have prefiled,
25 and also in an attempt to limit the highly confidential
CSB REPORTING 11 COLLOQUY
208.890.5198
1 information in the record,which I know is a challenge toO2maintain,we have gone ahead and withdrawn certain of our
3 highly confidential exhibits that are no longer relevant
4 to the final stipulated projects in this case,and those
5 are noted on the exhibit list by basically a strikeout,
6 so I've handed this out to all the parties.
7 If anybody has any objections to us
8 withdrawing those exhibits,we don't need to.This is
9 really designed to just make the record a little easier
10 to maintain for the Commission,so anyway,I wanted to
11 explain that and we can address concerns that people have
12 as we go if anybody has concerns about any of those
13 exhibits we're proposing to withdraw.
14 COMMISSIONER ANDERSON:Thank you,Ms.
15 McDowell,and if the Chair is getting into an area where
16 we're going to be hearing something,the obligation is
17 yours to stop me if I enter into that area,because I
18 just received this and I don't really know which pieces
19 that is.
20 MS.McDOWELL:I understand.It's just to
21 help maybe people understand where the confidentiality
22 issues are still,I think,in play a little bit.The
23 overall project costs,the cost cap is a confidential
24 piece of information in the settlement.Originally the
25 overall cost estimate was not confidential,but because
CSB REPORTING 12 COLLOQUY
208.890.5198
1 the settlement involves removing one of the projects,
2 we've always kept the individual project costs
3 confidential and because one of them is now backed out,
4 it would be possible to derive that individual project
5 cost from the project that was backed out if we have the
6 new cost estimate as a non-confidential number,so it is
7 a little awkward,but that is why that particular part of
8 the stipulation is confidential,and then that also
9 explains why certain other numbers derived from removing
10 that particular project are confidential,so we're fine
11 with people just approximating the numbers.
12 I think that is the best way to work
13 around that confidentiality issue.You know,the
14 approximation,then,does not reveal the cost of the
15 project that was withdrawn,so I hope that explains a
16 little bit and I understand it's our obligation to try to
17 monitor that as we move forward and I accept that
18 obligation.
19 COMMISSIONER ANDERSON:Thank you.
20 MS.McDOWELL:So the only other
21 preliminary matter we have to raise is that one of our
22 witnesses,Nikki Kobliha,the Company's CFO who has
23 presented testimony on the tax issues in this case,is
24 not available today,unfortunately.She is available
25 tomorrow,so we would propose to just call her out of
CSB REPORTING 13 COLLOQUY
208.890.5198
1 order tomorrow whenever there's a convenient moment to
2 put her on the stand.
3 COMMISSIONER ANDERSON:Without objection,
4 that's fine.
5 MS.McDOWELL:All right,that's great.
6 That's all I have this morning.Thank you so much.
7 COMMISSIONER ANDERSON:Thank you.Any
8 other preliminary issues to discuss?Okay,well,with
9 that,let's go ahead and start with our first witness and
10 the Applicant has the floor.
11 MS.McDOWELL:Thank you so much,
12 Commissioner.We would call Ms.Joelle Steward.
13
14 JOELLE R.STEWARD,
15 produced as a witness at the instance of Rocky Mountain
16 Power,having been first duly sworn to tell the truth,
17 was examined and testified as follows:
18
19 DIRECT EXAMINATION
20
21 BY MS.McDOWELL:
22 Q Good morning,Ms.Steward.
23 A Good morning.
24 Q For the record,can you please state and
25 spell your name?
CSB REPORTING 14 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 A My name is Joelle Steward,J-o-e-l-l-e
2 S-t-e-w-a-r-d.
3 Q By whom are you employed and what is your
4 current position?
5 A I am employed by Rocky Mountain Power and
6 I'm the vice president of regulation.
7 Q And are you the same Joelle Steward who
8 filed testimony in this proceeding beginning with your
9 direct testimony on June 30th,2018 --
10 A Yes.
11 Q --2017,sorry?
12 A Yes.I actually adopted the testimony of
13 Jeff Larson.
14 Q And then have you also proceeded to file
15 additional testimony in this case for rebuttal testimony,
16 your supplemental direct testimony,your second
17 supplemental direct testimony,and your supplemental
18 rebuttal testimony?
19 A Yes.
20 Q Do you have any additions or corrections
21 that you wish to make to your prefiled testimonies?
22 A No,I do not.
23 Q If I were to ask you the same questions
24 today that are set out in your prefiled testimony,would
25 your answers be the same?
CSB REPORTING 15 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 A Yes,they would.
2 MS.McDOWELL:Commissioner,I'd ask that
3 the prefiled testimony of Ms.Steward be spread upon the
4 record as if read.
5 COMMISSIONER ANDERSON:Thank you,Ms.
6 McDowell.Just two little side notes,on page 2 of the
7 stipulation,second paragraph,it looks like Monsanto
8 filed a petition to intervene on July 12th,2018,and I
9 don't think we've quite arrived there yet.
10 MS.McDOWELL:Yes,I was about ready to
11 get to that testimony and the stipulation,so yes,I do
12 believe that that is an error.
13 Q BY MS.McDOWELL:Ms.Steward,can you
14 clarify that on page 2 of the stipulation?
15 A Yes,on page 2 on paragraph 4,the date
16 for intervention of Monsanto should be 2017 and the date
17 for intervention of IIPA should also be 2017,not 2018.
18 COMMISSIONER ANDERSON:Thank you.
19 Without objection,we'll spread Ms.Steward's testimony,
20 direct,rebuttal,and supplemental across the record as
21 if read.
22 (The following prefiled direct of Mr.Jeffrey
23 Larson,as sponsored by Mr.Joelle Steward,and the
24 rebuttal,supplemental direct,second supplemental
O 25 direct,and supplemental rebuttal testimonies of
Ms.Joelle Steward are spread upon the record.)
CSB REPORTING 16 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 INTRODUCTION AND SUMMARY
2 Q.Please state your name,business address,and
3 current position with PacifiCorp d/b/a Rocky Mountain
4 Power ("Company").
5 A.My name is Jeffrey K.Larsen,and my business
6 address is 1407 West North Temple,Suite 310,Salt Lake
7 City,Utah 84116.I am currently employed as Vice
8 President of Regulation for Rocky Mountain Power.
9 Q.Please describe your education and professional
10 background.
11 A.I received a Master of Business Administration
12 degree from Utah State University in 1994,and a Bachelor
13 of Science degree in Accounting from Brigham Young
14 University in 1985.I have also participated in the
15 Company's Business Leadership Program through the Wharton
16 School,and an Advanced Education Program through the
17 J.L.Kellogg School of Management at Northwestern
18 University.In addition to formal education,I have also
19 attended various educational,professional and
20 electric-industry-related seminars and training programs
21 during my career at the Company.I joined the Company in
22 1985,and I have held various accounting,compliance,
23 regulatory and management positions before my current
24 position.
25 Q.Have you provided testimony in previous
17 Larsen,Di -1
Rocky Mountain Power
1 regulatory proceedings?
2 A.Yes.I have filed testimony on various matters
3 in the states of Utah,Idaho,Wyoming,California,
4 Washington,Oregon,and Nevada.
5 Q.What is the purpose of your testimony?
6 A.I explain the Company's requested ratemaking
7 treatment for the 860 MW of new wind facilities in
8 eastern Wyoming ("Wind Projects")and for the 140-mile,
9 500 kilovolt ("kV")Aeolus-to-Bridger/Anticline
10 transmission line and accompanying transmission
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
18 Larsen,Di -la
Rocky Mountain Power
1 facilities (the "Transmission Projects")for which the
2 Company is seeking approval in this Application.
3 Specifically,I describe and support the matching of the
4 costs and benefits of both the Wind Projects and the
5 Transmission Projects (the "Combined Projects")through
6 the Energy Cost Adjustment Mechanism ("ECAM").
7 Q.Please summarize the proposed ratemaking
8 treatment for the Combined Projects.
9 A.The Company is seeking approval of binding
10 ratemaking treatment for the Combined Projects to allow
11 the Company to act on a time-limited opportunity to
12 implement cost-effective generation and transmission
13 facilities while minimizing the impact on customer rates.
14 The Combined Projects are inextricably linked-the
15 Transmission Projects relieve existing congestion in
16 eastern Wyoming,and the Wind Projects will rely on the
17 new Transmission Projects for interconnection and allow
18 the Company to realize the benefits of production tax
19 credits ("PTCs")and zero-fuel-cost-energy.
20 The proposed ratemaking treatment,known as the
21 Resource Tracking Mechanism ("RTM"),is designed to
22 capture customer benefits and match those benefits with
23 the costs of the Combined Projects.The RTM would
24 primarily operate until the costs and benefits of the
25 Combined Projects are fully included in base rates
19 Larsen,Di -2
Rocky Mountain Power
1 through a general rate case.The RTM would be included as
2 a component of the ECAM.Once the full costs and benefits
3 are included in base rates,only the incremental
4 fluctuations associated with production levels of energy
5 and PTCs would continue to be tracked in the ECAM,as
6 they are today,since these are entirely dependent on the
7 variable output of the Wind Projects.The Company would
8 begin deferring the costs and benefits associated with
9 each new facility in the month it goes into service.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
20 Larsen,Di -2aRockyMountainPower
1 Q.As the Combined Projects come into service,
2 what are the annual,estimated deferral balances that
3 would flow through the RTM?
4 A.As described more fully later in my testimony
5 and exhibits,the Company is projecting the initial
6 annual revenue requirement impact for the years 2020 to
7 2023 to be in the range of ($1.0)million to $5.4 million
8 in Idaho,as shown in Table 1 of Exhibit No.27.The
9 Company will capture the impacts of the Combined Projects
10 through the RTM until they are included in base rates.
11 Q.What are the differences between your
12 calculation of revenue requirement impacts in Table 1 and
13 Company witness Mr.Rick T.Link's analysis of revenue
14 requirement savings from the Combined Projects?
15 A.Mr.Link conducted a revenue requirement
16 differential analysis,and my analysis is a revenue
17 requirement calculation based on his information.As
18 such,my analysis shows the annual,near-term revenue
19 requirement impacts of the large capital investments,
20 while Mr.Link's economic analysis estimates the change
21 in nominal revenue requirement,accounting for system
22 costs that would have otherwise been incurred if the
23 Combined Projects were not pursued.Mr.Link also
24 calculates the present-value change in nominal revenue
25 requirement due to the Combined Projects,which shows net
21 Larsen,Di -3
Rocky Mountain Power
1 customer benefits over time.In other words,Mr.Link's
2 testimony demonstrates that over time customer rates will
3 be lower with the Combined Projects than without.
4 Q.What is the potential rate impact to customers
5 of the Combined Projects?
6 A.In the first full year of operation (2021),the
7 rate impact to customers is less than 1.9 percent.While
8 this percentage change reflects the year-one impact to
9 customers,it does not fully reflect the value of the
10 Combined Projects due to costs avoided over
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
22 Larsen,Di -3aRockyMountainPower
1 time.Table 3 of Mr.Link's testimony shows the present
2 value savings calculated through 2050 to be $137 million.
3 This demonstrates that although there is an initial
4 increase in cost,the lifetime savings of the Combined
5 Projects are significant.
6 Q.Is the RTM proposed here the same mechanism the
7 Company proposes in the concurrently filed application
8 for an order approving non-traditional binding ratemaking
9 treatment related to the wind repowering project?
10 A.Yes.The Company proposes to use the RTM as a
11 component of the ECAM for both the Combined Projects and
12 the wind repowering project addressed in the Company's
13 concurrent filing.The Company proposes slight
14 differences in the treatment of the deferral balances,
15 applying the surcharge cap to wind repowering only.
16 BINDING RATEMAKING AUTHORITY
17 Q.Does the Idaho Public Utilities Commission have
18 binding ratemaking authority?
19 A.Yes.Idaho Code §§61-541(2)provides that a
20 public utility that proposes to construct,purchase,or
21 make major additions to an electric generation facility
22 or transmission facility:
23 [M]ay file an application with the commission
for an order specifying in advance the
24 ratemaking treatments that shall apply when the
costs of the proposed facility are included in
25 the public utility's revenue requirements for
23 Larsen,Di -4
Rocky Mountain Power
1 ratemaking purposes.
2 The "requested ratemaking treatments may
3 include nontraditional ratemaking treatments or
4 nontraditional cost recovery mechanisms."The Company's
5 request for binding ratemaking treatment fairly and
6 reasonably balances the interests of customers and
7 satisfies each of the five requirements listed under the
8 statute outlined in the Application,as explained by the
9 Company's witnesses.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
24 Larsen,Di -4a
Rocky Mountain Power
1 Moreover,the Company's proposed ratemakingO2treatmentensuresthatratesreflectboththecostsand
3 the benefits of the Combined Projects and is consistent
4 with established Commission precedent.Binding ratemaking
5 treatment is warranted because of the magnitude of the
6 proposed investment and the customer benefits resulting
7 from the Combined Projects.
8 Q.Why is the Company seeking approval of Binding
9 Ratemaking Treatment for the Combined Projects?
10 A.The Combined Projects meet the statutory
11 requirements regarding the public interest,and the
12 Company's proposed ratemaking addressed in this testimony
13 reflects the "nontraditional ratemaking treatments or
14 nontraditional cost recovery mechanisms"contemplated by
15 the statute.The Combined Projects themselves are an
16 innovative and nontraditional project intended to take
17 advantage of the time-limited opportunity to obtain
18 one-hundred percent PTC benefits for customers.The
19 Combined Projects are inextricably linked in that the
20 Wind Projects will rely on the new Transmission Projects
21 for interconnection and allow the Company to realize the
22 benefits of PTCs and zero-fuel-cost energy that support
23 the economics of the Transmission Projects.The Company's
24 request for approval pursuant to Idaho Code §§61-541(2)
25 provides interested parties and the Commission the
25 Larsen,Di -5
Rocky Mountain Power
1 opportunity to meaningfully review,before construction,
2 whether the Combined Projects and expenditures are
3 reasonable,prudent,and in the public interest.The
4 Company's proposed RTM is a nontraditional approach that
5 will properly match the timing of the benefits and costs
6 of this unique and time-constrained opportunity.Because
7 the Combined Projects are in the public interest,binding
8 ratemaking treatment is appropriate and reasonable.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
26 Larsen,Di -5a
Rocky Mountain Power
1 RESOURCE TRACKING MECHANISM
2 Q.Why are you requesting approval of the RTM?
3 A.The RTM is a nontraditional mechanism that
4 advances the public interest by fairly balancing the
5 interests of customers and shareholders regarding the
6 ratemaking impacts of the Combined Projects.As the other
7 Company witnesses discuss,the Combined Projects provide
8 a net benefit to customers through incremental,
9 zero-fuel-cost wind generation,additional PTCs,and
10 wheeling revenues,all of which help to mitigate
11 near-term costs.Without the RTM,a portion (90 percent)
12 of the zero-fuel-cost energy from the Wind Projects would
13 automatically flow through the ECAM,while 10 percent of
14 these benefits and the costs associated with the
15 investments and their operation would not be captured in
16 rates and would flow to shareholders;one-hundred percent
17 of the PTCs would flow through the ECAM to customers.The
18 RTM seeks to align the costs and benefits so that
19 customers and shareholders are treated fairly.
20 Q.Please describe the mechanics of the RTM in
21 conjunction with the ECAM.
22 A.The ECAM will track the actual energy and PTCs
23 produced from the wind facilities compared to the amount
24 included in base rates.Any variances of energy
25 production impacts Net Power Costs ("NPC")and PTCs.The
27 Larsen,Di -6RockyMountainPower
1 changes in NPC are shared 90 percent by customers and 10
2 percent by Company shareholders,and PTCs are tracked
3 dollar-for-dollar with no shareholder sharing.The RTM
4 would pass that 10 percent NPC value of the Wind Projects
5 back to customers,along with the associated costs
6 incurred by the Company to provide these benefits.Absent
7 the RTM,the ECAM would automatically pass through all
8 new PTCs and 90 percent of the value of the energy to
9 customers,while Company shareholders would bear all the
10 costs until the
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
28 Larsen,Di -6a
Rocky Mountain Power
1 next general rate case.O 2 To fully match the costs with the benefits of
3 the Combined Projects and pass these benefits entirely to
4 customers,the Company proposes implementing the RTM as a
5 component of the ECAM.Upon completion of each component
6 of the Combined Projects,the Company will begin monthly
7 deferrals of the associated costs and benefits in the
8 ECAM balancing account,which operates on a calendar-year
9 basis.On April 1 each year,the Company will file the
10 ECAM deferral balance from the prior calendar year,to be
11 included in rates beginning June 1,consistent with the
12 current ECAM schedule.The RTM review would continue on
13 the same schedule as a component of the ECAM each year
14 until the costs and benefits are fully included in base
15 rates as part of a general rate case.After a rate case,
16 only the NPC and PTC associated with the variability of
17 wind energy production will continue to be tracked in the
18 ECAM,as is done today.
19 Q.Why is it important to incorporate the RTM in
20 the ECAM?
21 A.Incorporating the RTM in the ECAM helps match
22 the production benefits of the wind facilities,which
23 will automatically flow,in part,through the ECAM,with
24 the costs of the Combined Projects.As the Combined
25 Projects are completed and placed into service,the RTM
29 Larsen,Di -7
Rocky Mountain Power
1 will calculate the monthly revenue requirement associatedO2withtheCombinedProjectsanddeferitwiththe
3 incremental benefits,matching costs with benefits.Also,
4 by incorporating the RTM as a component of the ECAM,
5 there is only one tariff and a single line item on
6 customer bills.
7 Q.What costs and revenues will be incorporated in
8 the RTM?
9 A.The deferral for the Combined Projects will
10 include the following revenue requirement
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
30 Larsen,Di -7a
Rocky Mountain Power
1 components:O 2 o Plant revenue requirement,consisting of:
3 o Capital investment
4 o Accumulated Depreciation Reserve ("ADR")
5 o Accumulated Deferred Income Tax ("ADIT")
6 o Operations and Maintenance Expense ("O&M")
7 o Depreciation expense
8 o Property taxes
9 o Wyoming Wind Tax
10 o NPC savings
11 o Wheeling Revenues
12 o PTCs.
13 These items are summarized in Exhibit No.26.The Company
14 will calculate the RTM deferral as the difference between
15 the value included in base rates for these items and the
16 new value taking into account the costs and benefits of
17 the Combined Projects as they are placed into service.
18 REVENUE REQUIREMENT COMPONENTS OF RTM
19 Q.Please describe how the RTM will track rate
20 base components,which include the capital investment,
21 ADR,and ADIT.
22 A.After each wind and transmission facility under
23 construction is placed into service,the Company will
24 defer the full amount of the capital investment,ADR,and
25 ADIT related to that facility in the RTM.Once the
31 Larsen,Di -8
Rocky Mountain Power
1 Company has included some or all of the Combined ProjectsO2inbaseratesthroughafuturegeneralratecase,the
3 amount in rates
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
32 Larsen,Di -8a
Rocky Mountain Power
1 will become the base plant balances that in the
2 subsequent annual RTM filings will be subtracted from the
3 capital investment.The Company will use the net plant
4 balance described above to calculate a return on
5 investment using the most recent Commission-approved cost
6 of capital and income tax rate.
7 Q.Please describe how the RTM will track
8 depreciation expense.
9 A.The Company will include depreciation expense
10 in the RTM deferral as the actual monthly
11 plant-in-service balances associated with the Combined
12 Projects,less the wind and transmission base
13 plant-in-service balance,multiplied by the current
14 depreciation rates.Until a general rate case is filed,
15 no depreciation expense associated with the Combined
16 Projects is reflected in base rates,so the full amount
17 would be included in the RTM.
18 Q.How will the depreciation expense be
19 calculated?
20 A.The current depreciation rates will be applied
21 to the gross electric plant in service ("EPIS")balance,
22 associated with the Combined Projects,to calculate the
23 depreciation expense.
24 Q.How will the RTM reflect revenue from
25 third-party transmission customers?
33 Larsen,Di -9
Rocky Mountain Power
1 A.Since the Transmission Projects will beO2includedintheCompany's Open Access Transmission Tariff
3 ("OATT"),part of the costs will be recovered from
4 third-party transmission customers,which is treated as a
5 revenue credit to retail customers.Exhibit Nos.27 and
6 28 assume that 12 percent of the transmission revenue
7 requirement will be paid by third-party transmission
8 customers and is included as an offset in the RTM.This
9 percentage will be updated using the most current
10 information at the time of each RTM filing.
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
34 Larsen,Di -9a
Rocky Mountain Power
1 Q.How will the RTM reflect incremental O&MO2expense?
3 A.As facilities that are part of the Combined
4 Projects are placed into service,the Company will
5 include the actual O&M expense associated with the
6 facilities in the RTM deferral.
7 Q.How will the RTM reflect property taxes?
8 A.The Company will calculate property taxes
9 associated with the Combined Projects by taking the
10 monthly average of the capital investment less ADR
11 included in the RTM deferral,multiplied by the average
12 property tax rate from the Company's last general rate
13 case.Exhibit No.29 provides an example of the property
14 tax calculation.
15 Q.How will the RTM reflect Wyoming wind taxes?
16 A.The Company will calculate the Wyoming wind tax
17 by taking the generation associated with the Wind
18 Projects that are subject to the Wyoming wind tax,
19 multiplied by the Wyoming wind tax rate.
20 NET POWER COST AND PTC BENEFITS IN THE RTM
21 Q.Please explain the calculation of the NPC
22 benefits in the RTM.
23 A.The Combined Projects will add significant
24 additional zero-fuel-cost energy to the system,reducing
25 total NPC.Under the sharing bands of the ECAM,90
35 Larsen,Di -10RockyMountainPower
1 percent of the NPC benefits of the Wind Projects will beO2creditedtocustomers,with 10 percent assigned to the
3 Company.Under the RTM,the Company is proposing to pass
4 100 percent of the NPC benefits of the Wind Projects to
5 customers through a credit equal to the amount of the NPC
6 benefits that would otherwise be absorbed by the sharing
7 band,or 10 percent.
8 The Company will value the energy from the Wind
9 Projects using a monthly market price less wind
10 integration costs,and the RTM will pass 10 percent of
11 that value
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
36 Larsen,Di -10a
Rocky Mountain Power
1 through to customers.The calculation is shown on ExhibitO2No.29.The RTM will continue to credit the full
3 incremental NPC benefits associated with the Wind
4 Projects until the Wind Projects are included in base
5 rates.
6 Q.What market price will the Company use to value
7 the energy?
8 A.The monthly Four Corners heavy load hour
9 ("HLH")and light load hour ("LLH")market price will be
10 used,depending on the time of generation.Additionally,
11 the market price will be reduced by the wind integration
12 costs from the most recent integration study,which
13 currently would be from the Company's 2017 Integrated
14 Resource Plan.
15 Q.Please explain the calculation of the PTCs.
16 A.Currently,the Internal Revenue Service ("IRS")
17 rate for PTCs is $24 per megawatt-hour and PTCs are
18 generally applicable for a period of 10 years after a
19 wind resource is operational.The PTC rate is applied to
20 the actual megawatt-hours of generation from the eligible
21 wind turbines.This produces a tax credit that can be
22 used to offset the Company's income tax expense under IRS
23 guidelines.To derive the revenue requirement value of
24 the tax credit,the pre-tax value must be grossed-up by
25 the Company's tax gross-up rate.The Company will use the
37 Larsen,Di -11
Rocky Mountain Power
1 tax gross-up rate from its most recent general rate case
2 to calculate the value of the PTCs from the Wind
3 Projects.Since the PTCs are already tracked 100 percent
4 in the ECAM per Order No.33440 in Case No.PAC-E-15-09
5 they won't need to be included in the RTM calculation.
6 Q.Do the base rates that are currently in place
7 include PTCs for the existing wind facilities?
8 A.Yes.A value based on the generation from the
9 Company's existing wind facilities during the last
10 general rate case test period is currently included in
11 base rates and
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
38 Larsen,Di -lla
Rocky Mountain Power
1 tracked in the ECAM.The Company is not proposing to stop
2 tracking the PTC variance between base rates and actual
3 PTCs in the ECAM,and is not proposing to change the
4 amount included in base rates until the next general rate
5 case.
6 RTM CALCULATION AND STRUCTURE
7 Q.Have you prepared an exhibit that illustrates
8 the calculation and structure of the RTM on a
9 year-by-year basis?
10 A.Yes.Page 2 of Exhibit No.27 provides an
11 illustrative example of the calculation of the RTM on an
12 annual basis.The annual amounts will be the sum of the
13 monthly amounts shown in Exhibit No.28,and the
14 individual lines are described as part of that exhibit.
15 The Company will address variances in actual costs from
16 the projections in this filing at the time the Company
17 seeks rate recovery.
18 Q.Please explain Exhibit No.28.
19 A.Exhibit No.28 is an example of the RTM's
20 monthly calculation.The RTM will be adjusted after a
21 general rate case to exclude amounts that are recovered
22 as part of base rates in the rate case to assure against
23 double-recovery.For items partially recovered in base
24 rates,such as capital investments included for part of
25 the test period,the portion included in the test period
39 Larsen,Di -12
Rocky Mountain Power
1 will be removed as of the effective date of the generalO2ratecase.Page 5 of Exhibit No.28 includes an overview
3 of the total plant revenue requirement,net power cost,
4 PTC,and the deferral balances.
5 Once per year on a calendar-year basis,the
6 Company will sum the monthly RTM revenue requirement
7 entries to prepare the annual RTM adjustment to be
8 included in the Idaho ECAM application for filing with
9 the Commission on April 1,with a rate effective date of
10 June 1.
11 /
12
O 13 /
i
14
15 /
16
17
18
19
20
21
22
23
24
25
40 Larsen,Di -12a
Rocky Mountain Power
1 Q.How will the Company calculate rates to creditO2orrecoverRTMbalances?
3 A.The Company is proposing that the allocation
4 factors used in the RTM match the allocation factors used
5 in the calculation of the ECAM.Also,the Company
6 proposes to use the same class allocation and rate design
7 as used for the annual ECAM filing.
8 INTER-JURISDICTIONAL COST ALLOCATION
9 Q.How will the Company allocate the investment in
10 the Combined Projects to the state jurisdictions
11 PacifiCorp serves?
12 A.Currently,the Company's investments in wind
13 generation and transmission resources are treated as
14 system resources under the approved 2017 Protocol
15 Allocation Agreement.That approved methodology will
16 continue for ratemaking purposes through 2019.The same
17 treatment will apply to new investments that occur in
18 that period.After that time period,the then-applicable
19 allocation methodology approved by the Commission would
20 govern.
21 The Company's analysis demonstrates that the
22 Combined Projects deliver system benefits,and the
23 Company believes that the Combined Projects should
24 continue to be allocated across the six-state service
25 territory on a system basis unless there is an agreement
41 Larsen,Di -13
Rocky Mountain Power
1 through the Multi-State Process to do otherwise.O 2 CONCLUSION
3 Q.Please summarize your testimony.
4 A.To match the investments and operational costs
5 with the benefits of the Combined Projects until the
6 costs and benefits are fully included in base rates
7 through a general rate case,the Company proposes to
8 implement the RTM as a component of the existing ECAM.
9 Matching the costs and benefits through the RTM is fair
10 to customers and
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
42 Larsen,Di -13a
Rocky Mountain Power
1 shareholders,and is consistent with the Commission's
2 authority to approve binding ratemaking treatment for
3 non-traditional cost recovery mechanisms.The RTM would
4 become a component of the ECAM until the costs and
5 benefits are fully included in base rates through a
6 general rate case,at which point the ECAM would continue
7 to track variances in NPC and PTC.
8 Q.What is your recommendation to the Commission?
9 A.I recommend that the Commission approve the
10 Combined Projects and the Company's proposal for the
11 binding ratemaking treatment for the Combined Projects.
12 Approval will provide certainty to the Company and enable
13 it to move forward with the Combined Projects.
14 Q.Does this conclude your direct testimony?
15 A.Yes.
16
17
18
19
20
21
22
23
24
25
43 Larsen,Di -14
Rocky Mountain Power
1 Q.Please state your name,business address,andO2currentpositionwithPacifiCorpd/b/a Rocky Mountain
3 Power ("Company").
4 A.My name is Joelle R.Steward.My business
5 address is 1407 West North Temple,Suite 330,Salt Lake
6 City,Utah 84116.My title is Vice President of
7 Regulation for Rocky Mountain Power.
8 QUALIFICATIONS
9 Q.Please describe your education and professional
10 background.
11 A.I have a Bachelor of Arts degree in Political
12 Science from the University of Oregon and a Masters of
13 Public Affairs from the Hubert Humphrey Institute of
14 Public Policy at the University of Minnesota.Between
15 1999 and March 2007,I was employed as a Regulatory
16 Analyst with the Washington Utilities and Transportation
17 Commission.I joined the Company in March 2007 as the
18 Regulatory Manager responsible for all regulatory filings
19 and proceedings in Oregon.From February 2012 through May
20 2016,I was a Director in charge of the work for the cost
21 of service,pricing,and regulatory operations groups for
22 the Company.In 2016,I became the Director of Rates and
23 Regulatory Affairs and added responsibilities for
24 regulatory affairs for Rocky Mountain Power.In November
25 2017,I assumed my current position as Vice President of
44 Steward,Di-Reb -1RockyMountainPower
1 Regulation for Rocky Mountain Power.O 2 Q.Have you testified in previous regulatory
3 proceedings?
4 A.Yes.I have filed testimony in proceedings
5 before the public utility commissions in Idaho,Oregon,
6 Utah,Wyoming,and Washington.
7 Q.Are you adopting the direct testimony of Mr.
8 Jeffrey K.Larsen in this case?
9 A.Yes.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
45 Steward,Di-Reb -la
Rocky Mountain Power
1 PURPOSE AND SUMMARY OF REBUTTAL TESTIMONYO2Q.What is the purpose of your rebuttal testimony?
3 A.In support of the Company's application to the
4 Idaho Public Utilities Commission ("Commission")
5 requesting Certificates of Public Convenience and
6 Necessity ("CPCNs")and binding ratemaking treatment for
7 wind and transmission projects ("Combined Projects"),I
8 respond to regulatory policy issues raised in the direct
9 testimonies of Monsanto witnesses Ms.Katie E.Iverson
10 and Mr.Nicholas L.Phillips,Idaho Irrigation Pumpers
11 Association,Inc.("IIPA")witness Mr.Anthony J.Yankel,
12 and Commission Staff ("Staff")witnesses Mr.Randy Lobb
13 and Mr.Richard Keller.
14 Q.What are the key issues you address in your
15 rebuttal testimony?
16 A.I address the following key issues:
17 o The reasonableness of allowing full
18 recovery of the prudent costs of the
19 Combined Projects,including a return on
20 investment.
21 o How the Company's proposed Resource
22 Tracking Mechanism ("RTM")fairly and
23 efficiently allows costs and benefits to
24 be tracked through rates on a temporary
25 basis until the next general rate case.
46 Steward,Di-Reb -2
Rocky Mountain Power
1 o The reasons why the approval conditionsO2proposedbythepartiesareinappropriate
3 and unreasonable.
4 Q.Please summarize your testimony.
5 A.The Company's application for CPCNs and binding
6 ratemaking is reasonable and in the public interest.The
7 Combined Projects are the least cost alternative to meet
8 customers'needs today and into the future.As such,the
9 higher standard for approval of the Combined Projects
10 proposed by parties is inappropriate and unwarranted.The
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
47 Steward,Di-Reb -2a
Rocky Mountain Power
1 Company has issued a request for proposals for the new
2 wind resources ("2017R RFP"),and is obtaining
3 engineering,procurement and construction ("EPC")bids to
4 ensure competitive costs for the Combined Projects.The
5 Company has also actively managed and mitigated project
6 risks within the Company's control.
7 The RTM is an interim mechanism to provide all
8 benefits of the Combined Projects to customers until the
9 resources are incorporated into rates in a general rate
10 case.The only "benefit"to the Company is the
11 opportunity to recover its reasonable and prudent costs,
12 like any other resource investment.
13 RESOURCE TRACKING MECHANISM
14 Q.What should the Commission consider when
15 determining whether to grant the requested CPCNs and
16 approve the proposed RTM?
17 A.For both the CPCNs and the RTM,the Commission
18 must determine that the Combined Projects are in the
19 public interest and the RTM reasonably balances the
20 interests of the Company and customers.This
21 determination is supported by the results of the
22 Company's 2017 Integrated Resource Plan,and Company
23 witness Mr.Rick T.Link's direct and rebuttal testimony
24 explaining why the Company selected the Combined Projects
25 as the least-cost,least-risk option to provide safe and
48 Steward,Di-Reb -3
Rocky Mountain Power
1 reliable electric service to customers.The CombinedO2Projectsprovidesubstantialbenefitstocustomers,and
3 these benefits should be matched in rates with project
4 costs.The proposed RTM combined with a future rate case
5 is the best way to achieve that goal.
6 Q.Why is the RTM necessary?
7 A.The RTM is designed to match all costs and
8 benefits over a short period of time.The RTM will allow
9 the Company to track costs and deliver benefits to
10 customers until the
11 /
12
I
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
49 Steward,Di-Reb -3a
Rocky Mountain Power
1 next rate case,while also allowing the Company to
2 include the Combined Projects in base rates in a single
3 general rate case filing.The RTM enables the Company to
4 align near-term cost drivers into one general rate case,
5 rather than rate cases over a multiple-year period.
6 Without the RTM,a portion (90 percent)of the zero-fuel
7 cost energy and all of the production tax credits ("PTC")
8 would flow to customers through the Energy Cost
9 Adjustment Mechanism ("ECAM")without recovery of the
10 costs that enable those benefits.
11 Q.Is the RTM intended to provide rate recovery
12 over the life of the new resources?
13 A.No.The RTM is a short-term tracking mechanism
14 that matches all benefits and costs until they are
15 included in rates in the next general rate case.The RTM
16 is not intended to be a permanent mechanism in place for
17 the life of the Combined Projects.
18 Q.Does Ms.Iverson support binding ratemaking
19 treatment and tracking benefits and costs of the Combined
20 Projects through the RTM?
21 A.No.Ms.Iverson argues that because the
22 Combined Projects are "discretionary,uneconomical and
23 pose unacceptable risks to customers,"the Company's
24 proposed ratemaking treatment should be denied.(Iverson
25 Direct,page 6,lines 9-21.)Ms.Iverson also claims that
50 Steward,Di-Reb -4
Rocky Mountain Power
1 tracking both the wind repowering project and theO2CombinedProjectsthroughtheRTMwouldmakemonitoring
3 the impacts of two projects difficult,if not impossible.
4 (Iverson Direct,page 8,lines 7-10.)
5 Q.Do you agree with Ms.Iverson that the Combined
6 Projects are "discretionary,uneconomical and pose
7 unacceptable risks to customers,"so the RTM should be
8 denied?
9 A.No.The proposed resources are a least-cost
10 opportunity to fill both a near-term and
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
51 Steward,Di-Reb -4a
Rocky Mountain Power
1 long-term need,so they should not be dismissed as
2 discretionary.The Company's economic analysis also shows
3 that customer benefits substantially outweigh the costs
4 and that forgoing the time-sensitive opportunity to
5 acquire the Combined Projects will result in higher
6 customer costs in the long-term.In addition,the
7 investment in the Combined Projects does not impose a
8 greater risk on customers than typical utility
9 investments.Setting a different or higher standard for
10 what benefits must be achieved,as effectively proposed
11 by Monsanto witnesses,is unwarranted and inappropriate.
12 Moreover,in light of the off-ramps built into
13 the Company's development schedule,approval of the
14 resource decision in this proceeding does not lock in the
15 decision to proceed if circumstances change before the
16 final notices to proceed,as discussed by Company witness
17 Mr.Chad A.Teply.Accordingly,a higher approval
18 standard or punitive conditions are not appropriate.The
19 proposed RTM is consistent with the statutory
20 requirements for binding ratemaking treatment set forth
21 in Idaho Code §61-541.
22 Q.Second,do you agree with Ms.Iverson that
23 tracking both projects in the RTM would make monitoring
24 the impact of the Combined Projects difficult?
25 A.No.The Company's accounting system currently
52 Steward,Di-Reb -5
Rocky Mountain Power
1 tracks capital,operation and maintenance costs,net
2 power costs,and PTC benefits by plant.The Company can
3 readily separate the wind repowering project from the
4 Combined Projects in the RTM.There is no reason to
5 create another tracking mechanism,or develop the
6 separate tariff proposed by Ms.Iverson.(Iverson Direct,
7 page 7,lines 9-14.)
8 Q.Are there other witnesses who testify on the
9 RTM?
10 A.Yes.Staff witness Mr.Lobb supports the
11 concept and purpose of the RTM.(Lobb
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
53 Steward,Di-Reb -5a
Rocky Mountain Power
1 Direct,page 7,lines 20-25.)However,he recommends thatO2therevenuerequirementfortheCombinedProjects
3 continue to be tracked in the RTM even after it is
4 included in base rates because the Combined Projects will
5 have a declining net rate base balance.(Lobb Direct,
6 page 9,lines 4-11.)
7 Q.Do you believe it is appropriate to make the
8 RTM permanent and adjust for the declining balance of the
9 Combined Projects?
10 A.No.While the net rate base balance of the
11 Combined Projects may decline over time,that is true of
12 other large investments in the Company's rate base and
13 none have ever been tracked separately.For example,Lake
14 Side 2 is currently being recovered through the ECAM
15 without accounting for changes to its annual revenue
16 requirement.
17 The balance of the Company's total rate base
18 generally increases over time,due to capital maintenance
19 and system improvements.Isolating the Combined Projects
20 and separately tracking their net rate base balance while
21 ignoring the total net rate base balance does not
22 accurately reflect the Company's cost of service,and
23 would unfairly harm the Company.This could actually
24 drive the need for more frequent rate cases,as opposed
25 to the RTM's intended purpose as a near-term tool to
54 Steward,Di-Reb -6
Rocky Mountain Power
1 decrease the frequency of rate cases.Mr.Lobb's proposalO2alsodoesnotexplicitlystatehowlongtheRTMshould
3 track the revenue requirement of the Combined Projects,
4 but presumably it would be over the life of the
5 resources,which are between 30 and 55 years.This would
6 be an unprecedented rate treatment for a project.
7 PROPOSED CONDITIONS FOR APPROVING THE COMBINED PROJECTS
8 Q.Have the parties raised concerns about risks
9 with the Combined Projects?
10 A.Yes.The parties raise similar concerns about
11 the risks of the Combined Projects.
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
55 Steward,Di-Reb -6a
Rocky Mountain Power
1 However,Mr.Keller from Staff summarized these risksO2intotwocategories:those within the Company's control,
3 and those over which the Company has no control.(Keller
4 Direct,page 4,lines 5-11.)Company witnesses Mr.Link,
5 Mr.Teply,and Mr.Rick A.Vail,explain the steps the
6 Company is taking to manage each of the risks within the
7 Company's control.
8 Q.Is it appropriate to cap cost recovery of
9 capital investment estimated in the initial filing as
10 proposed by Monsanto witness Mr.Phillips?(Phillips
11 Direct,page 25,lines 14-20.)
12 A.No.Mr.Phillips proposes to cap (reduce)cost
13 recovery for the Combined Projects to match customer
14 benefits and shareholder returns under the low gas and no
15 CO2 scenario in the initial filing.This cap
16 automatically disallows approximately 20 percent of the
17 project costs-even if those costs are prudently incurred.
18 The recommendation is unjustified because,as described
19 above,the Combined Projects are not discretionary or
20 unneeded investments.The recommendation is also
21 punitive,especially given the significant customer
22 benefits the Combined Projects provide.
23 Q.Mr.Phillips claims that shareholders are
24 receiving benefits associated with the investment,which
25 should be equally shared with customers.Please respond.
56 Steward,Di-Reb -7
Rocky Mountain Power
1 A.The recovery of capital costs is not a
2 "benefit,"it is an integral component of the regulatory
3 compact.Indeed,a basic premise of ratemaking,is that
4 "a capital-attracting rate of profit is here considered a
5 part of the necessary cost of service."1 The cost of
6 capital is no different than any other prudent cost
7 recoverable in rates if incurred to
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24 1 James C.Bonbright,Albert L.Danielsen,&David R.Kamerschen,
Principles of Public Utility Rates,112 (2d ed.Public Utilities
25 Reports 1988).
57 Steward,Di-Reb -7aRockyMountainPower
1 provide utility service.It is inaccurate to say that
2 shareholders are receiving a greater benefit than
3 customers based on the fact that shareholders recover the
4 costs incurred to provide utility service.
5 The Company's proposal fairly matches the
6 benefits with the costs of the Combined Projects.Mr.
7 Phillips'proposal,on the other hand,"flips the
8 regulatory compact"to justify taking all the benefits of
9 the Combined Projects,while capping and disallowing the
10 costs the Company may recover.
11 Q.Does Mr.Phillips propose additional conditions
12 to "flip the regulatory compact"?(Phillips Direct,page
13 3,lines 20-21.)
14 A.Yes.Mr.Phillips also recommends that the
15 Company guarantee PTCs at the current 35 percent tax rate
16 based on a fixed net capacity factor for the life of the
17 wind projects.This is unreasonable for various reasons,
18 including the fact that PTCs are only available for the
19 first 10 years of the Wind Projects'much longer life.
20 Also,as Mr.Keller notes,tax rates are beyond the
21 Company's control.
22 Q.What risk is the Company assuming with respect
23 to the PTCs?
24 A.As discussed by Company witness Cindy Crane,
25 the Company accepts the risks that are within the
58 Steward,Di-Reb -8
Rocky Mountain Power
1 Company's control related to PTC qualification.The ECAMO2currentlyassuresthat100percentofPTCsarepassed
3 onto customers,and the Company's proposal in this
4 proceeding is to continue with that same approach.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
59 Steward,Di-Reb -8a
Rocky Mountain Power
1 Q.Mr.Phillips and Mr.Yankel argue that theO2CombinedProjectsareinequitablebecausetheCompany's
3 shareholders will receive substantially more benefits
4 than customers.(Phillips Direct,page 10,lines 5-12;
5 Yankel Direct,page 8,lines 6-16.)Do you agree with
6 this characterization?
7 A.No.The purported shareholder benefit is the
8 capital cost incurred to fund the Combined Projects,
9 which is no more of a shareholder "benefit"than the
10 recovery of any other cost associated with providing
11 service.
12 The Company has shown it can deliver additional
13 generation to customers at a lower cost than the
14 alternatives,resulting in a net benefit to customers.
15 The customer benefits assume that shareholders recover
16 the full cost of the Combined Projects investment,
17 including capital costs.
18 After the next rate case,the prudent costs and
19 benefits of the Combined Projects will be included in the
20 Company's full revenue requirement.However,there is no
21 guarantee the Company will recover its full cost of
22 service related to the investment.The Company must
23 prudently manage its costs to achieve the full return
24 allowed by the Commission.
25 Further,Mr.Phillips'calculation assumes the
60 Steward,Di-Reb -9
Rocky Mountain Power
1 wind resources will be the Company's wind benchmarks.
2 However,the final resources are being selected through
3 the competitive solicitation that is open to a number of
4 structures,e.g.,benchmark EPC,market build transfer,
5 or market power purchase.
6 Q.Does Mr.Phillips propose additional
7 conditions?
8 A.Yes.Mr.Phillips proposes that the Commission
9 cap the future level of operation and maintenance costs
10 ("O&M")and capital expenditures to maintain the levels
11 assumed
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
61 Steward,Di-Reb -9a
Rocky Mountain Power
1 in the Company's economic analysis.(Phillips Direct,
2 page 34,lines 9-15.)
3 Q.Is Mr.Phillips'proposed cost cap reasonable?
4 A.No.In any forecast of the future,it is
5 unlikely that all assumptions will be completely
6 accurate.Some assumptions will be low and some will be
7 high.Because of these variances,the Company's modeling
8 includes a range of assumptions that can be used to
9 assess the impact if a particular variable differs from
10 the baseline.The Company's application requests
11 Commission review to verify the reasonableness of the
12 Company's assumptions and determine that customers will
13 benefit as a result of the Combined Projects.If
14 approved,the Company should recover its full cost of
15 service related to the Projects.
16 Moreover,as described in the testimony of
17 Company witnesses Mr.Teply and Mr.Vail,the Company has
18 strategies in place,based on its experience,to mitigate
19 the risks of construction cost over-runs and schedule
20 delays and those items that are within the Company's
21 control.
22 Q.Has the Commission previously approved resource
23 acquisitions based on their economic benefits to
24 customers?
25 A.Yes.The Commission has allowed cost recovery
62 Steward,Di-Reb -10
Rocky Mountain Power
1 for the Cholla,Craig and Hayden,and Chehalis power
2 plants.All of these were economic opportunities and in
3 every case,the Commission determined these facilities
4 were in the best interest of customers,i.e.,acquiring
5 these resources provided net savings to customers.
6 Although there were customer risks with the resource
7 decision in each case,the Commission allowed full
8 recovery.Consistent with this precedent,if the
9 Commission determines the Combined Projects provide
10 customer benefits,based on what is known today,then it
11 should allow
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
63 Steward,Di-Reb -10a
Rocky Mountain Power
1 full recovery of the costs associated with the CombinedO2Projects.
3 Q.Why is Mr.Phillips'proposal unreasonable in
4 this case?
5 A.The Company has shown it can deliver additional
6 generation and transmission resources to customers at a
7 lower cost than the alternatives,resulting in a net
8 benefit to customers.The customer benefits assume that
9 shareholders recover the full cost of the Combined
10 Projects investment,including O&M and capital costs.
11 After the next rate case,the prudent costs and benefits
12 of the Combined Projects will be included in the
13 Company's rate base,but there is no guarantee the
14 Company will recover its full cost of service related to
15 this investment.The Company must prudently manage all of
16 its costs to achieve the full return allowed by the
17 Commission.
18 Q.Do you agree with Mr.Lobb's recommendation
19 that the CPCNs and the RTM make binding ratemaking
20 unnecessary?
21 A.No.Mr.Lobb identified four reasons why
22 binding ratemaking should not be approved by the
23 Commission:1)the Company's ability to finance the
24 project;2)Idaho only represents 6 percent of the
25 Company's system;3)Staff recommends approval of the
64 Steward,Di-Reb -11RockyMountainPower
1 CPCNs and RTM,so binding ratemaking is not necessary;O 2 and 4)the Company has already made significant
3 investment in the project.(Lobb Direct,page 10,line 20
4 to page 11,line 4.)
5 These conditions are not appropriate
6 considerations under Idaho Code §61-541.The first two,
7 in particular,would effectively prohibit the Company
8 from ever receiving binding ratemaking treatment,even
9 though nothing in the statutory language suggests that it
10 is inapplicable to PacifiCorp.In fact,I understand that
11 PacifiCorp was one of the sponsors of the legislation
12 that enacted binding ratemaking treatment.
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
65 Steward,Di-Reb -lla
Rocky Mountain Power
1 Q.Why is the Company seeking binding ratemakingO2treatment?
3 A.Binding ratemaking is useful and necessary.
4 Section 2(b)of the statute lists the ratemaking
5 treatment of the proposed facilities,which include the
6 depreciation life,maximum amount of costs that the
7 Commission will include in rates at the time without the
8 utility having the burden of moving forward with
9 additional evidence of prudence and reasonableness of
10 costs,the method of handling variances between costs
11 estimates,and treatment of revenues.The proposed
12 ratemaking treatment in the RTM reflects these elements.
13 Q.What conditions does the Company accept related
14 to its application for CPCNs and binding ratemaking
15 treatment?
16 A.The Company agrees that approval of the
17 Combined Projects with binding ratemaking treatment would
18 be conditional on the circumstances known at the time of
19 approval.If there is a change in circumstances that may
20 materially affect the project,the Company agrees to
21 bring the project back to the Commission for review.
22 In addition,the law allows the Commission to
23 determine the maximum amount of costs to be included in
24 rates (IC §61-541(2)(b)(ii)),which is effectively a soft
25 cap.The Company agrees that the RTM would be consistent
66 Steward,Di-Reb -12
Rocky Mountain Power
1 with that soft cap and reflect actual costs (andO2benefits),up to a maximum of the final estimated costs
3 from this proceeding.The Company would apply for
4 prudence determination of any variances from the
5 estimates in the next rate case.
6 Q.Does this conclude your rebuttal testimony?
7 A.Yes.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
67 Steward,Di-Reb -12a
Rocky Mountain Power
1 Q.Are you the same Joelle R.Steward who adopted
2 direct testimony and submitted rebuttal testimony in this
3 proceeding on behalf of Rocky Mountain Power ("Company"),
4 a division of PacifiCorp?
5 A.Yes.
6 PURPOSE AND SUMMARY OF TESTIMONY
7 Q.What is the purpose of your supplemental direct
8 testimony?
9 A.My testimony supports the Company's application
10 to the Idaho Public Utilities Commission ("Commission")
11 requesting Certificates of Public Convenience and
12 Necessity ("CPCNs")and binding ratemaking treatment for
13 new wind resources ("Wind Projects")and the Aeolus-to-
14 Bridger/Anticline line and network upgrades
15 ("Transmission Projects"),as reflected in this
16 supplemental filing (collectively,the "Combined
17 Projects").In my supplemental direct testimony,I update
18 the expected costs and benefits proposed to be recovered
19 through the Resource Tracking Mechanism ("RTM"),
20 associated with the Combined Projects based on the
21 Company's 2017R Request for Proposals ("2017R RFP")final
22 shortlist.
23 Q.Please summarize your testimony.
24 A.The lower rate impact of the Combined Projects
25 reflects the reduction in costs and increase in benefits
68 Steward,Di-Supp -1
Rocky Mountain Power
1 in the Company's updated economic analysis provided by
2 Company witness Mr.Rick T.Link.It also reflects the
3 effects of federal tax reform.The first year revenue
4 requirement of the Combined Projects is reduced nearly 20
5 percent from the initial filing.The Company's request
6 for resource approval and recovery through the RTM is
7 reasonable and in the public interest.The Combined
8 Projects are the least cost alternative to meet
9 customers'needs today and into the future.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
69 Steward,Di-Supp -la
Rocky Mountain Power
1 SUPPLEMENTAL DIRECT TESTIMONYO2Q.Have you updated the exhibits from your direct
3 testimony to reflect the updated economic analysis for
4 the Combined Projects,including the Wind Projects
5 selected to the 2017R RFP final shortlist,as reflected
6 in this supplemental direct filing?
7 A.Yes.My original exhibits have been updated and
8 are presented as Exhibit No.42,Exhibit No.43,Exhibit
9 No.44,and Exhibit No.45.1 These exhibits are revised
10 with the updated economic analysis in Mr.Link's
11 supplemental direct testimony which reflects results from
12 the 2017R RFP final shortlist.The exhibits are in the
13 same format as in the initial filing and calculate the
14 monthly and annual revenue requirements and the overall
15 rate impact of the Combined Projects that would be
16 reflected in the proposed RTM.
17 Q.Please provide a summary of the updates in your
18 revised exhibits.
19 A.The updates include changes in Idaho's
20 allocated share of the updated Combined Projects'
21 construction costs,return,depreciation,Production Tax
22 Credits ("PTCs"),taxes,and operating costs and
23 benefits.Updated net power costs associated with the
24 2017R RFP final shortlist,an updated load forecast,
25 system dispatch,and revised wind generation projections
70 Steward,Di-Supp -2
Rocky Mountain Power
1 have also been included in the Energy Cost Adjustment
2 Mechanism ("ECAM")pass-through calculation.Overall,
3 these changes show a reduction in revenue requirement of
4 nearly 20 percent from the initial filing.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24 1 Exhibit No.42 is included but is the same as Exhibit No.26
25
presented in direct testimony.
71 Steward,Di-Supp -2aRockyMountainPower
1 Q.Does the updated revenue requirement analysis
2 incorporate the federal income tax rate change from 35
3 percent to 21 percent,as passed under the Tax Act of
4 2017?
5 A.Yes.As shown in Exhibit No.45,line 5,the
6 consolidated federal and state income tax rate has
7 changed from the 37.951 percent used in my direct
8 testimony to 24.587 percent,reflecting the change in the
9 federal tax rate.Also,on line 6 of Exhibit No.45,the
10 PTC tax gross-up factor has been updated from 1.6116 in
11 my direct testimony to 1.3260.These changes are
12 incorporated in the revenue requirement results shown in
13 Exhibit No.43 and Exhibit No.44.
14 Q.What is the updated estimated rate impact
15 associated with the Combined Projects,which would be
16 reflected in rates through the RTM,in conjunction with
17 the ECAM?
18 A.The Company is projecting the Combined
19 Projects'updated annual revenue requirement impact for
20 the years 2020 to 2023 to be in the range of ($0.3)
21 million to $4 million in Idaho,as shown in Table 1 of
22 Exhibit No.43.The net rate impact would now be less
23 than 1.6 percent for the first full year of operation.
24 Q.As a result of this updated economic analysis,
25 has the Company's proposed ratemaking treatment for
72 Steward,Di-Supp -3
Rocky Mountain Power
1 interim recovery of costs through the RTM changed?
2 A.No.As discussed in my rebuttal testimony filed
3 on December 18,2017,the Company continues to propose
4 recovery of costs through the RTM in order to match
5 benefits and costs in rates.
6 Q.Does this conclude your supplemental direct
7 testimony?
8 A.Yes.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
73 Steward,Di-Supp -3a
Rocky Mountain Power
1 Q.Are you the same Joelle R.Steward who
2 previously submitted testimony in this proceeding on
3 behalf of Rocky Mountain Power ("the Company"),a
4 division of PacifiCorp?
5 A.Yes.
6 PURPOSE OF TESTIMONY
7 Q.What is the purpose of your second supplemental
8 direct testimony?
9 A.I update the expected costs and benefits
10 proposed to be recovered through the Resource Tracking
11 Mechanism ("RTM"),to reflect the updated 2017R Request
12 for Proposals ("2017R RFP")final shortlist described in
13 the second supplemental direct testimony of Company
14 witness Mr.Rick T.Link.The Company proposed the RTM as
15 part of its request for approval of the Company's energy
16 resource decisions for new wind resources ("Wind
17 Projects")and for the Aeolus-to-Bridger/Anticline line
18 and network upgrades ("Transmission Projects")
19 (collectively,the "Combined Projects").
20 SECOND SUPPLEMENTAL DIRECT TESTIMONY
21 Q.Have you updated the exhibits from your first
22 supplemental testimony to reflect the updated economic
23 analysis for the Combined Projects summarized in Mr.
24 Link's testimony?
25 A.Yes.My original exhibits have been updated and
74 Steward,Di-2nd Supp-1
Rocky Mountain Power
1 are presented as Exhibit No.62,1 Exhibit No.63,
2 Exhibit No.64 and Exhibit No.65.These exhibits reflect
3 the updated costs and benefits in the economic analysis
4 in Mr.Link's testimony based on the updated 2017R RFP
5 final shortlist.The exhibits are in the same format used
6 in my previous testimony.They calculate the monthly and
7 annual revenue requirements and
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23 lExhibit No.62 is included but is the same as Exhibit No.42 in
supplemental direct testimony.
24
25
75 Steward,Di-2nd Supp-la
Rocky Mountain Power
1 show the overall net impact for the Combined Projects
2 that would be reflected in rates,including the proposed
3 RTM.
4 Q.Please provide a summary of the updates in your
5 revised exhibits.
6 A.As in my previous supplemental update,my
7 updated exhibits include changes in Idaho's allocated
8 share of the updated Combined Projects'capital costs,
9 return,depreciation,Production Tax Credits ("PTCs"),
10 taxes,and operating costs and benefits.Updated net
11 power costs associated with the updated 2017R RFP final
12 shortlist,system dispatch,and revised wind generation
13 projections have also been included in the Energy Cost
14 Adjustment Mechanism ("ECAM")pass-through calculation.
15 Q.What are the updated annual estimated rate
16 impacts associated with the Combined Projects that would
17 be reflected in rates through the RTM,in conjunction
18 with the ECAM?
19 A.The Company is projecting the Combined
20 Projects'updated annual revenue requirement impact for
21 the years 2020 to 2023 to be in the range of ($0.3)
22 million to $4.7 million in Idaho,as shown in Table 1 of
23 Exhibit No.63.The net rate impact would be less than
24 1.7 percent for the first full year of operation.
25 Q.Has the Company's proposed ratemaking treatment
76 Steward,Di-2nd Supp-2
Rocky Mountain Power
1 for interim recovery of costs through the RTM changed?
2 A.No.The Company continues to propose recovery
3 of costs through the RTM to concurrently match benefits
4 and costs in rates.Absent recovery through the RTM,the
5 Company continues to recommend symmetrical treatment of
6 the costs and benefits of the Combined Projects by
7 excluding net power cost benefits from the ECAM if costs
8 are not deferred or otherwise reflected in rates.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
77 Steward,Di-2nd Supp-2a
Rocky Mountain Power
1 Q.Does this conclude your second supplemental
2 direct testimony?
3 A.Yes.
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
78 Steward,Di-2nd Supp-3
Rocky Mountain Power
1 Q.Are you the same Joelle R.Steward who
2 previously provided testimony in this case on behalf of
3 Rocky Mountain Power ("Company"),a division of
4 PacifiCorp?
5 A.Yes.
6 PURPOSE AND SUMMARY OF SUPPLEMENTAL REBUTTAL TESTIMONY
7 Q.What is the purpose of your supplemental
8 rebuttal testimony?
9 A.In support of the Company's application asking
10 the Idaho Public Utilities Commission ("Commission")to
11 approve the request for certificates of public
12 convenience and necessity ("CPCNs")and binding
13 ratemaking treatment for wind and transmission projects
14 ("Combined Projects"),I respond to regulatory and
15 ratemaking policy issues raised in the supplemental
16 direct testimonies of Monsanto witness Mr.Nicholas L.
17 Phillips,PacifiCorp Idaho Industrial Customers ("PIIC")
18 witness Mr.Bradley G.Mullins,and Commission Staff
19 witness Mr.Michael Louis.
20 Q.Please summarize your testimony.
21 A.The conditions proposed by Messrs.Mullins,
22 Phillips,and Louis to require a hard cap on cost
23 recovery are unprecedented,unwarranted,and,in the case
24 of Monsanto's witness Mr.Phillips,unnecessarily
25 punitive.As the Company explained in rebuttal testimony
79 Steward,Supp Reb -1
Rocky Mountain Power
1 filed in December 2017,the Company accepts the risks
2 that are within the Company's control related to
3 qualification for the production tax credits ("PTCs"),
4 thereby mitigating potential harm to customers.
5 Additionally,the Company has agreed to a soft cost cap
6 in the Resource Tracking Mechanism ("RTM")based on the
7 estimated costs of the Combined Projects.This means that
8 the Company must establish the prudence of any costs in
9 excess of the estimate in the next rate case.In light of
10 the customer benefits from the Combined Projects,the
11 Company requests that the Commission grant the requested
12 CPCNs,and approve the RTM.
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
80 Steward,Supp Reb -laRockyMountainPower
1 RESPONSE TO PROPOSED CONDITIONSO2Q.Messrs.Phillips,Mullins,and Louis all
3 propose that the Commission impose a hard cap on cost
4 recovery.(Phillips Supp.Direct,page 3,lines 16-20;
5 Mullins Supp.Testimony,page 4,lines 4-9;Louis Supp.
6 Testimony,page 4,lines 21-24.)How do you respond?
7 A.Imposing a hard cap on potential cost recovery
8 would be unprecedented,unnecessary and unjustified.As I
9 discussed in my rebuttal testimony (Steward Rebuttal,
10 page 7,lines 6-15),Mr.Phillips's proposed cost cap is
11 an automatic disallowance of 21 percent of the capital
12 costs.His recommendation would effectively provide
13 customers a double-count of benefits,through both the
14 reduction in capital cost recovery and lower net power
15 costs and pass-through of production tax credits.
16 Adoption of this cost cap is unbalanced and not in the
17 public interest because it would create a disincentive
18 for the Company to pursue cost-effective resource
19 opportunities to serve customers.
20 Both Mr.Mullins and Mr.Louis recommend hard
21 caps at the cost estimates included in the Company's
22 second supplemental filingi.Although this proposal is
23 less egregious than Mr.Phillips's,it is still
24 inappropriate to pre-determine that costs may not be
25 recovered in rates,irrespective of whether they were
81 Steward,Supp Reb -2
Rocky Mountain Power
1 prudently incurred.Staff witness Michael Eldred evenO2calculatesabreakevenanalysis,presented on Table 4 of
3 his supplemental testimony,which shows the Combined
4 Projects would still be economic for customers if costs
5 exceed the estimates under most of the price-policy
6 scenarios.Setting a hard cap now,without the
7 opportunity for the Company to provide evidence to
8 explain and justify its actual costs would be
9 unprecedented and unfair,particularly in light of the
10 near-and long-term customer benefits from these
11 resources.
12 Q.Has the Company proposed a soft cap to protect
13 customers?
14 A.Yes.Under the soft cap,the Company agrees
15 that the total project capital costs included
16 /
17
18 /
19
20 /
21
22
23 1 However,the $1,370,237,000 for the Wind Projects included in Mr.
Mullins's testimony is not the cost included in the Company's second
24 supplemental filing.The amount included in the Company's filing is
25
$1,455,495,230 for the Wind Projects.
82 Steward,Supp Reb -2a
Rocky Mountain Power
1 in the RTM will not exceed the total estimated project
2 cost in the Company's most recent filing.The Company
3 will still be able to seek recovery of and show the
4 prudence of any increase in the total project capital
5 cost in a future rate case,but will not seek recovery of
6 the amount in excess of the current estimate before a
7 prudence finding by the Commission.Customers are
8 protected from any potential cost over-runs in the
9 interim cost recovery mechanism-the RTM-following this
10 pre-approval,and stakeholders will be able to review and
11 challenge any cost over-runs in a general rate case
12 before those costs are included in rates.
13 Q.Does the soft cap make a hard cap on cost
14 recovery unnecessary?
15 A.Yes.Under the soft cap,the Company accepts
16 the burden of proof on costs incurred above the current
17 estimates.Cost recovery through the RTM would be limited
18 to actual costs (and benefits),up to a maximum of the
19 estimated costs in this proceeding.This is consistent
20 with binding ratemaking treatment allowed under Idaho
21 Code §61-541(b)(iii),which recognizes the utility
22 having the burden of moving forward with additional
23 evidence of prudence and reasonableness of costs over the
24 estimates.It also recognizes that the Commission may set
25 the method of handling variances between cost estimates
83 Steward,Supp Reb -3
Rocky Mountain Power
1 (See IC §61-541(b)(iv)).Because the Company bears the
2 burden of demonstrating the reasonableness of costs and
3 prudent management for resource development,the Company
4 continues to have the motivation and incentive to keep
5 costs low,without the need for a hard cost cap.
6 Q.Mr.Phillips recommends that if the Company
7 ceases construction of the Combined Projects,for
8 whatever reason,any cost incurred should not be
9 recoverable from customers.(Phillips Supp.Direct,page
10 4,lines 10-11.)How do you respond?
11 A.The Company does not agree the Commission
12 should foreclose the opportunity to seek recovery of
i
I
13 costs.Recommending the Commission pre-determine and
14 disallow cost recovery under all circumstances is
15 inconsistent with Commission practice.As addressed in
16 Ms.Crane's rebuttal testimony,the Company will
17 prudently negotiate precautionary
18 /
19
20 /
21
22 /
23
24
25
84 Steward,Supp Reb -3a
Rocky Mountain Power
1 off-ramps in the contracts to allow it to exit theO2TransmissionProjectsiftheybecomeuneconomic.The
3 timing and terms of the execution of the contracts
4 necessary to procure or construct the Wind Projects will
5 also provide flexibility to allow the Company to reassess
6 project economics,if necessary,before executing the
7 contracts.If an adverse change of circumstances
8 materially affects the Combined Projects'economics,the
9 Company will seek Commission review of whether to proceed
10 with implementation.This is the prudent approach to
11 mitigate customer risk for items beyond the Company's
12 control.
13 Q.What has the Company testified in this
14 proceeding about the risks it is willing to assume?
15 A.The Company has consistently testified that it
16 assumes the risk associated with factors within its
17 control that the Wind Projects will qualify for PTC
18 benefits.For example,if any turbines fail to qualify
19 because of the Company's actions or inactions,
20 shareholders accept the consequences of that result.
21 (Crane Rebuttal,page 7,line 17 to page 8 line 2.)
22 Q.Does this conclude your supplemental rebuttal
23 testimony?
24 A.Yes.
25
85 Steward,Supp Reb -4
Rocky Mountain Power
1 (The following proceedings were had in
2 open hearing.)
3
4 DIRECT EXAMINATION
5
6 BY MS.McDOWELL:(Continued)
7 Q So Mrs.Steward,have you also caused to
8 be filed in the last couple of days additional testimony
9 in support of the stipulation of the Company filed on May
10 8th,2018?
11 A Yes.
12 Q Do you have any corrections or additions
13 to that testimony?
14 A No.
15 Q And are there any corrections or additions
16 to the stipulation other than what was just noted?
17 A No.
18 MS.McDOWELL:With that,Commissioner,I
19 would also ask that the stipulation and Ms.Steward's
20 testimony in support of the stipulation be spread upon
21 the record.
22 COMMISSIONER ANDERSON:Without objection,
23 we'll spread Ms.Steward's settlement testimony in
24 support of the stipulation across the record as if
25 read.
CSB REPORTING 86 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 MS.McDOWELL:Thank you.
2 (The following prefiled settlement
3 testimony of Ms.Joelle Steward is spread upon the
4 record.)
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING 87 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 Q.Are you the same Joelle R.Steward who
2 previously provided testimony in this case on behalf
3 Rocky Mountain Power,a division of PacifiCorp (the
4 "Company")?
5 A.Yes.
6 PURPOSE AND SUMMARY OF SETTLEMENT TESTIMONY
7 Q.What is the purpose of your settlement
8 testimony in this proceeding?
9 A.My testimony presents,explains,and supports
10 the stipulation ("Stipulation")in this proceeding,Case
11 No.PAC-E-17-07,between the Company and the Staff of the
12 Idaho Public Utilities Commission ("Staff"),filed with
13 the Commission on May 8,2018.In addition to my
14 testimony,Company witness Mr.Rick T.Link provides
15 testimony in support of the Stipulation,updating the
16 economic analysis to reflect the removal of the Uinta
17 wind project from the Company's application in this case.
18 The Stipulation proposes a resolution to all
19 but one of the issues in dispute between the Company and
20 Staff,as I will explain below.As described in the
21 Second Supplemental Direct Testimony of Rocky Mountain
22 Power,the Company requests a certificate of public
23 convenience and necessity ("CPCN")and ratemaking
24 treatment for the 140-mile Aeolus-to-Bridger/Anticline
25 500-kV transmission line,three new Wyoming wind
88 Steward,Sett -1
Rocky Mountain Power
1 resources,Ekola Flats,TB Flats I and II,and CedarO2Springs,totaling 1,150 MW ("Wind Projects"),and the
3 related network upgrades (collectively,"Stipulated
4 Projects").The Stipulation provides a framework for the
5 positive resolution of the complex issues presented in
6 this case and is in our customers'best interest.
7 Q.Please provide a short summary of the key terms
8 of the Stipulation.
9 A.The Company and Staff ("Stipulating Parties")
10 have entered into a Stipulation that
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
89 Steward,Sett -la
Rocky Mountain Power
1 includes the following key provisions:O 2 The Stipulating Parties request that the Commission
issue an order granting a CPCN for the proposed
3 Aeolus-to-Bridger/Anticline transmission line,the
Wind Projects,and the related network upgrades,
4 with a finding that (1)the Stipulated Projects are
prudent and in the public interest,and (2)in
5 accordance with Idaho Code §61-526,the Stipulated
Projects are a reasonable way to meet the present or
6 future public convenience and necessity.(Stipulation ¶9).
7
The Stipulating Parties request that the Commission
8 approve the Company's proposed ratemaking treatment
for recovery of the new investment,energy
9 production,and production tax credits ("PTC")
associated with the Stipulated Projects through the
10 proposed Resource Tracking Mechanism ("RTM"),as a
component of the Energy Cost Adjustment Mechanism
11 ("ECAM").The RTM,along with the ECAM,will capture
the costs and benefits of the Stipulated Projects
12 until the Company's next general rate case,at which
time the Stipulating Parties will re-evaluate the
13 use of the RTM going forward.(Stipulation ¶10).
14 The Company will include the actual costs and
benefits it incurs for the Stipulated Projects in
15 the RTM for recovery in the ECAM.Actual capital
costs included in the RTM,before the next general
16 rate case,cannot exceed (redacted),which are the
estimated costs for the Stipulated Projects included
17 in the Second Supplemental Direct Testimony of Rocky
Mountain Power.Parties will have the opportunity to
18 verify these costs as part of the annual audit of
the ECAM deferred balance.(Stipulation ¶13).
19
Costs that are passed on to customers through the
20 RTM,before the next general rate case,will be
capped at the benefits that will flow through the
21 ECAM.As such,on a combined basis,the ECAM and the
RTM will not result in a net cost to customers
22 associated with the Stipulated Projects.Any costs
above this cap will be deferred as a regulatory
23 asset for recovery to be set in the next general
rate case.(Stipulation ¶14).
24
In recognition of receiving timely recovery of its
25 investment through the ECAM and RTM,the Company
90 Steward,Sett -2
Rocky Mountain Power
1 will annually provide $300,000,which will be
deferred as a regulatory liability,beginning in the
2 month the first facility's costs are included in the
RTM,with the ratemaking treatment to be set in the
3 next general rate case.If the RTM deferral period
is a partial year,the annual $300,000 will be
4 pro-rated for the deferral period.(Stipulation ¶15).
5
The Stipulating Parties reserve all rights to argue
6 in this case for or against an overall capital cost
cap for the construction of the Stipulated Projects.
7 The Stipulating Parties agree that such a cap,if
any,would be applied at the time of the Company's
8 next general rate case,or when the Stipulated
Projects are placed into base rates.(Stipulation ¶
9 16).
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
91 Steward,Sett -2a
Rocky Mountain Power
1 The Company agrees to bear the risks of construction
cost overruns associated with the Stipulated
2 Projects and has the burden of proof regarding the
recovery of any of the costs associated with the
3 Stipulated Projects.However,Staff agrees not tochallengetheCompany's prudence related to the
4 decision to build the Stipulated Projects or
recovery of the actual capital costs associated with
5 the Stipulated Projects except to the extent (1)the
actual costs exceed the estimated costs of
6 (redacted),or (2)there is evidence of
mismanagement.(Stipulation 17).
7
The Company agrees to accept the risk that any
8 portion of the wind projects will not qualify for
PTCs,unless the failure is due to a change in the
9 law or a Force Majeure event.In the event of either
a change in law or Force Majeure event,the Company
10 will promptly file a notice with the Commissiondescribingthechange,its impact,and the Company's
11 assessment of the ability to complete the StipulatedProjectsinwholeorinpart.(Stipulation ¶18).
12
The Company will negotiate availability guarantees
O 13 for the new wind projects in any third-partyprovidedmaintenance,as provided by the competitive
14 market,which is currently 97 percent.All
liquidated damages received by the Company will be
15 passed onto customers through the ECAM.(Stipulation
¶19).
16
17 The provisions and agreements in the Stipulation were
18 negotiated in good faith,and advance the public
19 interest.The Stipulating Parties urge the Commission to
20 approve the Stipulation on this basis.
21 Q.Please summarize why the Company supports the
22 Stipulation.
23 A.The Company requested a CPCN for the Stipulated
24 Projects because the projects are the least-cost,
25 least-risk resources available to serve customers.The
92 Steward,Sett -3
Rocky Mountain Power
1 Stipulated Projects are a reasonable way to meet the
2 resources required by the present or future public
3 convenience and necessity.Indeed,the Company's economic
4 analysis demonstrates that the Stipulated Projects are an
5 unprecedented and time-sensitive opportunity to acquire
6 much-needed transmission resources and zero-fuel cost
7 wind resources while delivering all-in customer savings.
8 The Stipulation allows the Company to achieve substantial
9 customer savings through the construction of the
10 Aeolus-to-Bridger/Anticline transmission line and the
11 acquisition of the Wind Projects.Although
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
93 Steward,Sett -3aRockyMountainPower
1 the Uinta project is no longer included,the Stipulated
2 Projects continue to demonstrate substantial economic
3 benefits,and it is in the public interest to issue the
4 CPCN agreed to under the Stipulation.
5 Q.Why do you believe the Stipulation is in the
6 public interest?
7 A.The Stipulation resolves all but one of the
8 issues presented between the Company and the Staff in a
9 way that preserves the significant customer benefits of
10 the Stipulated Projects,while addressing Staff's
11 concerns over the project risks with customer
12 protections.As described in Mr.Link's testimony in
13 support of the Stipulation,the economic analysis of the
14 revised Stipulated Projects (removing Uinta)demonstrates
15 that they are highly likely to provide substantial
16 customer benefits both in the near-and long-term.
17 The Stipulation also provides greater certainty
18 going forward,and therefore mitigates customer risk,by
19 clarifying the scope of the PTC risk that the Company
20 will assume.
21 The Stipulation resolves the ratemaking
22 treatment of the costs and benefits of the Combined
23 Projects by recommending that the Commission approve the
24 Company's proposed ratemaking treatment for recovery of
25 the new investment,energy production,and PTCs
94 Steward,Sett -4
Rocky Mountain Power
1 associated with the Stipulated Projects,with certainO2modificationsagreedtobytheStipulatingParties.
3 Taken together,the provisions of the
4 Stipulation produce a sound and balanced resolution of
5 complex issues,and facilitate a favorable result for the
6 Stipulating Parties,in furtherance of the public
7 interest.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
95 Steward,Sett -4a
Rocky Mountain Power
1 STIPULATION PROVISIONSO2Q.Please describe how the Stipulation resolves
3 the Company's request for a CPCN for the Stipulated
4 Projects.
5 A.The Stipulating Parties agree that the Company
6 should be granted a CPCN for the Aeolus-to-Bridger/
7 Anticline 500-kV transmission line,the Wind Projects,
8 and associated network upgrades,as described in the
9 Company's Second Supplemental Direct Testimony filed
10 February 16,2018.Stipulation ¶9.Mr.Link's settlement
11 testimony describes how the removal of the request for a
12 CPCN for the Uinta project affects the Company's
13 estimated net customer benefits resulting from the
14 Stipulated Projects.Mr.Link demonstrates that customers
15 will still receive substantial savings as a result of the
16 Stipulated Projects.
17 Q.Did any party specifically challenge the
18 inclusion of the Uinta project in the Company's
19 application?
20 A.No.However,the Company agreed to remove the
21 Uinta project from this case consistent with its
22 agreement in the recent Wyoming case for approval of
23 CPCNs for the Stipulated Projects (Docket No.
24 20000-520-EA-17).For settlement in the Wyoming
25 proceeding,the Company agreed to remove the Uinta
96 Steward,Sett -5
Rocky Mountain Power
1 project from its CPCN request to address parties'
2 concerns that the customer benefits may not materialize
3 if future natural gas prices are low and there is no
4 regulation of carbon dioxide emissions.While this was
5 not an issue raised by Staff,removing Uinta makes the
6 CPCN request consistent and responds to concerns raised
7 by other parties in this proceeding.The removal of the
8 Uinta project here also simplifies the Company's request
9 in this docket.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
97 Steward,Sett -5a
Rocky Mountain Power
1 Q.Does the Stipulation have any terms that
2 mitigate customer risk associated with the Stipulated
3 Projects?
4 A.Yes.In response to concerns raised in this
5 case,the Company has agreed to several conditions
6 designed to reduce customer risk and provide greater
7 certainty that the expected benefits will be realized.
8 Q.Please describe the agreement related to
9 approval of the CPCN and for ratemaking treatment for the
10 Stipulated Projects.
11 A.First,the Stipulating Parties agree that the
12 Company will bear the risks related to any portion of the
13 Wind Projects that do not qualify for PTCs.Stipulation
14 ¶18.To the extent that the Wind Projects fail to
15 qualify for PTCs,in whole or in part,PTCs will be
16 imputed to each such project based on that project's
17 actual wind output for equipment placed in service and
18 included in rate base at full revenue value (i.e.,
19 including full gross up for federal and other applicable
20 taxes).
21 The Stipulating Parties agree,however,that
22 the Company will not bear the PTC qualification risk if
23 the failure to qualify for PTCs is a result of either:
24 (1)a change in law;or (2)a Force Majeure event.
25 Stipulation ¶18.
98 Steward,Sett -6
Rocky Mountain Power
1 Q.Does the Stipulation provide any guidance
2 regarding how the Company is to proceed if a change in
3 law occurs?
4 A.Yes.If a change in law occurs,the Company
5 will make all commercially reasonable efforts to mitigate
6 the loss of value to customers including,but not limited
7 to,cancelling the acquisition or construction of
8 facilities to the extent practical and cost effective
9 from the customers'perspective.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
99 Steward,Sett -6a
Rocky Mountain Power
1 Q.What happens if there is a change in law or aO2ForceMajeureevent?
3 A.In the event of a change in law or a Force
4 Majeure event,the Company will promptly file a notice
5 with the Commission describing the change or event,the
6 impact,and the Company's assessment of its ability to
7 complete the Stipulated Projects,in whole or in part,
8 and other relevant information regarding the change or
9 event and any possible remediation.Stipulation ¶18.If
10 there is any dispute regarding the applicability of this
11 provision or the extent of its applicability to a
12 particular facility,or any dispute about the Company's
13 actions in the face of a change of law or Force Majeure
14 event,such dispute will be resolved by the Commission in
15 the first general rate proceeding where the Company seeks
16 to include the capital costs of the facility in rates.
17 Q.How does the Company's assumption of PTC risk
18 address concerns raised in this case?
19 A.The substantial customer benefits of the
20 Stipulated Projects result directly from the ability of
21 the Wind Projects to qualify for PTCs,which offset the
22 cost of the Stipulated Projects and provide overall
23 customer savings.To qualify for PTCs,the Stipulated
24 Projects must reach commercial operation by the end of
25 2020.The Stipulation reaffirms the Company's commitment
100 Steward,Sett -7
Rocky Mountain Power
1 to accept the PTC risk within its control,and provides
2 greater details regarding the scope and extent of that
3 assumption of risk.
4 Q.Please generally describe the ratemaking
5 treatment agreed to in the Stipulation.
6 A.The ECAM,in conjunction with the new RTM,will
7 be used to track the costs and benefits of the Stipulated
8 Projects until the Company's next general rate case.At
9 that time,the Stipulating Parties will re-evaluate the
10 future use of the RTM.The existing sharing band in the
11 ECAM operates so that 90 percent of the net power cost
12 benefits
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
101 Steward,Sett -7a
Rocky Mountain Power
1 related to the energy production from each of the windO2facilitiesintheStipulatedProjectswillbecredited to
3 customers and 10 percent will be assigned to the Company.
4 Under the Stipulation,the Company will pass its 10
5 percent share of the benefits to customers in the RTM so
6 that customers will receive 100 percent of the benefits
7 of the energy produced by the Wind Projects.
8 Q.How will the costs and benefits of the
9 Stipulated Projects be treated in the RTM and the ECAM?
10 A.The costs and benefits of the Stipulated
11 Projects will be included in the RTM for recovery in the
12 ECAM until the Company's next general rate case.The
13 actual capital costs included in the RTM,before the next
14 general rate case,cannot exceed (redacted),the
15 estimated costs for the Stipulated Projects included in
16 the Second Supplemental Direct Testimony of the Company.
17 Confidential Table 1 shows the calculation and source for
18 the basis of the estimated capital costs without the
19 Uinta project.
20 /
21 /
22 /
23 /
24 /
25 /
102 Steward,Sett -8
Rocky Mountain Power
1
2 Confidential Table 1 -Calculation of CapitalCosts
3
In-Service I
4 Capital
($million)!Source
5 Wind Resource Capital Costs $1,455 ConfidentialExhibit No.54
Interconnection Network
6 Upgrades $111 ConfidentialExhibit No.54
Aeolus-to-Bridger/Anticline
7 Transmission Line $679 ConfidentialExhibit No.54
Sub-Total Capital Costs as
8 Filed $2,245
Remove Uinta Capital Costs ConfidentialExhibit No.54
9 Remove Uinta Interconnection
NetworkUpgrades ConfidentialExhibit No.49
10 TOTAL Capital Costs
Without Uinta
11
12
'13 Parties will have the opportunity to verify
O 14 actual costs as part of the annual audit of the
15 /
16
17 /
18
19 /
20
21
22
23
24
25
103 Steward,Sett -Sa
Rocky Mountain Power
1 ECAM and RTM deferred balance.The Company will also
2 include the costs and benefits that are tracked in the
3 RTM in its quarterly ECAM filing updates beginning after
4 the in-service date of the first facility placed
5 in-service.
6 Q.Will the ratemaking treatment you describe
7 above result in an increase in customer rates before the
8 next general rate case related to the Stipulated
9 Projects?
10 A.No.The Company will maintain a cap in the RTM
11 on the annual total costs of the Stipulated Projects not
12 to exceed the annual project benefits.Costs that are
13 passed onto customers through the RTM before the next
14 general rate case will be capped at the benefits that
15 flow through the ECAM.As such,the combined impact of
16 the Stipulated Projects in the ECAM and the RTM will not
17 result in a net cost to customers.Costs above this cap
18 will be deferred as a regulatory asset for recovery to be
19 set in the next general rate case.
20 Q.Are there other additional benefits for
21 customers in consideration of the Company's timely
22 recovery of its investment through the ECAM and RTM?
23 A.Yes.In light of receiving timely recovery of
24 its costs,the Company has agreed to defer $300,000
25 annually as a regulatory liability,beginning in the
104 Steward,Sett -9RockyMountainPower
1 month the first wind facility's costs are included in theO2RTM,with the ratemaking treatment to be set in the next
3 general rate case.If the RTM deferral period is a
4 partial year,the annual $300,000 will be pro-rated for
5 the deferral period.
6 Q.How will the gross-up pre-tax values of the
7 PTCs generated by each of the wind facilities within the
8 Stipulated Projects be credited to customers?
9 A.They will be credited through the ECAM,
10 consistent with the current treatment of PTCs.
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
105 Steward,Sett -9a
Rocky Mountain Power
1 Q.What if the Company is unable to
2 contemporaneously monetize PTCs to their full value?
3 A.There will be no return on any deferred tax
4 assets that may be created as a result.
5 Q.What is the timing of the deferral of the costs
6 and benefits of the Stipulated Projects?
7 A.The Company will begin deferring the costs and
8 benefits of the Stipulated Projects in the first month of
9 the actual in-service dates,until those costs and
10 benefits are included in base rates through a general
11 rate case.
12 Q.Will the Company earn a rate of return on the
13 net plant balance in the RTM?
14 A.Yes.A 9.2 percent pre-tax rate of return on
15 investment will be used in the RTM calculation,equating
16 to an after-tax return on investment of 6.96 percent.
17 Following the next general rate case,the return on the
18 net plant balance will be consistent with the rate of
19 return authorized by the Commission in that case.
20 Q.How does the Stipulation address construction
21 costs for the Stipulated Projects?
22 A.The Stipulating Parties agree that the Company
23 will bear the risks related to construction cost overruns
24 associated with the Stipulated Projects.Stipulation
25 ¶17.As such,the Company will not be allowed to recover
106 Steward,Sett -10
Rocky Mountain Power
1 any imprudent costs or costs due to Company
2 mismanagement.Further,the Company has the burden of
3 proof regarding the recovery of any costs associated with
4 the Stipulated Projects.
5 The Stipulating Parties agree,however,not to
6 challenge the Company's prudence related to the decision
7 to build the Stipulated Projects or recovery of the
8 actual capital costs associated the Stipulated Projects
9 except to the extent (1)the actual costs of constructing
10 the Stipulated Projects exceeds the estimate of
11 (redacted),or
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
107 Steward,Sett -10a
Rocky Mountain Power
1 (2)there is evidence of mismanagement.Stipulation ¶17.
2 If such circumstances ever exist,any challenge to cost
3 recovery will be limited to the prudence of the actual
4 costs in excess of the estimated costs or the impact of
5 the mismanagement.The standard audit function to verify
6 actual costs and to review operational prudence will
7 continue to apply for all costs.
8 Q.Is there an outstanding issue between the
9 Company and Staff regarding construction costs for the
10 Stipulated Projects?
11 A.Yes.The Stipulating Parties have not agreed on
12 whether the Commission should impose an overall cost cap
13 on the construction of the Stipulated Projects.Staff
14 believes that the Commission should impose an overall
15 cost cap,and the Company believes that a cost cap is
16 unprecedented and unnecessary based on the provisions of
17 paragraph 17 related to cost overruns.Therefore,the
18 Stipulating Parties reserve their right to present
19 arguments to the Commission on this issue under paragraph
20 16 of the Stipulation.
21 Q.Does the Stipulation provide customer
22 protections related to the availability of the Wind
23 Projects?
24 A.Yes.The Company agrees to negotiate an
25 availability guarantee for the Wind Projects in any
108 Steward,Sett -11
Rocky Mountain Power
1 third-party maintenance agreements.The availability
2 guarantee will be at the level provided by the
3 competitive market,which is currently 97 percent.
4 Further,the Stipulating Parties agree that all
5 liquidated damages received by the Company under
6 contractual agreements with vendors will be passed onto
7 customers through the ECAM,including,but not limited
8 to,liquidated damages received due to the equipment not
9 meeting specified availability and performance.
10 Stipulation ¶19.
11 /
12
I
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
109 Steward,Sett -lla
Rocky Mountain Power
1 Q.Does the Stipulation contain terms to address
2 what happens if the Company enters into a settlement in
3 the concurrent Utah case seeking pre-approval of the
4 Stipulated Projects?
5 A.Yes.The Stipulating Parties agree to reconvene
6 and reconsider and amend the terms and conditions of the
7 Stipulation if the Company executes and obtains approval
8 of a settlement agreement with parties in Utah Docket No.
9 17-035-40 and the settlement agreement includes more
10 favorable terms and conditions for customers.This
11 provision recognizes that differences exist in current
12 regulatory treatment or mechanisms between the states
13 that will impact any settlement structure achieved in
14 other states.Stipulation ¶22.If after reconvening,the
15 overall terms of a settlement agreement reached and
16 approved is more favorable,the Company will file with
17 the Commission to align the overall outcome of this
18 Stipulation with a Utah settlement.
19 GENERAL TERMS AND CONDITIONS
20 Q.Please explain Paragraphs 23 through 29.
21 A.Paragraphs 23 to 29 of the Stipulation identify
22 the general terms and conditions that the Stipulating
23 Parties have agreed to relative to the Stipulation.These
24 general terms and conditions are consistent with prior
25 settlements entered into by the Stipulating Parties and
110 Steward,Sett -12
Rocky Mountain Power
1 approved by the Commission.
2 Q.What is your request of this Commission?
3 A.For all of the reasons stated in my testimony
4 and the additional details provided within the
5 Stipulation itself,I urge the Commission to approve this
6 Stipulation because I believe it to be in the public
7 interest.The Stipulation demonstrates that the
8 Stipulated Projects are required for the public
9 convenience and necessity,and supports the
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
111 Steward,Sett -12a
Rocky Mountain Power
1 requested CPCN and ratemaking treatment .
2 Q.Does this conclude your settlement testimony?
3 A.Yes.
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
112 Steward,Sett -13
Rocky Mountain Power
1 (The following proceedings were had in
2 open hearing.)
3
4 DIRECT EXAMINATION
5
6 BY MS.McDOWELL:(Continued)
7 Q So Ms.Steward,are you the Company's
8 witness today who is introducing the stipulation to the
9 Commission?
10 A Yes.I'm very pleased to be here to
11 support the stipulation that we reached with Staff that
12 we filed just a day or two ago.
13 Q So Ms.Steward,could you please provide
14 an overview of the stipulation?
15 A Yes,since we just filed it a couple of
16 days ago,I wanted to do a very brief overview of the key
17 provisions within the stipulation.The stipulation
18 supports the approval of a CPCN for the Aeolus-to-
19 Bridger/Anticline transmission line as well as three wind
20 projects;the TB Flats,Ekola Flats,and Cedar Springs,
21 as well as the related network upgrade.The Uinta wind
22 project which had been in our application has effectively
23 been withdrawn from our request for approval of the
24 CPCN.
25 Specifically,the stipulation asks the
CSB REPORTING 113 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 Commission find that the stipulated projects are prudent
2 and in the public interest and are a reasonable way to
3 meet the present or future public convenience and
4 necessity consistent with the Idaho CPCN law.
5 The stipulation includes a number of
6 important customer protections,as well as the ratemaking
7 treatment.For the ratemaking treatment,the stipulation
8 provides the addition of a resource tracking mechanism or
9 the RTM to work in conjunction with the ECAM mechanism to
10 provide back 100 percent of the costs and benefits of the
11 resources until they are requested in rates in a general
12 rate case.
13 The RTM specifically will reflect 90
14 percent of the net power --10 percent of the net power
15 cost and benefits that would not otherwise flow through
16 the ECAM.The ECAM itself recovers 90 percent of the net
17 power cost and benefits,as well as 100 percent of the
18 production tax credits associated with the new projects.
19 The actual capital costs that we could flow through the
20 RTM are capped at the estimated cost that we have
21 reflected in our supplemental and is identified in my
22 settlement testimony.
23 The --there's also a cap on the rates
24 that could be put through the RTM.They will be capped
25 at the benefits of the ECAM,so there will be no net
CSB REPORTING 114 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 surcharge to customers related to these projects.The
2 Company will defer the amounts above that surcharge or
3 that cap to the benefit up to the point of the estimated
4 cost for recovery in a general rate case.
5 In light of receiving the timely recovery
6 of the costs and the benefits through the ECAM and the
7 RTM,the Company has agreed to annual regulatory deferral
8 of $300,000 or up to $300,000 annually until the
9 resources are put into base rates.In addition to those
10 cost cap provisions in the RTM,the Company has agreed to
11 bear the risks related to construction cost overruns.
12 This means that anything over the estimates will be
13 subject to a prudence review in the next general rate
14 case.
15 The Company also bears the risk of PTC
16 qualification,except for changes in law or Force Majeure
17 events.The stipulation requires notice to the
18 Commission if one of these event occurs and it also
19 includes the dispute resolution process in the event
20 there is any disagreement between the Company and parties
21 on whether or not this even qualifies under the Force
22 Majeure event.
23 Another customer protection is that we
24 have agreed to negotiate a 90 percent availability
25 guarantee for the wind projects in any third-party
CSB REPORTING 115 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 maintenance agreement,and any liquidated damages that
2 would come through those agreements would be passed on to
3 customers.
4 And then finally,if there is a material
5 change in circumstances or project costs,the Company
6 will bring that to the Commission and parties for further
7 review.
8 Q Ms.Steward,were there any issues between
9 the Company and the Staff that were not resolved in the
10 stipulation?
11 A Yes,there is one issue.The Company and
12 Staff were not able to reach agreement on whether or not
13 the Commission should approve an overall cost cap on the
14 construction costs that would be applied at the time of
15 the next general rate case.
16 Q And what is the Company's position on that
17 issue?
18 A The Company opposes an overall cost cap,
19 or a hard cap,on the costs for a couple of reasons that
20 we have identified in testimony and I'm just going to
21 quickly summarize what we've said in the testimony so
22 it's all in one place.A hard cap would be unprecedented
23 in our view.We're not aware of any other previous CPCN
24 decision where a cost was set prior to the facilities
25 being constructed.We also believe it's unnecessary.
CSB REPORTING 116 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 The stipulation itself includes a numberO2ofthosecustomerprotectionprovisionsthatIjust
3 outlined for you in the stipulation,including the cap on
4 the RTM,as well as the finding that we know we will be
-5 subject to a prudence review for any costs over those
6 estimates in a rate case,and then as well,a hard cap
7 would essentially operate to disallow costs that are
8 otherwise prudently incurred.Staff's own testimony
9 shows that costs could exceed the estimate and result in
10 reasonable expectation of benefits in a breakeven
11 analysis,and Mr.Link's testimony in this case actually
12 updates that breakeven analysis with Uinta removed from
13 that analysis,so even if costs exceed,there is a point
14 where it does flip around,but there is a reasonable
15 point above the current estimate where it could still be
16 prudently-incurred costs and we don't believe that should
17 be cut off at this premature stage of the project
18 development.
19 And then,lastly,you know,we believe a
20 hard cap below the current estimate as proposed by
21 Monsanto would be a disincentive and highly punitive and
22 essentially would provide a disincentive for the Company
23 to pursue this project,as well as any other economic
24 opportunity for customers in the future.
25 Q Ms.Steward,does that conclude your
CSB REPORTING 117 STEWARD (Di)
208.890.5198 Rocky Mountain Power
1 remarks in the stipulation this morning?
2 A It does.
3 MS.McDOWELL:Ms.Steward is available
4 for cross-examination.
5 COMMISSIONER ANDERSON:Let's start with
6 Monsanto.
7 MR.BUDGE:Thank you,Mr.Chairman.
8
9 CROSS-EXAMINATION
10
11 BY MR.BUDGE:
12 Q Good morning,Ms.Steward.
13 A Good morning.
14 Q Just a couple of clarification points with
15 respect to the stipulation I wanted to ask you.If you
16 could,please,turn to paragraph 18 on page 6 of the
17 stipulation.
18 COMMISSIONER KJELLANDER:Which page are
19 you at?
20 MR.BUDGE:That was on the settlement
21 stipulation on page 6,paragraph 18.
22 Q BY MR.BUDGE:And you discussed this a
23 little bit in your live testimony,but that provision
24 provides that the parties agree the Company would bear
25 the risks related to any portion of the wind projects
CSB REPORTING 118 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 that do not qualify for the PTCs due to completion delaysO2beyondthetimelines,and then focus on the next line,
3 "the timelines associated with the five percent safe
4 harbor."
5 A Yes.
6 Q And my question is to qualify for the PTCs
7 in addition to the safe harbor,isn't there also a
8 requirement that the project be in-service and
9 operational by November of 2020?
10 A I believe it is December 31st,2020.
11 Q December 31st,2020?
12 A Yes.
13 Q But it seems like if you're bearing the
14 risks in the settlement associated with the five percent
15 safe harbor,but not accepting the risks relative to the
16 project not coming on-line and be completed by that
17 in-service deadline,the reason it jumped out at me,when
18 I was comparing this stipulation with the Wyoming
19 settlement stipulation that the Company entered into with
20 WIEC,you have about the same paragraph in paragraph
21 80 00)in the Wyoming stipulation and it has the same
22 language,but it does not have --the period comes after
23 the timeline,so the Company is limiting its risks here
24 to those associated with the PTCs only relating to the
25 five percent safe harbor,but not relating to other
CSB REPORTING 119 STEWARD UK)
208.890.5198 Rocky Mountain Power
1 risks,so my question was,was the Company intending toO2leave--not bear risks with other aspects that may cause
3 the PTCs not to be authorized?
4 A No,it may just be a wording difference in
5 that we copied the --this language was intended to kind
6 of replicate to a great extent the commitment that was
7 under the repowering stipulation,which I don't have that
8 in front of me,but no,we're bearing the risk of
9 qualifying the PTCs for events that are within our
10 control,including reaching that five percent safe
11 harbor.
12 Q So the Company is bearing the risks that
13 the PTCs would be available,all of those risks?
14 A Yes,to the extent they are within our
15 control,yes.
16 Q And to the extent that the PTCs may not be
17 realized in operation,for example,if the wind didn't
18 blow as much or if the wind blew at night,not during the
19 day or vice versa,the timing of the wind,the actual
20 accrual of the PTCs going forward that is based on
21 production a kilowatt-hour,those are risks that still
22 remain with the ratepayers;correct?
23 A Correct.We are not assuming the risks
24 that the wind will blow.
25 Q I had one other clarifying question,if I
CSB REPORTING 120 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 may.If you would please turn to page 8 of theO2stipulation,paragraph 21,and it states there that if
3 there is a material change in circumstances,such as a
4 change in the projected costs or benefits,the parties
5 agree that the Company may make a filing with the
6 Commission to allow additional review,so I wanted to
7 clarify whether or not there is a material change in
8 circumstance is basically a discretionary determination
9 for the Company alone to make.
10 A Yeah,and I see this as another risk we're
11 assuming in that we will need to make that determination
12 on whether whatever change occurs if it would trigger
13 this provision,and clearly,if we miss that opportunity,
14 that would likely be taken up in the next rate case when
15 we put these resources into rates,so I see that as
16 another risk we are assuming that we will identify what
17 would be considered material.
18 Q So one of the questions I had is after
19 everything was filed in this case,the Company filed on
20 May 1 of 2018 an update of the 2017 IRP,which was the
21 fundamental basis upon which the projects were being
22 justified,and in that update,the update says that the
23 prices are declining and the Company's load forecasts
24 declined rather significantly and there's about a 500
25 megawatt load reduction in the updated IRP from what we
CSB REPORTING 121 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 saw in the original 2017 IRP,so would that be somethingO2theCompanywouldconsidertofallwithinthisparagraph
3 21,a substantial change in circumstances?The prices
4 which are a fundamental issue in this case have declined
5 significantly for electricity or gas or solar and now
6 your updated IRP says our resource imbalance is down 4 or
7 500 megawatts from what we were forecasting before,is
8 that --that's not the type or is the type of material
9 circumstances that would perhaps trigger a review of the
10 Company's proposal?
11 A It's not one that I certainly
12 contemplated.This is more of a change in circumstances
13 of a change in the law or a change in the project
14 implementation,so I think that could be a point that is
15 open to interpretation and a potential disagreement.At
16 that point next year,we will be far enough along in
17 these that it will be --you know,I'm not sure what the
18 implications are and how many costs are incurred by then,
19 but we are looking at this is the point where a prudence
20 determination would be made on whether or not to go
21 forward with these resources and this is essentially the
22 analysis we would present in a rate case after the fact
23 as this is where we made that decision to go forward and
24 to determine what was prudent.
25 Q So you're basically saying that updated
CSB REPORTING 122 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 IRP is not something that you would consider to be a
2 material change that would cause you to go back and
3 review the projects?
4 A Not in my mind,but,you know,Mr.Link
5 handles the IRP and perhaps he would be best to address
6 that.
7 Q So what might be a material change,if
8 costs of constructing the project started to go up
9 significantly,I suppose as those costs went above the
10 estimates for some period of time,the Company would not
11 be as concerned,because they would feel well,we can
12 support in the prudency review process later in a general
13 rate case those additional costs and we're not concerned
14 about them because we still get a rate of return not only
15 on the estimated costs,but the actuals that are higher,
16 but if you reach the point in time when costs got way out
17 of whack and you were worried about the project not
18 providing any benefits to the customer and you may not
19 survive prudency review,is that the type of material
20 change that you had in mind might give the Company an
21 opportunity to come back and revisit it?Is that what
22 you're trying to get at with this paragraph?
23 A Right.I mean,we are pretty confident
24 about our estimates.A lot of the transmission lines,a
25 lot of those costs,we've been through an RFP on the
CSB REPORTING 123 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 engineering,procurement,and construction contract,weO2feelprettyconfidentaboutthesecosts,but when you're
3 out building stuff,you run into things that you're not
4 aware of,and so that's why we don't want to limit our
5 ability to come in and argue that it was still reasonable
6 to go forward,so what those material changes would be,
7 yeah,they're kind of unknown to us at this point,but we
8 want to leave that open for future consideration.
9 Q Okay,one other area of questioning.You
10 had mentioned that the area of disagreement between the
11 Company and Staff that is not resolved is this hard cap
12 issue.
13 A Yes.
14 Q But my understanding is that the Company
15 remains opposed to a hard cap at any level on capital
16 costs or any other aspects of the project.
17 A Yes.
18 Q And while you just testified the Company's
19 quite confident in their cost estimates,you're not
20 confident enough to agree to any kind of a hard cost
21 cap?
22 A Correct.There are always conditions out
23 in the field that may not have been anticipated.
24 MR.BUDGE:Just to clarify with Ms.
25 McDowell,I think her testimony you were putting in at
CSB REPORTING 124 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 this point is only relative to the stipulation and we'llO2comelaterbacktoherothertestimony?
3 MS.McDOWELL:No,that is not correct.
4 MR.BUDGE:We could ask a couple of
5 questions on the other at this point?
6 MS.McDOWELL:Yes,that would be our
7 preference to put in all her testimony and we'd prefer to
8 just have all of the questions be at one time.
9 MR.BUDGE:Okay,thank you.
10 Q BY MR.BUDGE:Just a couple more,if I
11 may,relative to your supplemental direct and I wanted to
12 just clarify a couple of points.If you could look,
13 please,to your supplemental direct testimony and that
14 had a date on it of January 2018.If I printed it right,
15 at the very end of your testimony,you had an Exhibit
16 No.43.
17 A Yes.
18 Q Is that exhibit prepared based upon the
19 Company's proposed scenario of medium gas,medium CO2
20 prices,is that the basis of the preparation of that?
21 A No,this is an actual revenue requirement
22 calculation,not the economic analysis,so this is the
23 costs that are included in that economic analysis.
24 Q So if I understand Table 1 correctly,and
25 I'm looking at the net customer impact,is my
CSB REPORTING 125 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 understanding correct that even with the projects asO2currentlyestimatedandproposedbytheCompany,the
3 ratepayers can expect to have their rates go up in each
4 of those years,'20,'21,'22,and '23,as shown by this
5 table?
6 A Well the resources changed since this
7 table was filed.We had a second supplemental where we
8 added in Ekola Flats and took out McFadden Ridge,and
9 then where we're currently at is without Uinta,so these
10 costs are representative of what --
11 Q But the numbers may change,but customers,
12 isn't it true,can still expect to have their rates go up
13 in the early years of the project?
14 A Yes,except they are limited in the
15 stipulation that there would be no net surcharge through
16 the RTM.
17 Q I'm trying to just get a handle on that
18 amount.When I looked at your second supplemental direct
19 testimony,and that was filed a month later in February,
20 on page 2,you made the statement that the annual,
21 updated annual,estimate rate impact to be less than one
22 percent for the first full year of operation,so is that
23 an updated number that customers would expect even under
24 the estimated costs that were filed if there were no
25 overruns,that we're going to have some increase in those
CSB REPORTING 126 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 first two years of the projects and then arguablyO2benefitslateron?
3 A Yes,there will be costs and with the
4 stipulation,they will be deferred for recovery through
5 the rate case,yes.
6 Q Basically that's a product of some of the
7 costs being front-loaded and some of the benefits
8 back-loaded?
9 A That's essentially,yes,how the revenue
10 requirement works,yes.
11 MR.BUDGE:That's all I had.Thank you
12 very much.
13 COMMISSIONER ANDERSON:Thank you,Mr.
14 Budge.Mr.Williams.
15 MR.WILLIAMS:Yes,Mr.Chairman.
16
17 CROSS-EXAMINATION
18
19 BY MR.WILLIAMS:
20 Q Good morning,Ms.Steward.
21 A Good morning.
22 Q I want to talk to you about the
23 stipulation and first off,when your counsel was
24 discussing it or made a statement with respect to the
25 process in the hearing,it was something to the effect
CSB REPORTING 127 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 that with the stipulation,the issues are narrowed down
2 to essentially one issue.Is it your understanding that
3 the intervenors have also agreed that the issue is
4 narrowed down to one issue,the hard cap,or are there
5 other issues that were involved in negotiations,but
6 somehow weren't also resolved?
7 A No,the issues have been narrowed to the
8 stipulation between the Company and the Staff,although
9 we think some of those provisions also address the issues
10 raised by other parties.
11 Q Thank you,and when we get to the terms of
12 the stipulation,No.9,the very first one is that
13 there's an agreement between Staff and the Company and
14 the stipulation that there be a certificate issued under
15 Idaho Code 61-526,so am I to interpret this paragraph as
16 the Company's dropping its request for binding ratemaking
17 treatment?
18 A Yes,the stipulation does not address
19 binding ratemaking treatment,so the Company has
20 effectively with the stipulation withdrawn its request
21 for approval of that.
22 Q Then I want to turn to paragraph 14 of the
23 stipulation and this is the flow-through,if you will,
24 and I'll read --I'll paraphrase it,but the stipulating
25 parties agree the Company will maintain a cap on total
CSB REPORTING 128 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 costs of the stipulated projects not to exceed an amount
2 of benefits through the ECAM,but then when I read the
3 very last sentence,any costs above the cap will be
4 deferred as a regulatory asset for recovery to be set in
5 the next general rate case,so in effect,isn't this soft
6 cap through the RTM and the ECAM really just simply a
7 deferral of potential cost increases that could occur
8 later in a general rate case?
9 A Yes.
10 Q Okay.I want to turn to paragraph 17 of
11 the stipulation.Okay,the first sentence says,"The
12 stipulating parties agree that -the Company will bear the
13 risks related to construction costs overruns associated
14 with the stipulated projects.As such,the Company will
15 not be allowed to recover any imprudent costs or costs
16 due to Company mismanagement."Isn't that a relatively
17 general statement of ratemaking and cost recovery?
18 A Yes,we're always subject to prudence of
19 costs that we incur;however,the stipulation provides in
20 paragraph --the distinguishing piece about this
21 paragraph is that --if I can find it.The stipulation
22 also provides that Staff will not challenge the costs up
23 to those estimates,except in evidence of mismanagement,
24 but for the costs above that cap,those continued
25 construction cost overruns over the estimates,we fully
CSB REPORTING 129 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 bear the risk of prudence.O 2 Q But with that caveat,isn't most of this
3 paragraph a general statement of ratemaking,the burdens
4 of proof,prudency reviews,obligations of the
5 Commission?
6 A Yes.
7 MR.WILLIAMS:Mr.Chairman,I have no
8 further questions.
9 COMMISSIONER ANDERSON:Thank you.Mr.
10 Olsen,Irrigation Pumpers.
11 MS.OLSEN:Thank you,Mr.Chairman.
12
13 CROSS-EXAMINATION
14
15 BY MR.OLSEN:
16 Q I just have a couple of general questions,
17 Ms.Steward.In your rebuttal testimony and supplemental
18 direct testimony,and then I'll just direct you to your
19 testimony here on page 3,lines 25 through 28 that
20 supports the stipulation,you characterize the Company's
21 projects here as unprecedented and a time-sensitive
22 opportunity and you've used that,I guess,
23 characterization in other areas of the testimony.Is the
24 reason why it's unprecedented is just the fact that you
25 have this window of opportunity and the time sensitivity
CSB REPORTING 130 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 for the production tax credits?O 2 A Yes,those production tax credits are a
3 key element that help make the projects affordable to go
4 forward with right now.They're effectively a large
5 coupon discount of the costs,the transmission line in
6 particular,that would otherwise be incurred later.
7 Q Now,with this unprecedented opportunity,
8 there's also unprecedented risks,aren't there?
9 A No,I don't believe so.These are still
10 traditional resources.We're just able to acquire them
11 at a steeply discounted price or cost because of the
12 PTCs.
13 Q Well,there's some risks related to the
14 time you're putting them in place and this timeline and
15 the Company's actual need for these resources;isn't that
16 correct?
17 A Yes,that is correct.
18 Q Okay;so with these unprecedented projects
19 and these associated risks,doesn't that require
20 sometimes unprecedented ratemaking treatment to be
21 imposed on this project,because I think you had
22 characterized the other intervenors'request for a
23 condition,specifically this hard cap,as unprecedented
24 as well,didn't you?
25 A Yes,it would be unprecedented and there
CSB REPORTING 131 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 are elements of the stipulation,the creation of the RTM,
2 the deferral,there is --it's a new ratemaking treatment
3 that we have not done before,but overall,these are
4 still traditional resources.
5 MS.OLSEN:I have no further questions.
6 COMMISSIONER ANDERSON:Thank you.Mr.
7 Karpen,Staff?
8
9 CROSS-EXAMINATION
10
11 BY MR.KARPEN:
12 Q Yes,good morning,Ms.Steward.
13 A Good morning.
14 Q I'd like to start off talking a little bit
15 or get some clarifications on the stipulation.First of
16 all,I think in one of your earlier statements,you had
17 talked about,and this is in reference to paragraph 15,
18 the $300,000 annual payment to the RTM,you had made the
19 statement up to 300,000 every year.I just want to
20 clarify that it is 300,000 every year with the exception
21 of the first year that will be prorated?
22 A Yes,that's correct.
23 Q And then,secondly,with regard to the RTM
24 generally,you had said that it did provide customer
25 protections,and I believe that Mr.Williams touched on
CSB REPORTING 132 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 this as well,it is true that the RTM recovery provides
2 protection for the customers on an annual basis,but not
3 on the overall cost;is that correct?
4 A Correct,this is an interim mechanism.
5 Q And then,finally,in paragraph 17 on page
6 6 with regard to the risk related to construction cost
7 overruns,et cetera,you would agree,I'm assuming,
8 because it's typed out clearly,that the standard audit
9 functions to verify actual costs and review operational
10 prudence will continue to apply nonetheless?
11 A Yes.
12 Q Okay;so now,generally speaking,I'm
13 going to be referring to your supplemental rebuttal
14 testimony and I would like to talk a little bit about
15 prudence.I know that's a term that you throw around at
16 commissions a lot.In this case at this point in time,
17 we're talking about decisional prudence rather than
18 operational prudence.
19 A Correct.
20 Q Two different things,you would agree?
21 A Yes.
22 Q Decisional prudence,for example,is the
23 decision to move forward with the project or estimate;
24 whereas,operational prudence is did you do it right.On
25 page 3 of your testimony,your supplemental rebuttal --
CSB REPORTING 133 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 excuse me,let me start over.So to be clear,at thisO2stageweareatadecisionalprudencystage,we're not at
3 operational?We're not reviewing if you did it right?
4 A Correct.
5 Q The Company advocates for a soft cap in
6 this case;right?
7 A We did,yes.
8 Q So just to be clear,a soft cap --what do
9 you consider a soft cap?
10 A So in our filing with the RTM,we had
11 proposed that the RTM would track the costs up to the
12 total estimated,but we would still be able to come in
13 and seek prudence of costs over that estimate,so in that
14 aspect,there are elements of the stipulation that are
15 still consistent with that.
16 Q So in reality,is there really anything
17 different between standard ratemaking and a soft cap?
18 A I think so in this context in that we're
19 seeking essentially pre-approval of the projects through
20 the CPCN,that we will --that we are at interim recovery
21 until a rate case would only be up to that estimated
22 amount.
23 Q I guess as far as cost controls,in your
24 testimony on page 3,you state specifically that a soft
25 cap makes a hard cap unnecessary,and a soft cap provides
CSB REPORTING 134 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 the Company the burden of proof on costs incurred aboveO2currentestimates.Isn't that the case in just standard
3 ratemaking?
4 A It is,except we are in kind of a
5 pre-approval and so to protect customers from this
6 pre-approval decision,we propose this soft cap.You
7 know,traditionally,we would come in after the fact and
8 seek recovery and there wouldn't be a soft cap,it would
9 just be the total costs.
10 Q But as far as cost protections,the
11 difference between a soft cap and standard ratemaking is
12 virtually identical;correct?The Company has the burden
13 to show prudence,operational prudence?
14 A Yes.
15 Q So at this stage,at the decisional
16 prudence stage,a hard cap,that would provide an
17 incentive a soft cap wouldn't?
18 A We are already highly motivated to keep
19 costs as low as possible,because we know we're always
20 subject to prudence and we're seeing challenges in this
21 case and we want to make sure we will later be able to
22 get full recovery of those costs,so I don't think it
23 does create a greater incentive for us to control those
24 costs.
25 Q So you wouldn't agree that the soft cap
CSB REPORTING 135 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 formula of just coming in later for a rate case to seek
2 potentially unlimited cost overruns provides a different
3 protection than a hard cap that says do not exceed this
4 amount?
5 A Could you rephrase the beginning of that
6 question?
7 Q Yeah;so a soft cap would essentially
8 delay recovery for the Company until a rate case and
9 prudency is determined;whereas,a hard cap would say
10 you're done.You wouldn't agree that those don't provide
11 different protections?
12 A You know,in my mind,we are still subject
13 to prudence and that's not necessarily an easy hurdle,so
14 no,I'll still struggling with how we are more motivated.
15 We would just be pursuing something where we know we're
16 going to get a disallowance potentially if costs exceed,
17 so I struggle with that distinction,I guess.
18 Q Okay.My last question,you had stated in
19 your cross that you're not aware of any other decisions
20 regarding a hard cap.Has the Company ever agreed to the
21 imposition of a hard cap?
22 A In Idaho or ever?
23 Q Ever.
24 A Yes,we did.As part of a comprehensive
25 settlement in Wyoming,we did agree to a hard cap.
CSB REPORTING 136 STEWARD (X)
208.890.5198 Rocky Mountain Power
1 MR.KARPEN:Thank you.I'm done with
2 this witness.
3 COMMISSIONER ANDERSON:Thank you.Mr.
4 Karpen.Commissioner Kjellander.
5
6 EXAMINATION
7
8 BY COMMISSIONER KJELLANDER:
9 Q Can you hear me okay?
10 A Yes.
11 Q All right.I apologize if the question
12 isn't very artful,so bear with me,but I guess I want to
13 understand more about when you look at the risk to
14 overruns and notification to the Commission,what are you
15 anticipating if you should encounter some overrun risks?
16 Are we going to hear about it before the money is
17 expended?Are we going to hear about it afterwards?Are
18 there any kind of plans to look at maybe quarterly
19 updates or routine reviews and would you anticipate that
20 those would be public in nature with the Commission and
21 the other parties that might be involved in the case?
22 What are you seeing there in terms of that
23 notification?
24 A We have not discussed or really
25 anticipated regular updates.We could certainly do that.
CSB REPORTING 137 STEWARD (Com)
208.890.5198 Rocky Mountain Power
1 It would be --you know,it's sort of undefined and I
2 think it's up to us to determine whether or not if a
3 change in circumstance would trigger that notification.
4 In terms of whether or not that could possibly occur
5 before those costs were incurred or after,we'd very
6 likely be on a very short timeline and so I'm not sure I
7 could specifically answer that without knowing what those
8 circumstances were.
9 Mr.Teply who has a lot of experience in
10 actual project development and implementation can
11 probably describe a little better about what sort of
12 circumstances occur in the field during the
13 implementation or construction that could possibly
14 trigger a change in circumstances.
15 Q I guess the other question I'd like to
16 understand a little bit more,really,and you talk about
17 the opportunity being now and in large part because of
18 the production tax credits,I guess I'm curious about any
19 kind of risk associated with those PTCs,what's the
20 potential for those to go away?Is there any potential
21 for them to go away once you get started?I really would
22 like to understand more about the risk with those.
23 A I think we would love to understand how
24 Congress may act in the future as well.Right now we
25 feel pretty solid that the PTCs are reasonably protected,
CSB REPORTING 138 STEWARD (Com)
208.890.5198 Rocky Mountain Power
1 but,again,we don't know if a change in law would occur.
2 I mean,it passed through the last tax reform.I'm not
3 sure there's a lot of appetite for major changes in tax
4 reform in the next few years again.I'm not that close
5 to the D.C.side of things,but perhaps Ms.Cindy Crane
6 can address that since she has a little more exposure to
7 that side.
8 Q So,then,you're not aware of any
9 discussions with you or your team in relationship to what
10 might happen if the PTCs should go away?
11 A Correct.Well,we've not had discussions,
12 that I've been aware of,that were concerned about those
13 PTCs going away.I mean,we were concerned prior to the
14 tax act that occurred in December,but after that,we
15 feel pretty comfortable that that risk has been
16 resolved.
17 Q So let me,also,and maybe you're not the
18 right person for it,but you're here and,again,I
19 already got the caveat of saying it may not be an artful
20 question,so here it comes,because of these PTCs,your
21 incentive,then,if you get these projects built is to
22 run them as often as you possibly can,probably in front
23 of any other resource that you can;is that correct?
24 A For the wind projects?
25 Q Yes.
CSB REPORTING 139 STEWARD (Com)
208.890.5198 Rocky Mountain Power
1 A They will run as the wind,you know,
2 occurs,so in terms of the dispatch,yes,I think I would
3 probably turn to Mr.Link on that,how it could impact
4 other resources.
5 COMMISSIONER KJELLANDER:Okay,and that's
6 really the question I want to get to is how it might
7 impact other resources,so I guess when that witness
8 shows up,maybe we could have him address that as well,
9 then.Thanks.
10 COMMISSIONER ANDERSON:Commissioner
11 Raper.
12
13 EXAMINATION
14
15 BY COMMISSIONER RAPER:
16 Q Hi.
17 A Hi.
18 Q I have a quick question and it's in
19 relation to your conversation with Mr.Karpen.You were
20 talking hard cap,soft cap previous and you made a
21 statement and then Mr.Karpen took you in a different
22 direction.You said we are seeing challenges in this
23 case and then it trailed off.I'm wondering if you'll
24 elaborate on the challenges that you're seeing in this
25 case.
CSB REPORTING 140 STEWARD (Com)
208.890.5198 Rocky Mountain Power
1 A Right.Well,it is contested,is what IO2meant,by other parties,that they do not support our
3 decision to go forward with these projects and that's
4 actually what I was referring to,not challenges in terms
5 of development or our expected implementation of the
6 projects.
7 Q Or dollars,I guess?
8 A Yes.
9 Q That is what my --
10 A Yes.
11 Q So the challenges in this case are not
12 related to the expense or costs of the project or
13 overruns or what the Company may or may not spend?
14 A Correct.It is just the litigation
15 challenges and that there are parties not supporting the
16 decision to go forward.
17 COMMISSIONER RAPER:Thank you.
18 COMMISSIONER ANDERSON:Thank you.Ms.
19 McDowell,any redirect?
20 MS.McDOWELL:Yes,thank you.
21
22
23
24
25
CSB REPORTING 141 STEWARD (Com)
208.890.5198 Rocky Mountain Power
1 REDIRECT EXAMINATIONO2
3 BY MS.McDOWELL:
4 Q Ms.Steward,if you're not able to answer
5 this,just let me know,but I wanted to see if we could
6 clarify it while you're on the stand.Mr.Budge asked
7 you about changes in the forward price curve and the
8 Company's load and resource studies in the 2017 IRP
9 update.Do you recall those questions?
10 A I recall the reference,yes.
11 Q So do you understand whether those,that
12 demand load forecast and that forward price curve,were
13 incorporated in the Company's supplemental update of its
14 economic analysis in this case?
15 A Yes,that is my understanding that those
16 assumptions of lower price for load forecasts in the IRP
17 update are consistent with our second supplemental
18 filing.
19 Q So there's no change in the IRP update in
20 that respect?
21 A Not to my knowledge,no.
22 Q So Mr.Karpen asked you a question about
23 whether the Company had previously agreed to a cost cap,
24 hard cost cap,in any previous proceedings,do you recall
25 that question?
CSB REPORTING 142 STEWARD (ReDi)
208.890.5198 Rocky Mountain Power
1 A Yes.
2 Q And you said yes,the Company had agreed
3 to a cost cap in Wyoming.Do you recall that?
4 A Yes.
5 Q Can you identify whether that cost cap was
6 at the Company's estimate or at an amount above the
7 Company's estimate?
8 A It is at an amount above the Company's
9 estimate.
10 Q And is that exact amount a confidential
11 number?
12 A The exact amount and the percentage is a
13 confidential number;however,it's essentially the
14 breakeven analysis under a medium,medium scenario.
15 Q And on an approximate basis,can you say
16 whether that amount was above 10 percent or below 10
17 percent?
18 A It was above 10 percent.
19 Q And you explained that that was,that
20 agreement was,in the context of a larger set of
21 stipulations.Can you explain that testimony?
22 A Yes,on the same day we filed three
23 settlements.There was a comprehensive settlement with
24 the Wyoming Industrial Energy Consumers.We broke it out
25 into three distinct settlements because different parties
CSB REPORTING 143 STEWARD (ReDi)
208.890.5198 Rocky Mountain Power
1 were willing to sign on to different pieces of those,so
2 it covered both repowering,as well as these projects,as
3 well as tax reform,and so together,it was quite
4 comprehensive and two of those settlements are still
5 being processed through the Wyoming Commission.
6 Q Did the Commission approve,the Wyoming
7 Commission approve,the settlement related to the CPCN
8 docket?
9 A Yes,they did.
10 Q Commissioner Kjellander asked you some
11 questions about a change in the production tax credit law
12 and do you recall those questions?
O 13 A Yes.
14 Q Does the stipulation at paragraph 18 have
15 provisions and procedures related to the Company's
16 obligations in a change of law circumstance?
17 A Yes.
18 Q Can you briefly describe what obligations
19 the Company would bear if there is a change in law
20 related to the production tax credit provisions?
21 A Yes,and it says that we will make all
22 commercially reasonable efforts to mitigate the loss of
23 value to customers,including cancelling our acquisition
24 or construction of the facilities to the extent practical
25 and cost effective from the customers'perspective.
CSB REPORTING 144 STEWARD (ReDi)
208.890.5198 Rocky Mountain Power
1 Q Does the stipulation provide any kind ofO2disputeresolutionprocessifthere's a question about
3 whether the change in the CPCN provisions constitutes a
4 change of law under the stipulation?
5 A Yes,in that same paragraph,later in that
6 paragraph,it identifies that if there is a dispute
7 regarding the applicability of the Company's actions in
8 the face of a change in law or Force Majeure event,it
9 will be resolved at the Commission in the next general
10 rate case.
11 Q My last question relates to the change in
12 the tax law that occurred in December,does the Company's
13 economic analysis that it has presented in this case
14 fully incorporate the changes in the tax law that
15 occurred in December?
16 A Yes.
17 MS.McDOWELL:That's all I have.
18 COMMISSIONER ANDERSON:Thank you,
19 Ms.Steward.
20 (The witness left the stand.)
21 COMMISSIONER ANDERSON:Call your next
22 witness.
23 MS.McDOWELL:Thank you,we would call
24 Mr.Rick Link.
25
CSB REPORTING 145 STEWARD (ReDi)
208.890.5198 Rocky Mountain Power
1 RICK T.LINK,O 2 produced as a witness at the instance of Rocky Mountain
3 Power,having been first duly sworn to tell the truth,
4 was examined and testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MS.McDOWELL:
9 Q Good morning,Mr.Link.
10 A Good morning.
11 Q Can you please state and spell your full
12 name for the record?
13 A Yes,my name is Rick Link,spelled R-i-c-k
14 L-i-n-k.
15 Q Mr.Link,how are you employed?
16 A I am vice president,resource and
17 commercial strategy for PacifiCorp.
18 Q Are you the same Mr.Rick Link that filed
19 direct testimony in this proceeding in June of 2017?
20 A Yes.
21 Q And since that time have you also filed
22 rebuttal testimony,supplemental direct testimony,second
23 supplemental direct testimony,supplemental rebuttal
24 testimony,and just on Tuesday settlement testimony?
25 A Yes.
CSB REPORTING 146 LINK (Di)
208.890.5198 Rocky Mountain Power
1 Q Do you have any changes or correctionS to
2 your prefiled testimony?
3 A No.
4 Q If I were to ask you the questions that
5 are set forth in your prefiled testimony today,would
6 your answers here be the same?
7 A Yes.
8 MS.McDOWELL:Commissioner Anderson,we'd
9 move that the prefiled testimony and exhibits of Mr.Link
10 be spread upon the record as if read.
11 COMMISSIONER ANDERSON:Without objection,
12 we will spread Mr.Link's testimony,direct,rebuttal,
13 supplemental direct testimony,supplemental rebuttal,and
14 settlement,across the record as if read.
15 MS.McDOWELL:Thank you.
16 (The following prefiled direct,rebuttal,
17 supplemental direct,second supplemental direct,
18 supplemental rebuttal,and settlement testimonies of Mr.
19 Rick Link are spread upon the record.)
20
21
22
23
24
25
CSB REPORTING 147 LINK (Di)
208.890.5198 Rocky Mountain Power
1 Q.Please state your name,business address,and
2 position with PacifiCorp.
3 A.My name is Rick T.Link.My business address is
4 825 NE Multnomah Street,Suite 600,Portland,Oregon
5 97232.My position is Vice President,Resource and
6 Commercial Strategy.I am testifying on behalf of Rocky
7 Mountain Power,a division of PacifiCorp.
8 Q.Please describe the responsibilities of your
9 current position.
10 A.I am responsible for PacifiCorp's integrated
11 resource plan ("IRP"),structured commercial business and
12 valuation activities,long-term commodity price
13 forecasts,long-term load forecasts,and environmental
14 strategy and policy activities.Most relevant to this
15 docket,I am responsible for the economic analysis used
16 to screen system resource investments and for conducting
17 competitive request for proposal ("RFP")processes
18 consistent with applicable state procurement rules and
19 guidelines.
20 Q.Please describe your professional experience
21 and education.
22 A.I joined PacifiCorp in December 2003 and
23 assumed the responsibilities of my current position in
24 September 2016.Over this time period,I held several
25 analytical and leadership positions responsible for
148 Link,Di -1RockyMountainPower
1 developing long-term commodity price forecasts,pricingO2structuredcommercialcontractopportunitiesand
3 developing financial models to evaluate resource
4 investment opportunities,negotiating commercial contract
5 terms,and overseeing development of PacifiCorp's
6 resource plans.I was responsible for delivering
7 PacifiCorp's 2013,2015,and 2017 IRPs;have been
8 directly involved in several resource RFP processes;and
9 performed economic analysis supporting a range of
10 resource investment opportunities.Before joining
11 PacifiCorp,I was an energy and environmental economics
12 consultant with ICF Consulting (now ICF International)
13 from 1999 to 2003,where I performed electric-sector
14 financial modeling of
15 /
16
17 /
18
19 /
20
21
22
23
24
25
149 Link,Di -la
Rocky Mountain Power
1 environmental policies and resource investment
2 opportunities for utility clients.I received a Bachelor
3 of Science degree in Environmental Science from the Ohio
4 State University in 1996 and a Masters of Environmental
5 Management from Duke University in 1999.
6 Q.Have you testified in previous regulatory
7 proceedings?
8 A.Yes.I have testified in proceedings before the
9 Wyoming Public Service Commission,the Utah Public
10 Service Commission,the Public Utility Commission of
11 Oregon,and the Washington Utilities and Transportation
12 Commission.
13 PURPOSE AND SUMMARY OF TESTIMONY
14 Q.What is the purpose of your testimony?
15 A.I present and explain the economic analysis
16 that supports PacifiCorp's decision to construct or
17 procure four new Wyoming wind resources with a total
18 capacity of 860 megawatts ("MW")(collectively,the "Wind
19 Projects"),and the decision to construct the
20 "Aeolus-to-Bridger/Anticline Line"and construct the 230
21 kV Network Upgrades (collectively,the "Transmission
22 Projects").1 The Transmission Projects
23 /
24 /
25 /
150 Link,Di -2
Rocky Mountain Power
1 /
2
3 /
4
5 /
6
7
8
9
10
11
12 1 As more specifically described in the testimony of Mr.Rick A.
Vail,the Transmission Projects include:(1)a new 140-mile,500 kV
O 13 transmission line segment and associated infrastructure running from
the new Aeolus substation near Medicine Bow,Wyoming,to the new
14 Anticline substation located near the existing Jim Bridger
substation,which includes construction of the new Aeolus and
15 Anticline substations;(2)a new five-mile,345 kV transmission line
that will extend from the proposed Anticline substation to the
16 existing Jim Bridger substation,which includes modifications at the
existing Jim Bridger substation to allow termination of the new 345
17 kV line;(3)installation of a voltage control device at the Latham
substation;(4)a new 16-mile,230 kV transmission line running from
18 the Company's existing Shirley Basin substation to the proposed
Aeolus substation,which requires modifications to the Shirley Basin
19 substation and interconnection facilities in the new Aeolus
substation to accommodate the new line;(5)reconstruction of four
20 miles of an existing 230 kV transmission line between the proposed
Aeolus substation and the Freezeout substation,which requires
21 modifications to the Freezeout substation and interconnection
facilities in the new Aeolus substation to accommodate the rebuilt
22 line;and (6)reconstruction of 14 miles of an existing 230 kV
transmission line between the Freezeout substation and the Standpipe
23 substation,which requires modifications to the Freezeout and
Standpipe substations to accommodate the rebuilt line.Items 1
24 through 3 are collectively referred to as the
"Aeolus-to-Bridger/Anticline Line,"and items 4 through 6 are
25 collectively referred to as the "230 kV Network Upgrades."
151 Link,Di -2a
Rocky Mountain Power
1 enable interconnection of the new wind resources.MyO2testimonydemonstratesthatPacifiCorp's proposals to
3 construct or acquire approximately 860 MW of new Wind
4 Projects and construct the Transmission Projects
5 (collectively,the "Combined Projects")is in the public
6 interest.My testimony also summarizes PacifiCorp's
7 assessment of new Wyoming wind resources and the
8 Aeolus-to-Bridger/Anticline Line in its 2017 IRP.
9 Q.Please summarize your testimony.
10 A.PacifiCorp's economic analysis supports
11 investments in the Combined Projects.The Wind Projects,
12 which are enabled by the Transmission Projects,will
13 generate federal production tax credits ("PTCs")for ten
14 years;produce zero-fuel-cost energy that will lower net
15 power costs ("NPC");generate renewable-energy credits
16 ("RECs"),which can be sold in the market to create
17 additional revenues that would lower net customer costs;
18 and help decarbonize PacifiCorp's resource portfolio,
19 which will mitigate long-term risk associated with
20 potential future state and federal policies targeting
21 carbon dioxide ("CO2")emissions reductions from the
22 electric sector.
23 The Transmission Projects will relieve
24 congestion on the current transmission system in eastern
25 Wyoming,enable new wind resource interconnections,
152 Link,Di -3
Rocky Mountain Power
1 provide critical voltage support to the WyomingO2transmissionnetwork,improve overall reliability of the
3 transmission system,enhance PacifiCorp's ability to
4 comply with mandated reliability and performance
5 standards,and reduce line losses.Moreover,the proposed
6 transmission-system investments create an opportunity for
7 further increases to the transfer capability across the
8 Aeolus-to-Bridger/Anticline Line with the construction of
9 additional segments of Energy Gateway.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
153 Link,Di -3a
Rocky Mountain Power
1 The Combined Projects will produce customer
2 benefits that significantly outweigh costs.The change in
3 revenue requirement due to the Combined Projects was
4 analyzed using two different modeling tools across nine
5 different scenarios,each with varying natural-gas and
6 CO2 price assumptions.For each of these scenarios,the
7 present-value revenue requirement differential
8 ("PVRR(d)")was calculated from system revenue
9 requirement forecasts through 2050 (through the 30-year
10 life of the Wind Projects),reflecting nominal capital
11 revenue requirement from the Combined Projects,and from
12 system revenue requirement forecasts over a 20-year
13 period,where capital revenue requirement is levelized.
14 The Combined Projects show PVRR(d)benefits in
15 seven of the nine scenarios (all scenarios except two
16 using the lowest natural-gas price assumptions)when
17 calculated from system revenue requirement forecasts
18 through 2050.The present-value reduction to the change
19 in system revenue requirement through 2050 is $137
20 million when assuming medium natural-gas and medium CO2
21 price assumptions.
22 In seven of the nine scenarios (all scenarios
23 except two using the lowest natural-gas price
24 assumptions),the Combined Projects show PVRR(d)benefits
25 when calculated from system revenue requirement forecasts
154 Link,Di -4
Rocky Mountain Power
1 over a 20-year period.Over this 20-year forecast period,
2 the present-value reduction to the change in system
3 revenue requirement due to the Combined Projects ranges
4 between $85 million and $124 million when assuming medium
5 natural-gas and medium CO2 price assumptions.
6 The customer benefits from the Combined
7 Projects increase substantially with higher natural-gas
8 price assumptions and higher CO2 price assumptions.These
9 benefits conservatively do not assign any value to the
10 RECs that will be generated by the Wind
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
155 Link,Di -4a
Rocky Mountain Power
1 Projects.For every dollar assigned to the incremental
2 RECs that will be generated by the Wind Projects,
3 present-value benefits would improve for all scenarios by
4 an additional $34 million when calculated from the change
5 in system revenue requirement through 2050.When
6 calculated from the change in system revenue requirement
7 over a 20-year period,each dollar assigned to the
8 incremental RECs from the Wind Projects would increase
9 PVRR(d)benefits by $26 million.
10 Sensitivity analysis shows that substantial
11 benefits of the Combined Projects persist when paired
12 with PacifiCorp's plans to upgrade or "repower"certain
13 wind resources,which is the subject of a concurrently
14 filed application.Sensitivity analysis also shows that
15 there is additional upside to customer benefits if the
16 new equipment is depreciated over a longer life.
17 2017 INTEGRATED RESOURCE PLAN
18 Q.Did PacifiCorp analyze new Wyoming wind
19 resources and the Aeolus-to-Bridger/Anticline Line in its
20 2017 IRP?
21 A.Yes.The 2017 IRP preferred portfolio,
22 representing PacifiCorp's least-cost,least-risk plan to
23 reliably meet customer demand over a 20-year planning
24 period,includes 1,100 MW of new wind resources located
25 in Wyoming.This wind capacity is enabled by the
156 Link,Di -5
Rocky Mountain Power
1 Aeolus-to-Bridger/Anticline Line,which is also includedO2inthe2017IRPpreferredportfolio.The new wind and
3 Aeolus-to-Bridger/Anticline Line are assumed to be placed
4 in service by the end of 2020 so that the new wind
5 resources can qualify for the full value of PTCs.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
157 Link,Di -5a
Rocky Mountain Power
1 Q.What led PacifiCorp to include 1,100 MW of newO2WyomingwindresourcesandtheAeolus-to-Bridger
3 Anticline Line in its 2017 IRP preferred portfolio?
4 A.All of the resource portfolios produced during
5 the initial stages of the portfolio-development phase of
6 the 2017 IRP contained new Wyoming wind resources in
7 2021,which for modeling purposes was used as a proxy
8 on-line date for PTC-eligible wind achieving commercial
9 operation by the end of 2020.At the same time,the
10 load-and-resource balance developed for the 2017 IRP
11 shows that PacifiCorp would not require incremental
12 system capacity to meet its 13-percent planning-reserve
13 margin until 2028,accounting for assumed coal unit
14 retirements,incremental energy efficiency savings,and
15 available wholesale-power market purchase opportunities.
16 These results indicated that PTC-eligible wind resources
17 located in wind-rich areas like Wyoming provide customer
18 benefits.
19 During the initial stages of portfolio
20 development for the 2017 IRP,the amount of Wyoming wind
21 capacity that routinely appeared in 2021 was limited by
22 transmission congestion on PacifiCorp's existing 230 kV
23 transmission system.This congestion affects energy
24 output from resources in eastern Wyoming where there is
25 substantial potential to develop high-quality,low-cost
158 Link,Di -6
Rocky Mountain Power
1 wind resources.Wyoming resource selections at or near
2 the limitation on Wyoming wind capacity caused by
3 transmission constraints indicated clear potential for
4 incremental customer benefits if incremental transmission
5 is added to accommodate more PTC-eligible wind resources
6 located in Wyoming.
7 To assess these potential incremental benefits,
8 PacifiCorp reviewed components of its Energy Gateway
9 transmission project to identify specific sub-
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
159 Link,Di -6a
Rocky Mountain Power
1 segments that could access additional new Wyoming wind
2 resources.In performing this review,PacifiCorp looked
3 at the transmission interconnection queue and determined
4 that sub-segment D2 (the Aeolus-to-Bridger/Anticline
5 Line)of the Energy Gateway transmission project could
6 access a sizable volume of new wind projects being
7 developed in the Aeolus area.PacifiCorp then developed
8 an initial,high-level cost estimate for the
9 Aeolus-to-Bridger/Anticline Line that was used for an
10 initial Aeolus-to-Bridger/Anticline sensitivity assuming
11 650 MW of incremental transfer capability and 900 MW of
12 new Wyoming wind resources.
13 Q.Why did PacifiCorp assume new wind resource
14 capacity in excess of the assumed incremental transfer
15 capability of the Aeolus-to-Bridger/Anticline Line in
16 this initial sensitivity?
17 A.The Aeolus-to-Bridger/Anticline Line can enable
18 new resource interconnections in excess of the transfer
19 capability of the line.PacifiCorp's preliminary
20 sensitivity in the 2017 IRP assumed the
21 Aeolus-to-Bridger/Anticline Line would support at least
22 900 MW of new resource interconnections.The assumed
23 level of new wind resources is higher than the assumed
24 incremental transfer capability of the transmission line
25 because wind resources do not generate at their full
160 Link,Di -7
Rocky Mountain Power
1 capability in all hours of the year.At times when wind
2 resources in southeastern Wyoming are operating near full
3 output,other resources in the area can be re-dispatched
4 to accommodate PTC-producing wind generation.
5 Q.What were the results of this initial
6 Aeolus-to-Bridger/Anticline sensitivity?
7 A.The initial sensitivity indicated that there
8 could be economic benefits from aligning development of
9 the Aeolus-to-Bridger/Anticline Line with new,
10 PTC-eligible
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
161 Link,Di -7a
Rocky Mountain Power
1 Wyoming wind resources.Based on the promising results
2 from this initial sensitivity,PacifiCorp reviewed its
3 initial,high-level assumptions to determine how refined
4 inputs would affect potential benefits from the
5 incremental new Wyoming wind resources and the
6 Aeolus-to-Bridger/Anticline Line.
7 PacifiCorp completed power flow and
8 dynamic-stability studies to refine its
9 Aeolus-to-Bridger/Anticline Line assumptions.These
10 studies supported increasing the assumed incremental
11 transfer capability of the new transmission line from 650
12 MW to 750 MW and suggested that it could enable up to
13 1,270 MW of new resource interconnections.PacifiCorp
14 also refined its initial,high-level cost assumptions,
15 reducing the estimated capital cost of the project by
16 over $100 million.
17 In addition,PacifiCorp reviewed its new wind
18 resource cost-and-performance assumptions,initially
19 developed to represent proxy Wyoming wind resources,to
20 focus on specific projects that could be developed in the
21 Aeolus area.Based on this review,PacifiCorp determined
22 that the estimated capital cost for new wind resources
23 could be lowered by 10.7 percent from its initial proxy
24 cost assumptions and that its wind capacity factor
25 assumptions should be reduced from 43 percent to 41.2
162 Link,Di -8
Rocky Mountain Power
1 percent.O 2 In addition to refining its transmission and
3 new wind resource assumptions,PacifiCorp reviewed
4 whether additional benefits from the wind enabled by the
5 Aeolus-to-Bridger/Anticline Line could be quantified.
6 PacifiCorp identified and quantified three additional
7 value streams associated with its participation in the
8 energy imbalance market ("EIM"),improved transmission
9 reliability,and reduced transmission line losses.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
163 Link,Di -8a
Rocky Mountain Power
1 The results from this additional review andO2analysiswereappliedinthefinal2017IRP
3 resource-portfolio screening process,where PacifiCorp
4 conducted additional studies that considered analysis
5 performed in earlier resource-portfolio screening stages.
6 Q.What type of analysis did PacifiCorp consider
7 from earlier resource-portfolio screening stages?
8 A.In earlier stages of its resource-portfolio
9 screening process,PacifiCorp developed a wind repowering
10 sensitivity,where certain existing wind resources
11 qualify for an additional ten years of PTCs after they
12 are upgraded with modern equipment.The wind repowering
13 project,the subject of a concurrently filed application,
14 showed significant net customer benefits across a range
15 of assumptions related to forward market prices and
16 federal CO2 policy based on the Clean Power Plan ("CPP").
17 Considering the significant customer benefits associated
18 with the wind repowering project,PacifiCorp combined its
19 refined assumptions for incremental new Wyoming wind and
20 the Aeolus-to-Bridger/Anticline Line in a study that
21 included wind repowering.
22 Q.What were the results of PacifiCorp's final
23 2017 IRP resource-portfolio screening process that
24 incorporated refined and expanded input assumptions for
25 incremental new Wyoming wind resources and the
164 Link,Di -9
Rocky Mountain Power
1 Aeolus-to-Bridger/Anticline Line?O 2 A.Studies developed for the final 2017 IRP
3 resource-portfolio screening process showed significant
4 net customer benefits relative to other
5 resource-portfolio alternatives.Based on these results,
6 the Aeolus-to-Bridger/Anticline Line and the 1,100 MW of
7 new
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
165 Link,Di -9a
Rocky Mountain Power
1 Wyoming wind resources,both assumed to be placed in
2 service by the end of 2020,were included in the 2017 IRP
3 preferred portfolio.
4 Q.What are the benefits associated with the new
5 Wyoming wind assumed to come online by the end of 2020
6 that was included in the 2017 IRP preferred portfolio?
7 A.This new wind,which was included in the 2017
8 IRP preferred portfolio,will deliver several different
9 benefits for customers.First,these new wind resources
10 will generate PTCs for ten years after being placed in
11 service.The current value of federal PTCs,which is
12 adjusted annually for inflation by the Internal Revenue
13 Service,is $24 per megawatt-hour ("MWh").At a federal
14 and state effective tax rate of 37.95 percent,the
15 current PTC equates to a $38.68 per MWh reduction in
16 revenue requirement that can be passed through to
17 customers.Second,these zero-fuel-cost assets will
18 provide incremental NPC benefits for customers.Third,
19 the new wind facilities will generate RECs,which can be
20 sold in the market to create additional revenues that
21 would lower net customer costs.Fourth,these
22 zero-emissions assets will help to decarbonize
23 PacifiCorp's resource portfolio and mitigate long-term
24 risk associated with potential future state and federal
25 policies targeting CO2 emissions reductions from the
166 Link,Di -10
Rocky Mountain Power
1 electric sector.O 2 Q.What are the benefits associated with the
3 Aeolus-to-Bridger/Anticline Line included in the 2017 IRP
4 preferred portfolio?
5 A.As is the case with the new wind resources,the
6 Aeolus-to-Bridger/Anticline Line will also deliver
7 several benefits for customers.The new line will relieve
8 congestion on the current transmission system in eastern
9 Wyoming and enable the additional wind resource
10 interconnections.As discussed by Mr.Rick A.Vail,the
11 Aeolus-to-
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
167 Link,Di -10a
Rocky Mountain Power
1 Bridger/Anticline Line will also provide critical voltageO2supporttotheWyomingtransmissionnetwork,improve
3 overall reliability of the transmission system,enhance
4 PacifiCorp's ability to comply with mandated reliability
5 and performance standards,reduce line losses,and
6 creates an opportunity for further increases to the
7 transfer capability across the Aeolus-to-Bridger/
8 Anticline Line with the construction of additional
9 segments of Energy Gateway.
10 Q.Did PacifiCorp include an action item for new
11 Wyoming wind resources in its 2017 IRP action plan?
12 A.Yes.The 2017 IRP action plan,which lists the
13 specific steps PacifiCorp will take over the next two to
14 four years to deliver resources in the preferred
15 portfolio,includes the following action item associated
16 with the new Wyoming wind resources:
17 PacifiCorp will issue a wind resource request forproposals(RFP)for at least 1,100 MW of Wyoming wind
18 resources that will qualify for federal wind production
tax credits and achieve commercial operation by December
19 31,2020.
o April 2017,notify the Utah Public Service
20 Commission of intent to issue the Wyoming
wind resource RFP.
21 o May-June,2017,file a draft Wyoming wind
RFP with the Utah Public Service
22 Commission and the Washington Utilities
and Transportation Commission.
23 o May-June,2017,file to open a Wyoming
wind RFP docket with the Public Utility
24 Commission of Oregon and initiate the
Independent Evaluator RFP.
25 o June-July,2017,file a draft Wyoming wind RFP
168 Link,Di -11RockyMountainPower
1 with the Public Utility Commission of Oregon
and file a Public Convenience and Necessity
2 (CPCN)application with the Public Service
Commission of Wyoming.
3 o By August 2017,obtain approval of the Wyoming
wind resource RFP from the Public Utility
4 Commission of Oregon,the Utah Public Service
Commission and the Washington Utilities and
5 Transportation Commission.
o By August 2017,issue the Wyoming wind RFP to
6 the market.
o By October 2017,Wyoming wind RFP bids are due.
7 o November-December,2017,complete initial
shortlist bid evaluation.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
169 Link,Di -lla
Rocky Mountain Power
1 o By January 2018,complete final shortlist bid
evaluation,seek acknowledgment of the final
2 shortlist from the Public Utility Commission ofOregon,and seek approval of winning bids from
3 the Utah Public Service Commission.
o By March 2018,receive CPCN approval from the
4 Wyoming Public Service Commission.
o Complete construction of new wind projects by
5 December 31,2020.2
6 Q.Please describe the resource procurement
7 requirements in PacifiCorp's Oregon and Utah
8 jurisdictions applicable to the new Wyoming wind resource
9 action item included in the 2017 IRP action plan.
10 A.The Public Utility Commission of Oregon
11 established competitive bidding requirements for certain
12 resource acquisitions applicable to Oregon's
13 investor-owned utilities (the Competitive Bidding
14 Guidelines).3 Because of the multi-state regulatory
15 approach for cost recovery of PacifiCorp's generation
16 assets and NPC,the new Wyoming wind resources will be
17 subject to these Competitive Bidding Guidelines as it
18 relates to cost recovery for Oregon's allocated share of
19 costs.The new Wyoming wind resources described in the
20 2017 IRP action plan could exceed the 100 MW threshold
21 size for any given project as established by the
22 Competitive Bidding Guidelines.Therefore,procurement of
23 these Wyoming wind resources is governed by these
24 guidelines.
25 In addition,Utah's Energy Resource Procurement
170 Link,Di -12RockyMountainPower
1 Act requires a competitive solicitation process before
2 the acquisition of renewable resources greater than 300
3 MW.4 While it is not certain whether a single wind
4 resource acquired through a competitive bidding process
5 will exceed 300 MW,PacifiCorp is proceeding with filings
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23 2 PacifiCorp 2017 Integrated Resource Plan,Volume I at 16-17 (Apr.
4,2017).
24 3 The Competitive Bidding Guidelines were established by OPUC Order
25
N4 Oe6-U44a6hCnodDocken.UM 514181
-201 et.seq.
171 Link,Di -12a
Rocky Mountain Power
1 under the Utah Energy Resource Procurement Act becauseO2thetotalnewwindresourcecapacityassumedtocome
3 online by the end of 2020 that is in the 2017 IRP
4 preferred portfolio exceeds the 300 MW threshold
5 established by Utah's statute.
6 Q.Please summarize PacifiCorp's progress with the
7 Wyoming wind resource procurement action item outlined in
8 the 2017 IRP action plan.
9 A.PacifiCorp notified the Utah Public Service
10 Commission ("UPSC")of its intent to issue the Wyoming
11 wind resource RFP (the "2017R RFP")on April 17,2017.
12 This notification initiated the process for the UPSC to
13 hire an independent evaluator ("IE")to oversee the 2017R
14 RFP process.PacifiCorp subsequently filed its draft
15 2017R RFP with the UPSC on June 16,2017.The draft 2017R
16 RFP is seeking bids for Wyoming wind resources that can
17 be placed in service by the end of 2020 and that are
18 capable of interconnecting to,and/or delivering energy
19 and capacity across,PacifiCorp's transmission system in
20 Wyoming.PacifiCorp is encouraging bidders to offer
21 proposals under a range of different structures,
22 including power purchase agreements ("PPAs")and
23 build-transfer agreements.
24 PacifiCorp also filed an application with the
25 Public Utility Commission of Oregon requesting that a
172 Link,Di -13
Rocky Mountain Power
1 docket be opened to approve the 2017R RFP and to appointO2itsownIEtooverseethe2017RRFPprocess.
3 Since the 2017 IRP was filed,PacifiCorp
4 determined that the 2017R RFP does not need to be filed
5 and approved by the Washington Utilities and
6 Transportation Commission.
7 In his testimony,Mr.Chad A.Teply addresses
8 the construction schedule for the new Wyoming wind
9 resources.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
173 Link,Di -13a
Rocky Mountain Power
1 Q.What is the timing of the 2017R RFP and howO2doesitcomparewithPacifiCorp's proposed Wyoming CPCN
3 schedule?
4 A.PacifiCorp anticipates releasing the 2017R RFP
5 to the market by the end of August 2017 and receiving
6 bids in the first half of October 2017.PacifiCorp plans
7 to have its analysis of bids completed in early January
8 2018.After finalizing its bid analysis,PacifiCorp will
9 make a supplemental filing in this docket,so that
10 parties and the Commission can review and respond to
11 project-specific information and the associated economic
12 analysis confirming the net customer benefits from the
13 Combined Projects.Maintaining implementation schedules
14 for the Wind Projects,the Transmission Projects,and the
15 2017R RFP will require a conditional Wyoming CPCN,
16 subject to final acquisition of all rights-of-ways,for
17 the Transmission Projects under the schedule included in
18 the application.
19 Q.Why will PacifiCorp's benchmark resources play
20 an important role in the 2017R RFP?
21 A.PacifiCorp's benchmark resources will provide
22 an alternative contracting-and-implementation cost basis
23 that reflects competitive market-equipment-and-
24 construction costs while promoting participation from
25 market bids offering other project-delivery structures.
174 Link,Di -14
Rocky Mountain Power
1 PacifiCorp anticipates receiving bids in response to the
2 2017R RFP under a range of structures.Development and
3 submittal of benchmark resources expand competitive-
4 market offerings under a commercial structure that would
5 otherwise not be available.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
175 Link,Di -14a
Rocky Mountain Power
1 Q.Why is PacifiCorp not waiting until completion
2 of the 2017R RFP to file its applications with states for
3 approval of the Wind Projects?
4 A.The Combined Projects under review in this
5 Application are unique.The Wind Projects and
6 Transmission Projects are time-sensitive and codependent.
7 These unique attributes make it impossible to complete
8 the 2017R RFP before initiating review of the
9 Transmission Projects without jeopardizing the in-service
10 dates that are critical to delivering the customer
11 benefits summarized later in my testimony.As described
12 by Mr.Vail,the critical-path schedule for the
13 Transmission Projects is the CPCN procedural schedule.If
14 PacifiCorp were to wait for the 2017R RFP to finish in
15 the first quarter of 2018 to begin lengthy resource
16 review processes,it would not be possible to place the
17 Transmission Projects in service by the end of 2020,
18 which would eliminate the net customer benefits of this
19 time-sensitive opportunity.
20 Nonetheless,PacifiCorp will fully and
21 appropriately demonstrate the net customer benefits of
22 the Combined Projects using market-based information from
23 competitive procurement processes.To support this
24 objective,PacifiCorp has initiated this process with
25 proxy benchmark resource information that can ultimately
176 Link,Di -15
Rocky Mountain Power
1 be validated using project-specific information and
2 associated economic analysis from the 2017R RFP.
3 Q.Did PacifiCorp include an action item for the
4 Aeolus-to-Bridger/Anticline Line in its 2017 IRP action
5 plan?
6 A.Yes.The 2017 IRP action plan includes the
7 following action item associated with the Aeolus-to-
8 Bridger/Anticline Line:
9 By December 31,2020,PacifiCorp will build the
140-mile,500 kV transmission line running from
10 the Aeolus substation near Medicine Bow,
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
177 Link,Di -15a
Rocky Mountain Power
1 Wyoming,to the Jim Bridger power plant (a
sub-segment of the Energy Gateway West
2 transmission project).This includes pursuing
regulatory review and approval as necessary.
3 o June-July 2017,file a CPCN application
with the Wyoming Public Service
4 Commission.
o By March 2018,receive conditional CPCN
5 approval from the Wyoming Public Service
Commission pending acquisition of rights
6 of way.
o By December 2018,obtain Wyoming
7 Industrial Siting permit and issue EPC
limited notice to proceed.
8 o Complete construction of the transmission
line by December 31,2020.5
9
10 Q.Please summarize PacifiCorp's progress with the
11 Aeolus-to-Bridger/Anticline Line action item in the 2017
12 IRP action plan.
13 A.This application is being filed consistent with
14 the 2017 IRP action plan to pursue regulatory review and
15 approval.Mr.Vail addresses the construction schedule
16 for the Aeolus-to-Bridger/Anticline Line and the 230 kV
17 Network Upgrades identified in this Application.
18 SYSTEM MODELING METHODOLOGY
19 Q.Please summarize the methodology PacifiCorp
20 used in its system analysis of the Combined Projects.
21 A.PacifiCorp relied upon the same modeling tools
22 used to develop and analyze resource portfolios in its
23 2017 IRP to refine and update its analysis of the
24 Combined Projects.These modeling tools calculate system
25 PVRR by identifying least-cost resource portfolios and
178 Link,Di -16
Rocky Mountain Power
1 dispatching system resources over a 20-year forecast
2 period (2017-2036).Net customer benefits are calculated
3 as the PVRR(d)between two simulations of PacifiCorp's
4 system.One simulation includes the Combined Projects,
5 and the other simulation excludes the Combined Projects.
6 Customers are expected to realize benefits
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24 5 PacifiCorp 2017 Integrated Resource Plan,Volume I at 17 (Apr.4,
25
2017).
179 Link,Di -16a
Rocky Mountain Power
1 when the system PVRR with the Combined Projects is lower
2 than the system PVRR without the Combined Projects.
3 Conversely,customers would experience increased costs if
4 the system PVRR with the Combined Projects were higher
5 than the system PVRR without the Combined Projects.
6 Q.What modeling tools did PacifiCorp use to
7 perform its system analysis of the Combined Projects?
8 A.PacifiCorp used the System Optimizer ("SO")
9 model and the Planning and Risk model ("PaR")to develop
10 resource portfolios and to forecast dispatch of system
11 resources in simulations with and without the Combined
12 Projects.
13 Q.Please describe the SO model and PaR.
14 A.The SO model is used to develop resource
15 portfolios with sufficient capacity to achieve a target
16 planning-reserve margin.The SO model selects a portfolio
17 of resources from a broad range of resource alternatives
18 by minimizing the system PVRR.In selecting the
19 least-cost resource portfolio for a given set of input
20 assumptions,the SO model performs time-of-day,
21 least-cost dispatch for existing resources and
22 prospective resource alternatives,while considering the
23 cost-and-performance characteristics of existing
24 contracts and prospective demand-side-management ("DSM")
25 resources-all within or connected to PacifiCorp's system.
180 Link,Di -17
Rocky Mountain Power
1 The system PVRR from the SO model reflects the cost of
2 existing contracts,wholesale-market purchases and sales,
3 the cost of new and existing generating resources (fuel,
4 fixed and variable operations and maintenance,and
5 emissions,as applicable),the cost of new DSM resources,
6 and levelized revenue requirement of capital additions
7 for existing coal resources and potential new generating
8 resources.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
181 Link,Di -17a
Rocky Mountain Power
1 PaR is used to develop a chronological unit
2 commitment and dispatch forecast of the resource
3 portfolio generated by the SO model,accounting for
4 operating reserves and the volatility and uncertainty in
5 key system variables.PaR captures volatility and
6 uncertainty in its unit commitment and dispatch forecast
7 by using Monte Carlo sampling of stochastic variables,
8 which include load,wholesale electricity and natural-gas
9 prices,hydro generation,and thermal unit outages.PaR
10 uses the same common input assumptions that are used in
11 the SO model,with resource-portfolio data provided by
12 the SO model results.The PVRR from PaR reflects a
13 distribution of system variable costs,including variable
14 costs associated with existing contracts,
15 wholesale-market purchases and sales,fuel costs,
16 variable operations and maintenance costs,emissions
17 costs,as applicable,and costs associated with energy or
18 reserve deficiencies.Fixed costs that do not change with
19 system dispatch,including the cost of DSM resources,
20 fixed operations and maintenance costs,and the levelized
21 revenue requirement of capital additions for existing
22 coal resources and potential new generating resources,
23 are based on the fixed costs from the SO model,which are
24 combined with the distribution of PaR variable costs to
25 establish a distribution of system PVRR for each
182 Link,Di -18
Rocky Mountain Power
1 simulation.O 2 Q.How has PacifiCorp historically used the SO
3 model and PaR?
4 A.PacifiCorp uses the SO model and PaR to produce
5 and evaluate resource portfolios in its IRP.PacifiCorp
6 also uses these models to analyze resource-acquisition
7 opportunities,resource retirements,resource capital
8 investments,and system transmission projects.The models
9 were used to support the successful acquisition of the
10 Chehalis combined-cycle plant,to support selection of
11 the Lake Side 2 combined-cycle resource through a RFP
12 process,and to evaluate installation of emissions
13 control
14 /
15
16 /
17
18 /
19
20
21
22
23
24
25
183 Link,Di -18a
Rocky Mountain Power
1 equipment.These models will also be used to evaluate
2 bids in the soon-to-be-issued 2017R RFP.
3 Q.Are the SO model and PaR the appropriate tools
4 for analyzing the net customer benefits of the Combined
5 Projects?
6 A.Yes.The SO model and PaR are the appropriate
7 modeling tools when evaluating significant capital
8 investment that influence PacifiCorp's resource mix and
9 affect least-cost dispatch of system resources.The SO
10 model simultaneously and endogenously evaluates capacity
11 and energy trade-offs associated with resource capital
12 projects and is needed to understand how the type,
13 timing,and location of future resources might be
14 affected by the Combined Projects.PaR provides
15 additional granularity on how the Combined Projects are
16 projected to affect system operations,recognizing that
17 key system conditions are volatile and uncertain.
18 Together,the SO model and PaR are best suited to perform
19 a net-benefit analysis for the Combined Projects that is
20 consistent with long-standing least-cost,least-risk
21 planning principles applied in PacifiCorp's IRP.
22 Q.How did PacifiCorp use PaR to assess stochastic
23 system-cost risk associated with the Combined Projects?
24 A.Just as it evaluates resource portfolio
25 alternatives in the IRP,PacifiCorp uses the
184 Link,Di -19
Rocky Mountain Power
1 stochastic-mean PVRR and risk-adjusted PVRR,calculated
2 from PaR study results,to assess the stochastic system
3 cost risk of the Combined Projects.With Monte Carlo
4 sampling of stochastic variables,PaR produces a
5 distribution of system variable costs.The
6 stochastic-mean PVRR is the average of net variable
7 operating costs from the distribution of system variable
8 costs,combined with system fixed costs from the SO
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
185 Link,Di -19a
Rocky Mountain Power
1 model.PacifiCorp uses a risk-adjusted PVRR to evaluate
2 stochastic system cost risk.The risk-adjusted PVRR
3 incorporates the expected value of low-probability,
4 high-cost outcomes.The risk-adjusted PVRR is calculated
5 by adding five percent of system variable costs,from the
6 95th percentile of the distribution of system variable
7 costs,to the stochastic-mean PVRR.
8 When applied to the analysis of the Combined
9 Projects,the stochastic-mean PVRR represents the
10 expected level of system costs from cases with and
11 without the Wind Projects and the Transmission Projects.
12 The risk-adjusted PVRR is used to assess whether the
13 Combined Projects cause a disproportionate increase to
14 system variable costs under low-probability,high-cost
15 system conditions.
16 Q.Did PacifiCorp analyze how other assumptions
17 affect its economic analysis of the Combined Projects?
18 A.Yes.In addition to assessing stochastic system
19 cost risk,PacifiCorp analyzed the Combined Projects
20 under a range of assumptions regarding wholesale market
21 prices and CO2 policy ("price-policy")assumptions.These
22 assumptions drive NPC-related benefits,and so it is
23 important to understand how the net-benefit analysis is
24 affected under a range of potential outcomes.PacifiCorp
25 developed low,medium,and high scenarios for the market
186 Link,Di -20
Rocky Mountain Power
1 price of electricity and natural gas and zero,medium,
2 and high CO2 price scenarios.Each pair of model
3 simulations-with and without the Combined Projects,in
4 both the SO model and PaR-was analyzed under each
5 combination of these price-policy assumptions.I
6 summarize the assumptions for each price-policy scenario
7 later in my testimony.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
187 Link,Di -20a
Rocky Mountain Power
1 PacifiCorp also completed two sensitivity
2 studies to assess how certain factors affect the net
3 benefits of the Combined Projects.The first sensitivity
4 quantifies how the net benefits of the Combined Projects
5 are affected by the depreciable life assumed for the new
6 Wind Projects.PacifiCorp's base analysis assumes a
7 30-year depreciable life when calculating revenue
8 requirement associated with the Wind Projects.
9 Considering that wind facilities with modern equipment
10 might continue operating over a longer period,this
11 sensitivity quantifies the economic impact if the
12 depreciable life of the Wind Projects were reset at 40
13 years.
14 The second sensitivity quantifies how the net
15 benefits of the Combined Projects are affected when
16 paired with the wind repowering project,the subject of a
17 concurrent application.Consistent with PacifiCorp's wind
18 repowering application,this sensitivity assumes
19 approximately 999 MW of existing wind resource capacity
20 is upgraded with modern equipment in the 2019-to-2020
21 time frame.
22 Q.How much new Wyoming wind capacity did
23 PacifiCorp analyze in its economic analysis of the
24 Combined Projects for this Application?
25 A.PacifiCorp assumed approximately 1,180 MW of
188 Link,Di -21
Rocky Mountain Power
1 new Wyoming wind resources for all SO model and PaR
2 simulations that include the Combined Projects.As
3 described by Mr.Teply,this includes approximately 860
4 MW from the Wind Projects,which can achieve commercial
5 operation by year-end 2020.The remaining 320-MW balance
6 of new wind resource capacity is associated with certain
7 qualifying facility projects (the "QF Projects")that are
8 located in the Aeolus area,have executed PPAs with
9 PacifiCorp,and have preferential positions in the
10 transmission interconnection queue.The QF Projects are
11 reasonably expected to interconnect with PacifiCorp's
12 transmission system
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
189 Link,Di -21a
Rocky Mountain Power
1 after the Aeolus-to-Bridger/Anticline Line is placed in
2 service and are assumed to achieve commercial operation
3 at the end of 2021,consistent with the terms in their
4 PPAs.Because the QF Projects are not expected to be able
5 to interconnect with PacifiCorp's transmission system
6 without the Aeolus-to-Bridger/Anticline Line,they are
7 only included in the SO model and PaR simulations that
8 include the Combined Projects.
9 Q.Why is the total capacity of the new Wyoming
10 wind resources included in PacifiCorp's economic analysis
11 of the Combined Projects different from the capacity
12 included in the 2017 IRP preferred portfolio?
13 A.As discussed in the testimony of Mr.Teply,
14 PacifiCorp is seeking approvals for the specific wind
15 projects that it will offer as benchmark resources in the
16 2017R RFP.This includes three projects (Ekola Flats,TB
17 Flats I,and TB Flats II)being developed by a third
18 party totaling approximately 750 MW and a fourth,110-MW
19 project (McFadden Ridge II),which PacifiCorp is
20 developing on a site it controls.The capacity of the
21 specific Wind Projects that will be offered as benchmark
22 resources in the 2017R RFP (approximately 860 MW),when
23 combined with the total capacity of the QF Projects (320
24 MW),totals 1,180 MW.This level of procurement is
25 consistent with PacifiCorp's 2017 IRP action item to
190 Link,Di -22
Rocky Mountain Power
1 procure at least 1,100 MW of Wyoming wind resources.
2 PacifiCorp will evaluate the level of Wyoming wind
3 resource procurement that will maximize customer
4 benefits,up to approximately 1,270 MW of new resource
5 interconnections enabled by the Aeolus-to-Bridger/
6 Anticline Line,based on specific bids submitted in
7 response to the 2017R RFP.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
191 Link,Di -22a
Rocky Mountain Power
1 Q.What key assumptions did PacifiCorp update
2 since analyzing the new Wyoming wind resources and the
3 Aeolus-to-Bridger/Anticline Line in its 2017 IRP?
4 A.Beyond the price-policy assumptions used to
5 analyze a range of NPC-related benefits,PacifiCorp's
6 economic analysis reflects updated assumptions for
7 up-front capital costs,run-rate operating costs,and
8 energy output specific to the Wind Projects and QF
9 Projects described earlier in my testimony.PacifiCorp's
10 analysis assumes an up-front capital investment for the
11 Wind Projects totaling approximately (redacted)and are
12 assumed to operate at a capacity-weighted-average-
13 annual capacity factor of (redacted).The PPA price paid
14 to the QF Projects add (redacted)to total-system NPC
15 beginning 2022,rising to (redacted)by the end of their
16 contract terms in 2041.The QF Projects are assumed to
17 operate at an aggregate capacity factor of 40.7 percent.
18 The cost and performance assumptions for the Wind
19 Projects and the QF Projects studied for this application
20 are summarized n nfide 1 hb meNntf22r
the
22 Aeolus-to-Bridger/Anticline Line is (redacted),
23 consistent with the capital cost assumed in PacifiCorp's
24 2017 IRP.The assumed up-front capital investment for the
25 230 kV Network Upgrades,reflecting costs to interconnect
192 Link,Di -23
Rocky Mountain Power
1 the Wind Projects,total (redacted).The cost and
2 performance assumptions for the Transmission Projects
3 studied for this application are also summarized in
4 Confidential Exhibit No.22.
5 Q.Does PacifiCorp assume that all of the up-front
6 capital costs of the Transmission Projects will be paid
7 by its retail customers?
8 A.No.While the up-front capital cost of the
9 Transmission Projects will contribute to retail-customer
10 rate base,the revenue requirement for these investments
11 will be
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
193 Link,Di -23a
Rocky Mountain Power
1 partially offset by incremental revenue from other
2 transmission customers.The up-front transmission costs
3 will flow into PacifiCorp's formula transmission rate
4 under its Open Access Transmission Tariff ("OATT")and
5 generate revenue credits that offset costs for retail
6 customers.
7 PacifiCorp's merchant function,which uses
8 PacifiCorp's transmission system to serve retail-customer
9 load and to manage retail-customer NPC through off-system
10 market sales and purchases,is the largest user of
11 PacifiCorp's transmission system.However,other
12 transmission customers pay OATT-based transmission rates
13 that generate revenue credits and offset the cost of
14 PacifiCorp's transmission revenue requirement.As
15 discussed in Mr.Vail's testimony,the Transmission
16 Projects are considered network transmission assets under
17 PacifiCorp's OATT and therefore will be given rolled-in
18 treatment under PacifiCorp's transmission formula rate.
19 Over recent history,these revenue credits have accounted
20 for approximately 12 percent of PacifiCorp's transmission
21 revenue requirement.Based on this recent history,
22 PacifiCorp's analysis assumes its retail customers pay 88
23 percent of the revenue requirement from the up-front
24 capital cost for the Transmission Projects after
25 accounting for an assumed 12 percent revenue credit from
194 Link,Di -24
Rocky Mountain Power
1 other transmission customers.
2 Q.How did PacifiCorp model de-rates to its
3 Wyoming 230 kV transmission system when evaluating the
4 Combined Projects?
5 A.In its final 2017 IRP resource-portfolio
6 screening process,PacifiCorp identified and quantified
7 reliability benefits associated with the Aeolus-to-
8 Bridger/Anticline Line.This new transmission project
9 will eliminate de-rates caused by outages on 230 kV
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
195 Link,Di -24a
Rocky Mountain Power
1 transmission-system elements.Historical outages on this
2 part of PacifiCorp's transmission system indicate an
3 average de-rate of 146 MW over approximately 88 outage
4 days per year,which equates to approximately one 146-MW,
5 twenty-four hour outage every four days.Without knowing
6 when these events might occur,de-rates on the existing
7 230 kV transmission system were captured in the SO model
8 and PaR as a 36.5 MW reduction in the transfer capability
9 from eastern Wyoming to the Aeolus area.In simulations
10 that include the Combined Projects,this de-rate
11 assumption was eliminated when the new transmission
12 assets are placed in service at the end of October 2020.
13 Q.How did PacifiCorp model line-loss benefits
14 associated with the Transmission Projects when performing
15 its economic analysis of the Combined Projects?
16 A.Line-loss benefits are only applicable in those
17 simulations where the Transmission Projects are built and
18 therefore were only considered in the simulations that
19 include the Combined Projects.When the Aeolus-to-
20 Bridger/Anticline Line is added in parallel to the
21 existing transmission lines,resistance is reduced,which
22 lowers line losses.With reduced line losses,an
23 incremental 11.6 average MW ("aMW")of energy,which
24 equates to approximately 102 gigawatt hours ("GWh"),will
25 be able to flow out of eastern Wyoming each year.The
196 Link,Di -25
Rocky Mountain Power
1 line-loss benefit was reflected in the SO model and PaR
2 by reducing northeast Wyoming load by approximately 11.6
3 aMW each year.
4 Q.Did PacifiCorp analyze potential EIM benefits
5 in its economic analysis of the Combined Projects?
6 A.Yes.In its final 2017 IRP resource-portfolio
7 screening process,PacifiCorp described how the EIM can
8 provide potential benefits when incremental energy is
9 added to
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
197 Link,Di -25a
Rocky Mountain Power
1 transmission-constrained areas of Wyoming.Unscheduled or
2 unused transmission from participating EIM entities
3 enables more efficient power flows within the hour.With
4 increasing participation in the EIM,there will be
5 increasing opportunities to move incremental energy from
6 Wyoming to offset higher-priced generation in the
7 PacifiCorp system or other EIM participants'systems.The
8 more efficient use of transmission that is expected with
9 growing participation in the EIM was captured in the
10 economic analysis of the Combined Projects by increasing
11 the transfer capability between the east and west sides
12 of PacifiCorp's system by 300 MW (from the Jim Bridger
13 plant to south-central Oregon).The ability to more
14 efficiently use intra-hour transmission from a growing
15 list of EIM participants is not driven by the Combined
16 Projects;however,this increased connectivity provides
17 the opportunity to move low-cost incremental energy out
18 of transmission-constrained areas of Wyoming.
19 ANNUAL REVENUE REQUIREMENT MODELING METHODOLOGY
20 Q.In addition to the system modeling used to
21 calculate present-value net benefits over a 20-year
22 planning period,has PacifiCorp forecasted the change in
23 nominal revenue requirement due to the Combined Projects?
24 A.Yes.The system PVRR from the SO model and PaR
25 was calculated from an annual stream of forecasted
198 Link,Di -26
Rocky Mountain Power
1 revenue requirement over a 20-year time frame,consistent
2 with the planning period in the IRP.The annual stream of
3 forecasted revenue requirement captures nominal revenue
4 requirement for non-capital items (i.e.,NPC,fixed
5 operations and maintenance,etc.)and levelized revenue
6 requirement for capital expenditures.To estimate the
7 annual revenue-requirement impacts of the Combined
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
199 Link,Di -26a
Rocky Mountain Power
1 Projects,capital costs for the Wind Projects and the
2 Transmission Projects need to be considered in nominal
3 terms (i.e.,not levelized).
4 Q.Why is the capital revenue requirement used in
5 the calculation of the system PVRR from the SO model and
6 PaR levelized?
7 A.Levelization of capital revenue requirement is
8 necessary in these models to avoid potential distortions
9 in the economic analysis of capital-intensive assets that
10 have different lives and in-service dates.Without
11 levelization,this potential distortion is driven by how
12 capital costs are included in rate base over time.
13 Capital revenue requirement is generally highest in the
14 first year an asset is placed in service and declines
15 over time as the asset depreciates.
16 Consider the potential implications of modeling
17 nominal capital revenue requirement for a future
18 generating resource needed in 2036,the last year of the
19 2017 IRP planning period.If nominal capital revenue
20 requirement were assumed,the model would capture in its
21 economic assessment of resource alternatives the highest,
22 first-year revenue requirement capital cost without
23 having any foresight into the potential benefits that
24 resource would provide beyond 2036.If nominal capital
25 costs were applied,the model's economic assessment of
200 Link,Di -27
Rocky Mountain Power
1 resource alternatives for the 2036 resource need would
2 inappropriately favor less capital-intensive projects or
3 projects having longer asset lives,even if those
4 alternatives would increase system costs over their
5 remaining life.Levelized capital costs for assets that
6 have different lives and in-service dates is an
7 established way to address these types of distortions in
8 the comparative economic analysis of resource
9 alternatives.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
201 Link,Di -27a
Rocky Mountain Power
1 Q.How did PacifiCorp forecast the annualO2revenue-requirement impacts of the Combined Projects?
3 A.In the simulations that include the Combined
4 Projects,the annual stream of costs for the Wind
5 Projects,including levelized capital and PTCs,the QF
6 Projects,and the Transmission Projects are temporarily
7 removed from the annual stream of costs used to calculate
8 the stochastic-mean PVRR.The differential in the
9 remaining stream of annual costs,which includes all
10 system costs except for those associated with the
11 Combined Projects and the QF Projects,represents the net
12 system benefit caused by the Combined Projects.
13 These data are disaggregated to isolate the
14 estimated annual NPC benefits,other non-NPC
15 variable-cost benefits (i.e.,variable operations and
16 maintenance and emissions costs for those scenarios that
17 include a CO2 price assumption),and fixed-cost benefits.
18 To complete the annual revenue-requirement forecast,the
19 change in costs for the Combined Projects and the QF
20 Projects,including nominal capital revenue requirement
21 and PTCs,are added back in with the annual system net
22 benefits caused by the Combined Projects.
23 Q.Over what time frame did PacifiCorp estimate
24 the change in annual revenue requirement due to the
25 Combined Projects?
202 Link,Di -28
Rocky Mountain Power
1 A.The change in annual revenue requirement wasO2estimatedthrough2050.This captures the full 30-year
3 life of the Wind Projects.
4 Q.What is the assumed life of the Transmission
5 Projects?
6 A.PacifiCorp assumed a 62-year life for the
7 Transmission Projects.The Transmission Projects will
8 continue to provide system benefits well beyond 2050 when
9 the Wind
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
203 Link,Di -28a
Rocky Mountain Power
1 Projects are fully depreciated.These additional benefits
2 are not reflected in PacifiCorp's economic analysis.
3 Q.How did PacifiCorp calculate the annual net
4 benefits caused by the Combined Projects beyond the
5 20-year forecast period used in PaR?
6 A.The PaR-forecast period runs from 2017 through
7 2036.The change in net system benefits caused by the
8 Combined Projects over the 2028-through-2036 time frame,
9 expressed in dollars-per-MWh of incremental energy output
10 from the Wind Projects and the QF Projects,were used to
11 estimate the change in net system benefits from 2037
12 through 2050.This calculation was performed in several
13 steps.
14 First,the net system benefits caused by the
15 Combined Projects were divided by the change in
16 incremental energy expected from the Wind Projects and
17 the QF Projects,as modeled in PaR over the
18 2028-through-2036 time frame.Next,the net system
19 benefits per MWh of incremental energy from the Wind
20 Projects and the QF Projects over the 2028-through-2036
21 time frame were levelized.These levelized results were
22 extended out through 2050 at inflation.The levelized net
23 system benefits per MWh of incremental energy output from
24 the Wind Projects and the QF Projects over the
25 2037-through-2050 time frame were then multiplied by the
204 Link,Di -29RockyMountainPower
1 change in incremental energy output from the Wind
2 Projects and the QF Projects over the same period.
3 Q.Why did PacifiCorp use PaR results from the
4 2028-through-2036 time frame to extend system cost
5 impacts out through 2050?
6 A.Consistent with the 2017 IRP,PacifiCorp's
7 economic analysis of the Combined Projects assumes the
8 Dave Johnston coal plant,located in eastern Wyoming,
9 retires at the end of 2027.When this plant is assumed to
10 retire,transmission congestion affecting
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
205 Link,Di -29a
Rocky Mountain Power
1 energy output from resources in eastern Wyoming,where
2 the Wind Projects and the QF Projects are located,is
3 reduced.The incremental energy output from the Wind
4 Projects and the QF Projects provides more system
5 benefits when not constrained by transmission
6 limitations.Consequently,the net-system benefits caused
7 by the Combined Projects over the 2028-through-2036 time
8 frame,after Dave Johnston is assumed to retire,is
9 representative of net system benefits that could be
10 expected beyond 2036.
11 Q.Did PacifiCorp calculate a PVRR(d)for the
12 Combined Projects using its estimate of annual revenue
13 requirement impacts projected out through 2050?
14 A.Yes.
15 PRICE-POLICY SCENARIOS
16 Q.Please explain why price-policy scenarios are
17 important when analyzing the Combined Projects.
18 A.Wholesale-power prices,often set by
19 natural-gas prices,and the system cost impacts of
20 potential CO2 policies influence the forecast of net
21 system benefits from the Combined Projects.
22 Wholesale-power prices and CO2 policy outcomes affect the
23 value of system energy,the dispatch of system resources,
24 and PacifiCorp's resource mix.Consequently,
25 wholesale-power prices and CO2 policy assumptions affect
206 Link,Di -30
Rocky Mountain Power
1 the NPC benefits,non-NPC variable-cost benefits,andO2systemfixed-cost benefits of the Combined Projects.
3 Because wholesale-power prices and CO2 policy outcomes
4 are both uncertain and important drivers to the economic
5 analysis,PacifiCorp studied the economics of the
6 Combined Projects under a range of different price-policy
7 scenarios.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
207 Link,Di -30a
Rocky Mountain Power
1 Q.What price-policy scenarios did PacifiCorp use
2 in its economic analysis of the Combined Projects?
3 A.PacifiCorp analyzed the Combined Projects under
4 nine different price-policy scenarios.PacifiCorp
5 developed three wholesale-power price scenarios (low,
6 medium,and high),and similarly developed three CO2
7 policy scenarios (zero,medium,and high).The nine
8 price-policy scenarios developed for the economic
9 analysis of the Combined Projects reflect different
10 combinations of these scenario assumptions.
11 Considering that there is a high level of
12 correlation between wholesale-power prices and
13 natural-gas prices,the wholesale-power price scenarios
14 were based on a range of natural-gas price assumptions.
15 This ensures consistency between power price and
16 natural-gas price assumptions for each scenario.
17 PacifiCorp implemented its CO2 policy assumptions through
18 a CO2 price,expressed in dollars-per-ton.
19 While it is unlikely that the CPP will be
20 implemented in its current form,it is possible that
21 future CO2 policies targeting electric-sector emissions
22 could be adopted and impose incremental costs to drive
23 emissions reductions.CO2 price assumptions used in the
24 price-policy scenarios are not intended to mimic a
25 specific type of policy mechanism (i.e.,a tax or an
208 Link,Di -31
Rocky Mountain Power
1 allowance price under a cap-and-trade program),but areO2intendedtorecognizethattheremightbefutureCO2
3 policies that impose a cost to reduce emissions.Table 1
4 summarizes the nine price-policy scenarios used to
5 analyze the Combined Projects.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
209 Link,Di -31a
Rocky Mountain Power
21
Tab e 1.Price-PolicylScenarios
3 Price-Policy Scenario Natural-GasPrices CO2 Price Description(Levelized$/MMBtu)*
Low Gas,Zero CO2 $3.19 $0/ton4
Low Gas,Medium CO2 $3.19 $3.41/ton in 2025 growing to
$14.40/ton in 2036
5 $4.73/ton in 2025 growingtoLowGas,High CO2 $3.19 $38,42/ton in 2036
6 Medium Gas,Zero CO2 $4.07 $0/ton
Medium Gas,Medium CO2 $4.13 $3.41/ton in 2025 growingto
7 $14.40/ton in 2036
Medium Gas,HighCO2 $4.13 $4.73/ton in 2025 growingto
8 $38.42/ton m 2036
High Gas,Zero CO2 $5.83 $0/ton
9 $3.41/ton in 2025 growingtoHighGas,Medium CO2 $5.83 $14.40/ton in 2036
$4.73/ton in 2025 growingto10HighGas,High CO2 $5.83 $38.42/ton in 2036*Nominallevelized Henry Hub natural-gas price from2018 through 2036.
12
13 Q.Please describe the natural-gas price
14 assumptions used in the price-policy scenarios.
15 A.The medium-natural-gas-price assumptions that
16 are paired with zero CO2 prices reflect natural-gas
17 prices from PacifiCorp's official forward price curve
18 ("OFPC")dated April 26,2017.The OFPC uses observed
19 forward market prices as of April 26,2017,for 72
20 months,followed by a 12-month transition to natural-gas
21 prices based on a forecast developed by (redacted).The
22 low-,medium-,and high-natural-gas price assumptions
23 used for all other scenarios were chosen after reviewing
24 a range of credible third-party forecasts developed by
25 (redacted),and the U.S.Department of Energy's Energy
210 Link,Di -32
Rocky Mountain Power
1 Information Administration.Exhibit No.23 shows the
2 range in natural-gas price assumptions from these
3 third-party forecasts relative to those adopted for the
4 price-policy scenarios to evaluate the Combined Projects.
5 The low-natural-gas price assumption was
6 derived from a low-price scenario developed by
7 (redacted),which is based on surging growth in
8 price-inelastic associated gas,
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
211 Link,Di -32a
Rocky Mountain Power
1 technology improvements,stagnant liquefied-natural-gas
2 exports,and an ever-expanding resource base.The
3 medium-natural-gas price assumption,which is used beyond
4 month 84 in the April 2017 OFPC,and in all months when
5 medium-natural-gas prices are paired with medium or low
6 CO2 price assumptions,is based on a base-case forecast
7 from (redacted)that is reasonably aligned with other
8 base-case forecasts.The high-natural-gas price
9 assumption was based on a high-price scenario from
10 (redacted).The high-price scenario is based on
11 risk-aversion,whereby natural-gas developers are
12 reluctant to commit capital before demand,and the
13 associated price response,materializes.This gives rise
14 to exaggerated boom-bust cycles (cyclical periods of high
15 prices and low prices).PacifiCorp smoothed the boom-bust
16 cycle in the third party's high-price scenario because
17 the specific timing of these cycles are extremely
18 difficult to project with reasonable accuracy.
19 Figure 1 shows Henry Hub natural-gas price
20 assumptions from the April 2017 OFPC,low-,medium-,and
21 high-natural-gas price scenarios.The April 2017 OFPC
22 forecast only differs from the medium-natural-gas-price
23 assumption in that it reflects observed-market forwards
24 through the first 72 months followed by a twelve-month
25 transition to (redacted)'s base-case forecast.
212 Link,Di -33
Rocky Mountain Power
2
3 Figure 1.Nominal Natural-Gas Price Scenarios
4 $11 -----
$10 --
5 ,*
6 $8 -
7
10 $2
C
-M-Low Gas ---Med Gas (Apn1201TOFPC)
12 Med Gas -4-High Gas
O 13 ------
14
15 Q.Please describe the CO2 price assumptions used
16 in the price-policy scenarios.
17 A.As with natural-gas prices,the medium-and
18 high-CO2 price assumptions are based on third-party
19 projections from (redacted)and (redacted).Both
20 forecasters assume CO2 prices start in 2025.To bracket
21 the low end of potential-policy outcomes,PacifiCorp
22 assumes there are no future policies adopted that would
23 require incremental costs to achieve emissions reductions
24 in the electric sector.In this scenario,the assumed CO2
25 price is zero.Figure 2 shows the three CO2 price
213 Link,Di -34
Rocky Mountain Power
,-,1 assumptions used to analyze the Combined Projects.illi 2
3 Figure 2.Nominal CO2-Price Scenarios
4 $45
5 540 -
10
11
12 --Zero -Medium -4-High
13O14
15
16 SYSTEM MODELING PRICE-POLICY RESULTS
17 Q.Please summarize the PVRR(d)results calculated
18 from the SO model and PaR through 2036.
19 A.Table 2 summarizes the PVRR(d)results for each
20 price-policy scenario.The PVRR(d)between cases with and
21 without the Combined Projects are shown from the SO model
22 and from PaR,which was used to calculate both the
23 stochastic-mean PVRR(d)and the risk-adjusted PVRR(d).
24 The data that was used to calculate the PVRR(d)results
25 shown in the table are provided as Exhibit No.24.
214 Link,Di -35
Rocky Mountain Power
@ 2
3
4
Table 2.SO Model and PaR PVRR(d)
5 (Benefit)/Cost of the Combinet Projects ($millit n)
PaR Risk-.SO Model PaR Stochastic-6 Price-Policy Scenano AdjustedPVRR(d)Mean PVRR(d)PVRR(d)
7 Low Gas,Zero CO2 $121 $77 $74
Low Gas,Medium CO2 $73 $32 $26
8 Low Gas,High CO2 ($84)($133)($147)
Medium Gas,Zero CO2 ($19)($57)($66)
9 Medium Gas,Medium CO2 ($85)($111)($124)
MediumGas,High CO2 ($156)($224)($242)
10 High Gas,Zero CO2 ($304)($260)($280)
HighGas,Medium CO2 ($318)($272)($293)11 High Gas,High CO2 ($396)($409)($437)
12
13O14 Over a 20-year period,the Combined Projects
15 reduce customer costs in seven out of nine price-policy
16 scenarios price-policy scenarios.This trend occurs in
17 the PVRR(d)calculated from both the SO model and PaR.
18 The only price-policy scenarios without net customer
19 benefits are those assuming the lowest natural-gas prices
20 when paired with either medium or zero-CO2 price
21 assumptions.Under the central price-policy scenario,
22 assuming medium-natural-gas prices and medium-CO2 prices,
23 the PVRR(d)benefits range between $85 million,when
24 based upon SO model results,and $124 million,when based
6 25 upon PaR-risk-adjusted results.
215 Link,Di -36RockyMountainPower
1 The PVRR(d)results show that the benefits of
2 the Combined Projects increase with natural-gas prices
3 and CO2 prices,which increase NPC and other system
4 variable cost benefits.
5 Q.Is there incremental customer upside to the
6 PVRR(d)results calculated from the SO and PaR models
7 through 2036?
8 A.Yes.The PVRR(d)results presented in Table 2
9 do not reflect the potential value of RECs generated by
10 the incremental wind energy output from the Wind
11 Projects.Customer benefits for all price-policy
12 scenarios would improve by approximately $26
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
216 Link,Di -36a
Rocky Mountain Power
1 million for every dollar assigned to the incremental RECs
2 that will be generated from the Wind Projects through
3 2036.Beyond potential REC-revenue benefits,the economic
4 analysis of the Combined Projects does not reflect
5 PacifiCorp's enhanced ability to comply with mandated
6 reliability and performance standards the opportunity for
7 further increases to the transfer capability across the
8 Aeolus-to-Bridger/Anticline Line with the construction of
9 additional segments of the Energy Gateway project.
10 Q.Why do the PaR results tend to show a different
11 level of benefits from Combined Projects when compared to
12 the results from the SO model?
13 A.The two models assess the system impacts of the
14 Combined Projects in different ways.The SO model is
15 designed to dynamically assess system dispatch,with less
16 granularity than PaR,while optimizing the selection of
17 resources to the portfolio over time.PaR is able to
18 dynamically assess system dispatch,with more granularity
19 than the SO model and with consideration of stochastic
20 risk variables;however,PaR does not modify the type,
21 timing,size and location of resources in the portfolio
22 in response to its more detailed assessment of system
23 dispatch.
24 Q.Does one of these two models provide a better
25 assessment of the Combined Projects relative to the
217 Link,Di -37
Rocky Mountain Power
1 other?O 2 A.No.The two models are simply different,and
3 both are useful in establishing a range of benefits from
4 the Combined Projects through the 20-year forecast
5 period.Importantly,the PVRR(d)results from both models
6 show customer benefits across all price-policy scenarios
7 with consistent trends in the difference in PVRR(d)
8 results between price-policy scenarios.The consistency
9 in the trend of forecasted benefits between the two
10 models,each having its own strengths,shows that the
11 benefits from the Combined
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
218 Link,Di -37a
Rocky Mountain Power
1 Projects are robust across a range of price-policy
2 assumptions and when analyzed using different modeling
3 tools.
4 Q.How do the risk-adjusted PVRR(d)results
5 compare to the stochastic-mean PVRR(d)results?
6 A.The risk-adjusted PVRR(d)results consistently
7 show a slight increase in the benefits of the Combined
8 Projects when compared to the stochastic-mean PVRR(d)
9 results.This indicates that the Combined Projects reduce
10 the risk of high-cost,low-probability outcomes that can
11 occur due to volatility in stochastic variables like
12 load,wholesale-market prices,hydro generation,and
13 thermal-unit outages.
14 ANNUAL REVENUE REQUIREMENT PRICE-POLICY RESULTS
15 Q.Please summarize the PVRR(d)results calculated
16 from the change in annual revenue requirement through
17 2050.
18 A.Table 3 summarizes the PVRR(d)results for each
19 price-policy scenario calculated off of the change in
20 annual nominal revenue requirement through 2050.The
21 annual data over the period 2017 through 2050 that was
22 used to calculate the PVRR(d)results shown in the table
23 are provided as Exhibit No.25.
24 /
25 /
219 Link,Di -38
Rocky Mountain Power
2 Table 3.Nominal Revenue RequirementPVRR(d)
(Benefit)/Cost of the Combined Projects ($million)
Price-Policy Scenario Annual Revenue RequirementPVRR(d)
Low Gas,Zero CO2 $174
4 Low Gas,Medium CO2 $93
Low Gas,HighCO2 ($194)
5 Medium Gas,Zero CO2 ($53)
Medium Gas,Medium CO2 ($137)
6 Medium Gas,High CO2 ($317)
High Gas,Zero CO2 ($341)
7 High Gas,Medium CO2 ($351)
High Gas,HighCO2 ($595)
8
9
10
11
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
220 Link,Di -38a
Rocky Mountain Power
1 When calculated through 2050,which covers the
2 30-year life of the Wind Projects,the Combined Projects
3 reduce customer costs in seven out of nine price-policy
4 scenarios.The only price-policy scenarios without net
5 customer benefits are those assuming the lowest
6 natural-gas prices when paired with either medium or
7 zero-CO2 price assumptions.The PVRR(d)results show
8 customer benefits under the price-policy scenario with
9 low natural-gas prices and high-CO2 prices,in all three
10 of the medium-natural-gas price scenarios,and in all
11 three of the high-natural-gas price scenarios.Under the
12 central price-policy scenario,assuming medium-natural-
13 gas prices and medium-CO2 prices,the PVRR(d)benefit is
14 $137 million.
15 Consistent with the PVRR(d)results calculated
16 from the SO model and PaR through 2036,the PVRR(d)
17 results show that the benefits of the Combined Projects
18 increase with natural-gas prices and CO2 prices,which
19 increase NPC and other system variable cost benefits.
20 Q.What causes the decrease in PVRR(d)benefits
21 when calculated off of nominal revenue requirement
22 through 2050 relative to the PVRR(d)results calculated
23 from the SO model and PaR results through 2036?
24 A.The PVRR(d)calculated from estimated annual
25 revenue requirement through 2050 reflects reduced
221 Link,Di -39
Rocky Mountain Power
1 incremental wind energy output beginning in 2042 after
2 the QF Projects'PPAs end.Confidential Figure 3 shows
3 the incremental change in wind energy output from the
4 Wind Projects and the QF Projects.Incremental energy
5 output associated with the Combined Projects is steady at
6 approximately (redacted)GWh over the 2022-through-2041
7 period.Beyond 2041,energy output is approximately
8 (redacted)GWh-(redacted).This
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
222 Link,Di -39aRockyMountainPower
1 reduction in incremental wind energy output reduces NPC
2 benefits and other system variable costs benefits over
3 the last nine years of the PVRR(d)calculated off the
4 change in nominal revenue requirement estimates through
5 2050.Consequently,the PVRR(d)calculated off the change
6 in nominal revenue requirement through 2050 does not
7 capture likely benefits associated with a potential
8 extension of the QF Projects'PPAs or incremental
9 procurement of additional Wyoming wind resources after
10 the term of these PPAs end.
11 Confidential Figure 3 .Change Incremental Wind EnergyOutputfromtheWindProjectsandQFProjects(GNh)
12
13
14
15
16
17
18
19
20
21
22
23
24 Q.Is there incremental customer upside to the
25 PVRR(d)results calculated from the change in estimated
223 Link,Di -40
Rocky Mountain Power
1 annual revenue requirement through 2050?
2 A.Yes.As in the case with the PVRR(d)results
3 calculated from the SO model and PaR results through
4 2036,the PVRR(d)results presented in Table 3 do not
5 reflect the potential value of RECs produced by the Wind
6 Projects.Customer benefits for all price-policy
7 scenarios would improve by approximately $34 million for
8 every dollar assigned to the incremental RECs that will
9 be generated from the Wind Projects through 2050.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
224 Link,Di -40a
Rocky Mountain Power
1 Q.Please describe the change in annual nominalO2revenuerequirementfromtheCombinedProjects.
3 A.Figure 4 shows the estimated change in annual
4 nominal-revenue requirement due to the Combined Projects
5 for the medium-natural-gas and medium-CO2-price-policy
6 scenario on a total-system basis.The annual revenue
7 requirement shown in the figure reflects all costs for
8 the Combined Projects,including capital revenue
9 requirement (i.e.,depreciation,return,income taxes,
10 and property taxes)net of transmission revenue credits,
11 operations and maintenance expenses,the Wyoming
12 wind-production tax,incremental wind integration costs,.
13 and PTCs.The project costs are netted against system
14 impacts of the Combined Projects,reflecting the change
15 in NPC,emissions,non-NPC variable costs,and system
16 Figure 4.Total-System Change in Annual Revenue Requirement
17 Due to the Combined Projects ($million)
560
18 $40 -
19
50
20 =.:($20)-----
2 1 ()---
($60)
22 (sso)
23 0 00)
($120)
oooooooooooooooooooooooooooooooooo
25
225 Link,Di -41
Rocky Mountain Power
1 fixed costs that are affected by,but not directly
2 associated with,the Combined Projects.
3 In the initial year the Combined Projects come
4 online,net system benefits offset partial-year capital
5 revenue requirement.In 2021,the first full year the
6 Combined Projects are in service,the change in
7 total-system nominal revenue requirement
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
226 Link,Di -41a
Rocky Mountain Power
1 increases by $51 million.This figure rapidly declinesO2andcrossesoverfromanetincreaseinnominalrevenue
3 requirement to a decrease in nominal revenue requirement
4 beginning 2024-just four years after the first full year
5 of operation.The net revenue requirement benefits
6 persist and grow through 2030 as PTC benefits increase
7 with inflation and the new equipment continues to
8 depreciate.On a total-system basis,the change in annual
9 revenue requirement is down by $109 million in 2030-the
10 last year the Wind Projects produce PTCs.After the PTCs
11 expire,annual revenue requirement increases.However,as
12 the assets continue to depreciate,the Combined Projects
13 once again begin producing annual revenue requirement
14 savings beginning 2036.These annual benefits persist
15 through 2050.
16 SENSITIVITY STUDY RESULTS
17 Q.Please summarize the results of the sensitivity
18 that assumes the Wind Projects have a 40-year-depreciable
19 life.
20 A.Table 4 summarizes the PVRR(d)results for the
21 sensitivity assuming a 40-year life for the Wind
22 Projects.To assess the relative impact of the 40-year
23 life,the PVRR(d)results were calculated through 2036
24 based on SO model and PaR results and are presented
25 alongside the benchmark study in which the Combined
227 Link,Di -42RockyMountainPower
1 Projects were evaluated assuming a 30-year life for theO2WindProjects.Medium-natural-gas and medium-CO2
3 price-policy assumptions were applied to this
4 sensitivity.
5 Table 4 .40-Year-Life Sensitivity
(Benefit)/Cost of the Combined Projects ($million)
6
Model Sensitivity Benchmark Change in
7 PVRR (d)PVRR (d)PVRR (d)
8 SO Model ($106)($85)($21)
9 PaR Stochastic-Mean ($132)($111)($21)
10 PaR Risk-Adjusted ($145)($124)($21)
11
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
228 Link,Di -42a
Rocky Mountain Power
1 If the Wind Projects are depreciated over aO240-year life,reduced book depreciation would drive lower
3 annual revenue requirement.In this sensitivity,PVRR(d)
4 benefits increase by approximately $21 million relative
5 to the benchmark case assuming a 40-year life for the
6 Wind Projects.
7 Q.Please summarize the results of the sensitivity
8 that analyzes the Combined Projects with wind repowering.
9 A.Table 5 summarizes the PVRR(d)results for the
10 sensitivity assuming the Combined Projects are
11 implemented along with wind repowering of approximately
12 999 MW of existing wind capacity.To assess the relative
13 impact of wind repowering on the Combined Projects,the
14 PVRR(d)results were calculated through 2036 based on SO
15 model and PaR results and are presented alongside the
16 benchmark study in which the Combined Projects were
17 evaluated without repowering.Medium-natural-gas and
18 medium-CO2 price-policy assumptions were applied to this
19 sensitivity.
20 /
21 /
22 /
23 /
24 /
25 /
229 Link,Di -43
Rocky Mountain Power
1 Table 5.The Combined Projects with Wind Repowering
Sensitivity
2 (Benefit)/Cost ($million)
3 Model Sensitivity Benchmark Change in
PVRR (d)PVRR (d)PVRR (d)
4
SO Model ($114)($85)($29)
5
PaR Stochastic-Mean ($104)($111)$8
6
PaR Risk-Adjusted ($116)($124)$8
7
8 When the Combined Projects are analyzed with
9 the wind repowering project,PVRR(d)benefits increase by
10 $29 million when assessed with the SO model.PaR shows a
11 slight $8 million increase to the PVRR(d).
12 Q.Do the PaR results for this sensitivity
13 indicate that the wind repowering project lowers customer
14 benefits if implemented in parallel with the Combined
15 Projects?
16 A.No.The sensitivity does not capture any of the
17 incremental benefits from the wind repowering project
18 that will occur just beyond the 2036 period,which is the
19 last year
20 /
21
22 /
23
24 /
25
230 Link,Di -43a
Rocky Mountain Power
1 simulated in the SO model and PaR.Consequently,the
2 PVRR(d)results from the SO model and PaR do not capture
3 the significant increase in the benefits from repowering
4 that is associated with increased incremental energy
5 output that will occur beyond 2036.
6 The change in wind energy output between cases
7 with and without repowering experiences a step change in
8 the 2036-through-2040 time frame,when the wind
9 facilities within the repowering project scope that were
10 originally placed in-service during the 2006-through-2010
11 time frame would otherwise have hit the end of their
12 depreciable life.Before the 2036-through-2040 time
13 frame,the period captured in the PVRR(d)results
14 summarized in Table 5,the change in wind energy output
15 from repowering reflects the incremental energy
16 production that results from installing modern equipment
17 on repowered wind assets.Beyond the 2036-through-2040
18 time frame,a period that is not captured in the PVRR(d)
19 results reported in Table 5,the change in wind energy
20 output between a case with and without repowering
21 reflects the full energy output from the repowered wind
22 facilities that would otherwise be retired.
23 Figure 5 shows the incremental change in wind
24 energy output resulting from the repowering project.
25 Incremental energy output associated with wind repowering
231 Link,Di -44
Rocky Mountain Power
1 progressively increases over the 2036-through-2040O2period,as wind facilities originally placed in service
3 in the 2006-through-2010 time frame would have otherwise
4 hit the end of their lives.Before 2036,and once all of
5 the wind resources within the project scope are
6 repowered,the average annual incremental increase in
7 wind energy output is approximately 551 GWh.Beyond 2040,
8 and before the new equipment hits the end of its
9 depreciable life,the average annual incremental increase
10 in wind energy output is
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
232 Link,Di -44a
Rocky Mountain Power
1 approximately 3,283 GWh.The value of this incremental
2 wind-energy output associated with repowering adds
3 substantial incremental benefits not reflected in the
4 PVRR (d)results for this sensitivity that would more than
5 offset the modest $8 million PVRR(d)incremental cost
6 based on PaR results through 2036.
7
Figure 5.Change in Incremental Wind Energy Output
8 Due to Repowering (GWh)
9 3,500 -
10 3,000
11 2,500
2,000 ------
12
1,500
13
1,000
IIIlillllmilill
16 (500)
18
19
2 0 CONCLUSION
21 Q.Please summarize the conclusions of your
22 testimony.
23 A.PacifiCorp's analysis supports proceeding with
24 its planned investments in the Wind Projects and
O 25 Transmission Projects.The Wind .Projects,which are
233 Link,Di -45RockyMountainPower
1 enabled by the Transmission Projects will:(1)qualifyO2fortenyearsoffederalPTCs;(2)produce zero-fuel-cost
3 energy that will lower NPC;(3)generate RECs,which can
4 be sold in the market to create additional revenues that
5 would lower net customer costs;and (4)help to
6 decarbonize PacifiCorp's resource portfolio,which
7 mitigates long-term risk
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
234 Link,Di -45a
Rocky Mountain Power
1 associated with potential future state and federalO2policiestargetingCO2emissionsreductionsfrom the
3 electric sector.
4 The Transmission Projects will:(1)relieve
5 congestion on the current transmission system in eastern
6 Wyoming;(2)enable the additional wind resource
7 interconnections;(3)provide critical voltage support to
8 the Wyoming transmission network;(4)improve overall
9 reliability of the transmission system and enhance
10 PacifiCorp's ability to comply with mandated reliability
11 and performance standards;(5)reduce line losses;and
12 (6),create an opportunity for further increases to the
13 transfer capability across the Aeolus-to-Bridger/
14 Anticline Line with the construction of additional
15 segments of the Energy Gateway project.
16 The economic analysis of the Combined Projects
17 demonstrates that net benefits more than outweigh net
18 project costs.
19 Q.What do you recommend?
20 A.As supported by PacifiCorp's economic analysis,
21 I recommend that the Commission determine that
22 PacifiCorp's decision to invest in the Wind Projects and
23 the Transmission Projects is in the public interest and
24 approve the Application as filed,including the proposed
25 ratemaking treatment for the new costs and benefits of
235 Link,Di -46
Rocky Mountain Power
1 the Combined Projects.
2 Q.Does this conclude your direct testimony?
3 A.Yes.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
236 Link,Di -46a
Rocky Mountain Power
1 Q.Are you the same Rick T.Link who previously
2 provided direct testimony in this case on behalf of Rocky
3 Mountain Power ("Company"),a division of PacifiCorp?
4 A.Yes.
5 PURPOSE AND SUMIRRY OF REBUTTAL TESTIMONY
6 Q.What is the purpose of your rebuttal testimony?
7 A.My rebuttal testimony supports the Company's
8 request for certificates of public convenience and
9 necessity ("CPCNs")and binding ratemaking treatment for
10 the Company's proposal to construct or procure new wind
11 resources ("Wind Projects")and construct the Aeolus-to-
12 Bridger/Anticline line and 230 kV Network Upgrades
13 ("Transmission Projects")(collectively,the "Combined
14 Projects").I summarize the status of the Company's 2017R
15 Request for Proposals ("RFP")for the Wind Projects,the
16 results of which will be included in my supplemental
17 testimony on January 16,2018,and outline the
18 information and updated economic analysis that the
19 Company will include in that filing.I also rebut
20 challenges on resource need and the Company's economic
21 analysis raised by Monsanto Company ("Monsanto"),
22 PacifiCorp Idaho Industrial Customers ("PIIC"),and the
23 Idaho Irrigation Pumpers Association ("IIPA"),and
24 respond to testimony provided by Staff of the Idaho
25 Public Utilities Commission ("Staff").
237 Link,Di-Reb -1
Rocky Mountain Power
1 Q.Please summarize your rebuttal testimony.
2 A.My rebuttal testimony demonstrates that:
3 o PacifiCorp has near-term and long-term
4 resource needs that will be partially met
5 with the proposed Wind Projects.
6 o The heavily discounted cost of the Wind
7 Projects are lower cost than all
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
238 Link,Di-Reb -la
Rocky Mountain Power
1 other near-term and long-term resource
2 alternatives.
3 o Contrary to certain parties'claims,there
4 is nothing novel or unique about the
5 Combined Projects that justifies
6 unprecedented cost-recovery treatment to
7 assign all risk to the Company.
8 o The Company's long-standing methodology to
9 develop its official forward price curve
10 ("OFPC")produces the best representation
11 of future market prices and is
12 appropriately used for the central
13 forecast in the Company's economic
14 analysis;the alternative price-policy
15 scenarios provide a reasonable foundation
16 for judging risk.
17 o The Company's economic analysis
18 appropriately addresses project risks and
19 supports including the Combined Projects
20 as an important element of PacifiCorp's
21 least-cost,least-risk resource plan.
22 STATUS OF 2017R RFP
23 Q.When did the Company issue the 2017R RFP?
24 A.The Company issued the 2017R RFP on September
25 27,2017.The 2017R RFP was approved by the Public
239 Link,Di-Reb -2
Rocky Mountain Power
1 Service Commission of Utah ("Utah Commission")onO2September22,2017,and the Public Utility Commission of
3 Oregon ("Oregon Commission")on September 27,2017.
4 Q.Has the schedule for completion of the 2017R
5 RFP changed?
6 A.No.
7 Q.Was the scope of the 2017R RFP modified before
8 it was issued to include non-Wyoming wind projects?
9 A.Yes.The Company's original proposal limited
10 the RFP to wind resources capable of
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
240 Link,Di-Reb -2a
Rocky Mountain Power
1 interconnecting to or delivering on a firm basis to the
2 Company's transmission system in Wyoming.In response to
3 issues raised in the RFP approval process,and consistent
4 with the recommendations of the Utah independent
5 evaluator ("IE"),the Company expanded the 2017R RFP to
6 allow bids from non-Wyoming wind projects capable of
7 interconnecting to or delivering on a firm basis to
8 anywhere on PacifiCorp's transmission system.
9 Q.In response to the Utah Commission's approval
10 order,did the Company decide to issue a solar RFP to run
11 concurrently with the 2017R RFP?
12 A.Yes.In its order approving the 2017R RFP,the
13 Utah Commission suggested,but did not require,a
14 modification to expand the 2017R RFP to solicit solar
15 resource bids.To maintain the 2017R RFP schedule while
16 addressing the Utah Commission's suggestion,the Company
17 issued a separate solicitation for solar resources,the
18 2017S RFP,on November 15,2017.The 2017S RFP seeks bids
19 for solar resources up to 300 megawatt ("MW")per
20 individual project that can deliver energy and capacity
21 to the Company's transmission system.
22 Similar to the 2017R RFP,the Company retained
23 an IE to oversee the solar RFP process.The 2017S RFP
24 schedule allows the Company to:(1)evaluate how solar
25 resource bids might impact the economic analysis of bids
241 Link,Di-Reb -3
Rocky Mountain Power
1 selected to the final shortlist in the 2017R RFP without
2 delaying the schedule for the 2017R RFP;and (2)explore
3 whether new solar resource opportunities might provide
4 all-in economic benefits for customers.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
242 Link,Di-Reb -3a
Rocky Mountain Power
1 Q.Does the Company anticipate that non-Wyoming
2 wind and solar resources will replace the Wyoming wind
3 targeted by the 2017R RFP?
4 A.No.The Company anticipates that the Wyoming
5 wind resources targeted by the 2017R RFP will deliver
6 customer benefits regardless of whether proposals for
7 non-Wyoming wind and solar resources can deliver
8 incremental value for customers.The Company will
9 consider procuring renewable resources that deliver
10 customer benefits,including Wyoming wind resources and
11 non-Wyoming wind resources targeted by the 2017R RFP and
12 solar resources targeted by the 2017S RFP.
13 Q.Has the Company received initial bids in the
14 2017R RFP?
15 A.Yes.The Company received initial bids for
16 Wyoming wind projects on October 17,2017,and initial
17 bids for non-Wyoming wind projects on October 24,2017.
18 The 2017R RFP was well received by the market,as
19 indicated by the fact the Company received Wyoming wind
20 proposals from nine bidders offering 49 bid alternatives
21 for 13 wind projects.The Company also received
22 non-Wyoming wind proposals from five bidders offering 15
23 bid alternatives for six wind projects.In aggregate,
24 5,219 MW of new wind resource capacity was bid into the
25 2017R RFP (4,624 MW of Wyoming wind and 595 MW of
243 Link,Di-Reb -4
Rocky Mountain Power
1 non-Wyoming wind).
2 Q.Is the review and evaluation of these bids now
3 underway?
4 A.Yes.On November 12,2017,the Company
5 completed its initial shortlist evaluation and scoring
6 and began the third-party evaluation of capacity factors.
7 The Utah and Oregon IEs completed their review of the
8 initial shortlist November 17,2017.Once the IEs
9 completed their review of the initial shortlist,the
10 Company notified bidders whether their proposed projects
11 were selected to the initial shortlist and provided an
12 opportunity
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
244 Link,Di-Reb -4a
Rocky Mountain Power
1 for bidders selected to the initial shortlist to update
2 pricing.On November 22,2017,the Company received
3 best-and-final pricing for bids selected to the initial
4 shortlist.The Company is now conducting portfolio
5 analysis of each bid to determine which bids it will
6 include on the final shortlist in January 2018.
7 Q.Do you have any general observations about the
8 2017R RFP?
9 A.At this time,I can state only that the
10 Company's preliminary analysis indicates that the winning
11 bids from the 2017R RFP may be lower cost than estimated
12 in the initial filing in this case.To protect the
13 integrity of the bidding process while the review and
14 scoring is ongoing,however,I cannot disclose any
15 details or studies related to specific bids or the
16 on-going portfolio analysis until the shortlist is
17 finalized in January 2018.
18 Q.What is the status of the 2017S RFP?
19 A.The Company received initial bids for new solar
20 resources on December 11,2017.In coordination with the
21 IE,PacifiCorp is currently reviewing the eligibility of
22 proposals and has initiated the initial shortlist price
23 and non-price scoring process.As was the case with the
24 2017R RFP,the market response to the 2017S RFP was
25 robust.Considering that the bid eligibility review
245 Link,Di-Reb -5RockyMountainPower
1 process is ongoing,on a preliminary basis,the Company
2 received solar resource proposals from 31 bidders
3 offering 109 bid alternatives for 46 solar projects.In
4 aggregate,6,496 MW of new solar resource capacity was
5 bid into the 2017S RFP.
6 The Company is on track to be able to evaluate
7 how solar resource bids received through the 2017S RFP
8 might influence the economic analysis of bids submitted
9 into the 2017R RFP,which will be considered when
10 selecting the 2017R RFP final shortlist.
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
246 Link,Di-Reb -5a
Rocky Mountain Power
1 Q.What specific information and analysis on the
2 2017R RFP will the Company provide in its supplemental
3 filing on January 16,2018?
4 A.The Company's supplemental testimony will
5 describe the winning bids from the 2017R RFP,and provide
6 updated project cost-and-performance estimates specific
7 to winning bids.The Company will provide the analysis
8 supporting its selection of the winning bids,including
9 the third-party capacity factor review report,and an
10 assessment of how solar bids received in the 2017S RFP
11 might affect the economic analysis of winning bids from
12 the 2017R RFP.
13 Using the updated project cost-and-performance
14 information from the 2017R RFP,the Company's
15 supplemental filing will include an updated economic
16 analysis of the Combined Projects.This analysis will
17 reflect an updated load forecast and updated price-policy
18 scenarios that reflect the most current forward price
19 curves.If Congress passes tax-reform legislation in the
20 coming weeks,the updated economic analysis will also
21 reflect updated income tax assumptions.Bidders with
22 proposals selected to the 2017R RFP initial shortlist
23 have been notified that if Congress passes tax-reform
24 legislation,those bidders will be asked to update
25 pricing to account for changes in the final tax bill.If
247 Link,Di-Reb -6
Rocky Mountain Power
1 Congress has not yet passed tax-reform legislation,theO2updatedeconomicanalysiswillincludesensitivities
3 consistent with income tax proposals being considered by
4 Congress.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
248 Link,Di-Reb -6a
Rocky Mountain Power
1 Q.Based on the fact that the Company will soon
2 confirm winning bids in the 2017R RFP and refresh its
3 economic analysis,is the Company proposing to address
4 certain economic arguments raised by intervenors in more
5 detail in its supplemental testimony?
6 A.Yes.The Company believes that its updated
7 economic analysis will address a number of the specific
8 issues raised around the size and certainty of the
9 economic benefits of the Combined Projects,including the
10 impact of changes to federal tax law,as discussed above.
11 RESOURCE NEED
12 Q.Monsanto,PIIC,and IIPA argue that the
13 Combined Projects are discretionary projects that are not
14 tied to a specific resource need.(Phillips Direct,page
15 6,lines 6-9;Mullins Direct,page 9,lines 18-20;Yankel
16 Direct,page 4,lines 22-23.)Do you agree?
17 A.No.The Combined Projects meet both a near-term
18 and long-term resource needs identified in the Company's
19 2017 Integrated Resource Plan ("IRP").The Combined
20 Projects leverage federal production tax credits ("PTCs")
21 to provide least-cost resources that meet this need,and
22 do so with substantial savings to customers.
23 Q.How does the Company develop its forecast of
24 resource need?
25 A.Resource need is the product of a
249 Link,Di-Reb -7
Rocky Mountain Power
1 load-and-resource balance,which is reported in the IRP.
2 Figure 1 summarizes the elements of the load and resource
3 balance that are used to establish resource need,and
4 once identified,how that need can be met.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
250 Link,Di-Reb -7a
Rocky Mountain Power
(Il 2
3
Figure 1.Elements of the Load and Resource Balance
4 obugationExistingResources&.(Net Load and Planning
5 Contracts Margin)
6
7
Load &Resource Balance
(Need)
9
Wind Solar DSM
12
Gas CCCT Gas Peaker Storage
"13
Geothermal Nuclear14
15
16 There are two basic elements to the load and
17 resource balance:(1)existing resources and committed
18 contracts;and (2)obligations.Existing resources and
19 committed contracts account for any planned or assumed
20 resource retirements and contract terminations over time.
21 Obligations include load,net of customer-sited
22 generation and interruptible contracts,over time.
23 Obligations also include a planning margin,which
24 represents an incremental planning requirement,applied
'25 as an increase to the projected obligation,to ensure6
251 Link,Di-Reb -8RockyMountainPower
1 sufficient capacity on the system to manage uncertain
2 events (i.e.,weather and outages)and known requirements
3 (i.e.,operating reserves).In recent IRPs,including the
4 2017 IRP,the Company assumes a 13 percent planning
5 margin.
6 The load-and-resource balance reflects the
7 difference between these two basic elements.When
8 existing resources and contracts exceed obligations,the
9 Company has
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
252 Link,Di-Reb -8a
Rocky Mountain Power
1 sufficient resources to reliably meet customer needs.
2 When existing resources and contracts are less than its
3 obligations,the Company has a resource need.This
4 balance between existing resources,including committed
5 contracts,and obligations can change over time.When the
6 Company faces a resource need,the IRP is used to
7 evaluate a wide range of supply-side resources (such as
8 renewable resources,gas-fired resources,uncommitted
9 front-office transactions or "FOTs")and demand-side
10 management resources ("DSM")that can be used to meet
11 that need over time.Different types of resource
12 portfolios that can be used to meet a resource need are
13 evaluated in the IRP to determine which portfolio is
14 least cost,accounting for risk.
15 Q.Does the load-and-resource balance presented in
16 the 2017 IRP show a near-term resource need?
17 A.Yes.Accounting for assumed retirement of
18 resources,contract terminations,and incremental DSM
19 savings from the preferred portfolio,the 2017 IRP shows
20 a near-term resource need of 527 MW in 2017 rising to
21 1,023 MW in 2021,the first full year the Combined
22 Projects will be placed in service.1 The resource need
23 grows over time with load growth,existing resource
24 retirements,and committed contracts terminations.
25 Q.Do the Combined Projects fully satisfy the
253 Link,Di-Reb -9
Rocky Mountain Power
1 near-term resource need identified in the 2017 IRP
2 load-and-resource balance?
3 A.No.In the 2017 IRP,the Company updated its
4 capacity contribution values for wind and solar
5 resources.Based on these values,15.8 percent of Wyoming
6 wind resource capacity can be relied upon at times when
7 the system is most likely to experience conditions where
8 load exceeds available resources.Consequently,the 1,100
9 MW of
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25 1 Table 5.15,PacifiCorp's 2017 IRP,Volume I.
254 Link,Di-Reb -9a
Rocky Mountain Power
1 new Wyoming wind in the 2017 IRP preferred portfolio
2 meets approximately 174 MW (17 percent)of the 1,023 MW
3 resource need in 2021.The remaining resource need in
4 2021 (83 percent)is met with uncommitted FOTs.
5 Q.If the Combined Projects were not included in
6 the resource portfolio,how would the 2021 resource need
7 be met?
8 A.Resource portfolios that do not include the
9 Combined Projects include more uncommitted FOTs.The
10 resource portfolios with more uncommitted FOTs are higher
11 cost than resource portfolios that include the Combined
12 Projects under a wide range of price-policy scenarios.
13 Simply stated,resource portfolios with the Combined
14 Projects displace FOTs in the near-term because the
15 Combined Projects,accounting for PTC savings,are lower
16 cost and lower risk than FOT resource alternatives.
17 Notably,this is the exact process described by
18 Monsanto and PIIC.Mr.Phillips testifies that,"[i]f
19 there is a need for a new resource,the economics of
20 alternatives can be compared to determine the best way to
21 meet the need."(Phillips Direct,page 8,lines 12-14;
22 Mullins Direct,page 10,lines 10-17.)Here,the 2017 IRP
23 identified a resource need and determined the least-cost,
24 least-risk combination of resources to meet that need.
25 That combination of resources in the preferred portfolio
255 Link,Di-Reb -10
Rocky Mountain Power
1 includes the Combined Projects.O 2 Q.Has the Company previously acquired renewable
3 resources that displace FOTs?
4 A.Yes.This is not the first time the Company has
5 implemented a least-cost,least-risk plan to procure
6 renewable resources that displace uncommitted FOTs.In
7 fact,all 1,698 MW of PacifiCorp's existing contracted
8 and owned renewable resources included in rates today,
9 not including qualifying facilities,were acquired and
10 approved by the
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
256 Link,Di-Reb -10a
Rocky Mountain Power
1 Commission because they were the least-cost,least-riskO2resources,displaced FOTs,and were acquired well before
3 any thermal capacity or state renewable portfolio
4 standard need.
5 Q.PIIC claims that FOTs do not represent
6 fulfillment of a resource need (Mullins Direct,page 11,
7 lines 15-17.)Is this true?
8 A.No.PIIC claims that the 2017 IRP shows
9 currently available resources and FOTs will meet the
10 Company's resource needs through 2026 and therefore the
11 Combined Projects "cannot be reasonably characterized as
12 addressing a resource need[.]"(Mullins Direct,page 9,
13 line 20-page 10,line 7.)This claim improperly assumes
14 that the maximum level of FOTs assumed in the IRP are
15 committed resources and that other resource alternatives,
16 such as the Combined Projects,cannot be used to meet the
17 projected resource need at a lower cost.As noted above,
18 in the IRP,FOTs represent uncommitted resources,meaning
19 they can be displaced if lower-cost alternatives are
20 available.As the 2017 IRP shows,the energy and capacity
21 provided by the Wind Projects are lower cost than other
22 resource alternatives,including FOTs.
23 Q.PIIC further claims that FOTs do not represent
24 a resource need because "[1]ittle to no incremental
25 ratepayer supplied capital is required [.]"(Mullins
257 Link,Di-Reb -11
Rocky Mountain Power
1 Direct,page 12,line 1.)Has the Idaho CommissionO2previouslyrecognizedthatthedisplacementof
3 higher-cost market transactions can meet a customer
4 resource need?
5 A.Yes.I understand that in 2001,Idaho Power
6 requested a CPCN to construct a natural-gas-fired
7 combustion-turbine plant.In the Matter of the
8 Application of Idaho Power Co.for a Certificate of
9 Public Convenience and Necessity for the Ratebasing of
10 the Mountain Home Generating Station,Case No.
11 IPC-E-01-12,Order No.28773 (July 10,
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
258 Link,Di-Reb -11a
Rocky Mountain Power
1 2001).Although the new plant was not identified in theO2near-term action plan of its most recent IRP,Idaho Power
3 argued that it would "provide[]a cost-effective
4 alternative to the planned wholesale market purchases"
5 that were included in the action plan.Id.at 2.The
6 Commission approved the CPCN.2 Although the
7 circumstances of that case are different (because it
8 arose during the summer of 2001 when market prices were
9 very high),nothing in the order limits the principle
10 that a utility can show need by displacing higher-cost
11 market transactions with a utility-owned resource.
12 Q.What factors influence the type of resources
13 used to meet the Company's resource need over the long
14 term?
15 A.Uncommitted FOTs are traditionally one of the
16 lowest cost resources that can be used to meet a resource
17 need.This is because the cost of these FOT resources
18 reflect only the marginal,variable operating cost of
19 existing resources selling excess firm energy to market
20 participants on a forward basis.While the availability
21 of PTCs changes this dynamic for the Combined Projects,
22 supporting their inclusion in the Company's resource
23 portfolio by the end of 2020,uncommitted FOTs are still
24 generally lower cost than other resource alternatives.
25 Consequently,as the resource need grows over time,the
259 Link,Di-Reb -12
Rocky Mountain Power
1 level of uncommitted FOTs in the preferred portfolioO2generallygrows,approaching maximum limits.3 The timing
3 in which the resource need exceeds maximum uncommitted
4 FOT limits,after accounting for other lower-cost
5 alternatives such as the Combined Projects,is a strong
6 indicator of when the Company will require incremental
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21 2 The Commission did not approve a commitment estimate and therefore
did not provide Idaho Power a dollar amount of rate base assurance
22 due to the lack of a sufficient record that the particular plant was
the least-cost alternative.
23 3 These maximum limits are based on the Company's active
participation in the wholesale power markets,physical delivery
24 constraints,market liquidity and market depth,and with
25
consideration of regional resource supply.
260 Link,Di-Reb -12a
Rocky Mountain Power
1 generating resources to meet its long-term resource need.
2 Q.How do the Combined Projects meet a long-term
3 resource need?
4 A.The Company's 2017 IRP forecasts that maximum
5 levels of uncommitted FOTs begin to exceed resource needs
6 by just under 400 MW beginning in 2028.The 1,100 MW of
7 Wyoming wind resources included in the 2017 IRP preferred
8 portfolio in 2021 contributes 174 MW of system capacity.
9 Consequently,the 2017 IRP analysis shows that the
10 Combined Projects will meet approximately 44 percent of
11 the resource need incremental to the resource need that
12 can be met with FOTs.Therefore,beginning in the 2028
13 timeframe,the Combined Projects begin deferring the need
14 for other,high-cost resource alternatives.In this
15 sense,the Combined Projects can be viewed as displacing
16 higher-cost uncommitted FOT resources in the near-term
17 and deferring other higher-cost resource alternatives
18 over the long-term.
19 Q.While the Combined Projects will be used to
20 meet both near-term and long-term resource needs,are you
21 aware of examples where the Commission deemed early
22 acquisition prudent?
23 A.Yes.In 1993,I understand that the Commission
24 approved an upgrade at an Idaho Power hydro facility that
25 increased its capacity from 9 MW to 43.5 MW.In the
261 Link,Di-Reb -13
Rocky Mountain Power
1 Matter of the Application of Idaho Power Company for
2 Authority to Rate Base the Investment Required for Adding
3 Capacity to the Twin Falls Hydroelectric Facility,Case
4 No.IPC-E-91-4,Order No.25021 (June 1,1993).At the
5 time,an intervenor argued that Idaho Power had no need
6 for additional capacity until 2006,and the Commission
7 should therefore deny the application.In response,Idaho
8 Power argued that the upgrade was cost-effective even if
9 placed in service ahead of need based on the incremental
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
262 Link,Di-Reb -13a
Rocky Mountain Power
1 generation alone,particularly because the upgrade was aO250-year resource.Idaho Power also stressed that it
3 should acquire the least-cost resources regardless of
4 ownership.The Commission agreed with Idaho Power and
5 found that the resource was cost-effective.
6 Q.Monsanto points to the fact the Company
7 recently revised its load forecast down as further
8 evidence that the resources are not needed.(Phillips
9 Direct,page 7,lines 19-20.)Does this downward revision
10 materially impact the need for the Combined Projects?
11 A.No.The Company's most recent load forecast
12 shows that the summer coincident peak demand in 2021 is
13 down by approximately 428 MW relative to the load
14 forecast used in the economic analysis summarized in my
15 direct testimony,which is the same load forecast used in
16 the 2017 IRP.Before updating the load forecast,the
17 projected resource need in 2021 is 1,023 MW.With the
18 updated load forecast,the 2021 resource need is reduced
19 by 428 MW to 595 MW.The capacity contribution of 1,100
20 MW of new Wyoming wind is 174 MW,which is just under 30
21 percent of the projected resource need in 2021 after
22 accounting for the Company's updated load forecast.
23 Q.Monsanto claims that the "Company's proposal is
24 based solely on projected future savings for customers."
25 (Phillips Direct,page 8,line 20-21.)Is this a fair
263 Link,Di-Reb -14
Rocky Mountain Power
1 characterization of the Combined Projects?O 2 A.No.Monsanto argues that the Combined Projects
3 represent purely an economic opportunity.But
4 PacifiCorp's analysis shows that acquiring the new wind
5 resources now,when they are PTC-eligible,will displace
6 higher cost resources in both the near term and long
7 term.The PTCs affect the timing and economics of the new
8 resource,not the need for the resource.The fact that
9 the Combined Projects are a time-limited
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
264 Link,Di-Reb -14a
Rocky Mountain Power
1 opportunity based on PTCs does not inherently indicate
2 that they are disconnected from a resource need.
3 Q.PIIC indicates that it was surprised when the
4 Company announced as part of its 2017 IRP process that
5 its preferred portfolio included the Combined Projects.
6 (Mullins Direct,page 5,lines 5-10.)How do you respond?
7 A.The Combined Projects were a logical
8 development as the 2017 IRP analysis evolved.In late
9 2016 and early 2017,PacifiCorp continued to study and
10 refine its resource portfolios,all of which contained
11 new Wyoming wind resources.In reviewing these resource
12 portfolios,it became clear that the amount of Wyoming
13 wind included in these resource portfolios was limited by
14 transmission constraints.The presence of the Wyoming
15 wind resources in these initial portfolios led PacifiCorp
16 to assess whether additional wind resources enabled by
17 advancing sub-segments of Energy Gateway West would
18 further lower system costs.Consequently,after the
19 January 2017 public input meeting,PacifiCorp
20 incorporated the Aeolus-to-Bridger/Anticline line as a
21 specific sensitivity case in its broader Energy Gateway
22 sensitivity analysis.In late February,PacifiCorp's
23 modeling of four Energy Gateway transmission
24 sensitivities indicated there were potential benefits to
25 including the Aeolus-to-Bridger/Anticline line in the
265 Link,Di-Reb -15
Rocky Mountain Power
1 portfolio.At the March 2017 public input meeting,
2 PacifiCorp presented this preliminary analysis to
3 stakeholders,along with next steps that communicated
4 PacifiCorp's intention to further refine key assumptions
5 for this sensitivity case.
6 While the pre-filing stakeholder review process
7 of the Combined Projects was necessarily limited by the
8 timing of PacifiCorp's analysis and 2017 IRP filing
9 deadlines,it was in customers'interest to consider
10 these resources and ultimately
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
266 Link,Di-Reb -15a
Rocky Mountain Power
1 include them in the 2017 IRP preferred portfolio.
2 PacifiCorp explicitly chose to share the results of its
3 analysis with stakeholders as it was being produced.
4 Given the time-sensitive nature of these resource
5 opportunities,delaying the IRP to allow additional
6 pre-filing review was not a viable option.Instead,
7 PacifiCorp expeditiously completed the necessary analysis
8 and shared it with IRP stakeholders in real time.
9 Q.Were there wind resources in other scenarios?
10 A.Yes.The 2017 IRP analyzed all alternatives
11 when identifying ways to meet customers'near-term and
12 long-term resource needs,including incremental DSM
13 savings,procurement of uncommitted FOTs,new supply-side
14 resources,including new renewable resources,and changes
15 in use of or upgrades to existing resources to develop
16 the preferred least-cost,least-risk portfolio of
17 resources.PacifiCorp's 2017 IRP shows a need for new
18 resources that can be partially met with new wind
19 generation by the end of 2020 across almost all modeled
20 portfolios.PacifiCorp examined alternatives for meeting
21 this near-term need,but transmission constraints limited
22 wind resource options.
23 Q.Are there risks associated with not pursuing
24 the Combined Projects?
25 A.Yes.If the Company does not pursue the
267 Link,Di-Reb -16
Rocky Mountain Power
1 Combined Projects,it will be forgoing the opportunityO2forcustomerstoacquireheavilydiscountedresources in
3 the near term,in exchange for greater reliance on
4 near-term market transactions and waiting until after the
5 expiration of PTCs to acquire zero-fuel-cost resources to
6 meet growing energy and capacity needs.Contrary to
7 parties'implication that there are no customer risks
8 associated with forgoing the opportunity to procure
9 PTC-eligible resources,there are risks associated with
10 greater reliance on higher-cost FOT resources over the
11 near term
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
268 Link,Di-Reb -16aRockyMountainPower
1 and greater reliance on other higher-cost resources over
2 the long term-and those risks will be borne by customers.
3 Although parties point out the risks of the
4 Combined Projects,they do not demonstrate that they are
5 higher risk than the next best alternative.In contrast,
6 the 2017 IRP and the economic analysis summarized in my
7 direct testimony clearly demonstrates that the Combined
8 Projects are least-cost,least-risk compared to all other
9 alternatives,including the status quo alternative,which
10 will result in increased reliance on higher-cost FOTs.
11 Q.Has Monsanto,PIIC,or IIPA provided meaningful
12 analysis demonstrating that the status quo is less risky
13 than pursing the Combined Projects?
14 A.No.In asserting,without analysis,that the
15 status quo yields superior outcomes,Monsanto,PIIC,and
16 IIPA discount the availability of a lower-cost,
17 lower-risk alternative.To the extent they assume
18 inaction is less risky than action,this assumption lacks
19 either logical or factual support.There is nothing about
20 inaction that makes it preferable to action when
21 objectively considering relative risk.For the Combined
22 Projects,the vast majority of modeling scenarios result
23 in customer benefits.Declining to pursue the Combined
24 Projects results in a likely opportunity cost-that is,a
25 likely customer loss.
269 Link,Di-Reb -17
Rocky Mountain Power
1 The parties'recommendation against theO2CombinedProjectsissubstantiallymorelikelyto achieve
3 a less favorable outcome for customers in the form of
4 increased costs and increased risk-a result inadequately
5 justified by the preference for inaction over action.The
6 Company seeks to develop the Combined Projects now
7 because the PTCs make this the least-cost,least-risk
8 option to serve current capacity and energy
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
270 Link,Di-Reb -17a
Rocky Mountain Power
1 needs.Inaction will forgo a valuable opportunity,and
2 delaying the acquisition of least-cost resources in favor
3 of higher cost alternatives is not in the best interest
4 of customers.
5 Q.Both Monsanto and PIIC also argue that the
6 Company has an incentive to invest in the Combined
7 Projects and suggest that this incentive is improperly
8 driving the investment decision.(Mullins Direct,page 7,
9 lines 6-8,and page 8,lines 1-4;Phillips Direct,page
10 10,lines 3-12.)How do you respond?
11 A.These claims ignore the resource need discussed
12 above.PIIC further supports this conclusion by citing
13 the Averch-Johnson thesis,which theorizes that
14 traditional rate-base and rate-of-return regulation
15 biases a regulated firm,as compared to an unregulated
16 one,toward more capital-intensive modes of production.
17 PIIC's reliance on the Averch-Johnson thesis is
18 misplaced,however,because there is considerable debate
19 about whether the Averch-Johnson effect is real and,even
20 if it is real,whether such an effect would be
21 undesirable.4 And even if the effect were both real and
22 undesirable,PIIC's concern assumes that PacifiCorp will
23 own the wind resources;this is not necessarily true.The
24 RFP process will determine whether the Company or a
25 third-party will own the proposed wind resources and who
271 Link,Di-Reb -18
Rocky Mountain Power
1 will fund the concomitant capital investment.
2 This argument also ignores that the Combined
3 Projects are more cost-effective
4 /
5
6 /
8 /
9
10
11
12
13
14
15
16
17
18 4 Charles F.Phillips,Jr.,The Regulation of Public Utilities 892-93
(1993);see also James C.Bonbright et al.,Principles of Public
19 Utility Rates 362 (2d ed.1988)("[T]o the extent [the Averch-Johnson
effect]exists,it could well be a more important influence for good
20 than for poor performance[.]")(quoting Alfred E.Kahn,Applications
of Economics to Utility Rate Structures,101 Public Utilities
21 Fortnightly 59 (Jan.19,1978));id.("To repeat:we find a paucity
of data documenting the Averch-Johnson effects and instead find
22 largely educated speculation.").A recent meta-analysis of
scholarship concerning the Averch-Johnson effect concluded that it
23 amounts to "an intellectual curiosity,"and suggested that further
efforts to discern an Averch-Johnson effect on regulated utilities be
24 "abandoned in favour of more productive enterprises."Stephen M.Law,
Assessing the Averch-Johnson-Wellisz Effect for Regulated Utilities,
25 6 INT'L J.OF ECON.&FIN.41,42,52 (2014).
272 Link,Di-Reb -18a
Rocky Mountain Power
1 than FOTs,even when including capital and run-rate
2 operating costs.A higher-cost resource should not be
3 selected merely to prevent an opportunity for
4 shareholders to earn a rate of return.
5 Q.Monsanto presents a series of proposed
6 conditions it recommends the Commission impose if it
7 approves the Combined Projects.(Phillips Direct,page 4,
8 lines 14-32,and page 5,lines 1-2.)Please describe the
9 proposed conditions.
10 A.Monsanto's proposed conditions would:(1)
11 disallow recovery of turbines that are not PTC-eligible;
12 (2)automatically disallow a portion of the estimated
13 capital costs through a cost-recovery cap set well below
14 the cost estimate;(3)cap future costs associated with
15 the Combined Projects;(4)impute an assumed capacity
16 factor and PTC value;(5)impute full PTC value even if
17 the Company cannot immediately monetize the value of the
18 PTC;and (6)disallow cost recovery if construction
19 stops,for whatever reason.
20 Q.Is there any basis for imposing such conditions
21 on the Combined Projects?
22 A.No.The purpose of the proposed conditions
23 appears to be the elimination of any customer risk
24 associated with the projects,based on the claim that the
25 projects are discretionary and not tied to an actual
273 Link,Di-Reb -19
Rocky Mountain Power
1 resource need.(Phillips Direct,page 34,lines 21-22.)
2 But there is nothing novel or unique about the Combined
3 Projects that require this unprecedented treatment.These
4 recommendations appear premised on the Company not
5 demonstrating a need for the Combined Projects,despite
6 the fact that Monsanto does not challenge the fact that
7 the Company has an energy and capacity need in 2028.At
8 the very least,the Combined Projects are an early
9 acquisition to meet a future resource need.Even in the
10 hypothetical scenario where there was a proposal to
11 acquire a resource early,Monsanto provides no support
12 for its position that customers
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
274 Link,Di-Reb -19a
Rocky Mountain Power
1 should bear no risk when a utility prudently acquires a
2 resource ahead of need.
3 Q.Do Monsanto's proposed conditions relate to
4 risks associated with early acquisitions?
5 A.No.Monsanto's proposal to eliminate all
6 customer risk is also unwarranted because the Combined
7 Projects do not present risks different than typical
8 utility investments.Even assuming the Combined Projects
9 are being acquired early,the only incremental risk
10 associated uniquely with the Combined Projects is a
11 timing risk.Monsanto never explains why this timing risk
12 outweighs the risk of forgoing PTC-eligible resources.
13 Again,PacifiCorp disagrees with the assertion that the
14 resources are being procured before they are needed
15 because they are displacing higher-cost FOTs in the
16 near-term while also meeting a long-term energy and
17 capacity need.But even if the Commission accepts
18 Monsanto's view,the Company's analysis shows that
19 benefits from the Combined Projects accrue to customers
20 in the near-term,well in advance of the alleged 2028
21 capacity deficiency.
22 ECONOMIC ANALYSIS
23 Q.Monsanto,PIIC and IIPA argue that the Company
24 has overstated the economic benefits of the Combined
25 Projects because natural-gas prices in the base case are
275 Link,Di-Reb -20
Rocky Mountain Power
1 too high.(Phillips Direct,page 18,lines 18-19;Mullins
2 Direct,page 17,lines 17-18;Yankel Direct,page 11,
3 lines 1-8.)How does the Company determine the forecasted
4 natural gas prices used for the economic analysis?
5 A.The medium or base-case forecast is the
6 Company's OFPC,which uses observed forward market prices
7 for the first 72 months,followed by a 12-month
8 transition to natural-gas prices based on a forecast
9 developed by a reputable third-party expert.The
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
276 Link,Di-Reb -20a
Rocky Mountain Power
1 low-and high-natural-gas price assumptions were alsoO2basedonrecentforecastsdevelopedbyreputable
3 third-party experts.The Company verified the
4 reasonableness of the third-party forecasts by comparison
5 to forecasts prepared by others,including the U.S.
6 Department of Energy's Energy Information Administration.
7 Q.Is the OFPC used in the Company's economic
8 analysis the same forecast the Commission has used for
9 ratemaking,setting avoided-costs prices,and evaluating
10 both demand-and supply-side resources?
11 A.Yes.The OFPC,which represents the medium
12 natural-gas price case is the same forecast used for
13 setting net power costs in the Company's Idaho rates.It
14 is also used when the Company calculates avoided-cost
15 prices paid to qualifying facilities,and evaluates the
16 cost-effectiveness of demand-side and supply-side
17 resources.
18 Q.How does the Company use each of the
19 price-policy scenarios in its analysis?
20 A.The price-policy scenario assuming medium
21 natural-gas prices and medium carbon dioxide ("CO2")
22 prices represents the central forecast,around which the
23 impact of lower or higher price assumptions can be
24 evaluated.In the Company's initial filing,the
25 present-value revenue requirement differential
277 Link,Di-Reb -21
Rocky Mountain Power
1 ("PVRR(d)")net benefit of the Combined Projects derivedO2fromthecentralprice-policy scenario is $137 million
3 when calculated off the forecasted change in annual
4 revenue requirement through 2050.This outcome indicates
5 that,when central price-policy assumptions are used,
6 there is a reasonably sized cushion in the PVRR(d)
7 results allowing for some erosion of the favorable
8 economics should long-term natural-gas prices and CO2
9 prices end up lower than what is assumed in this
10 scenario.The other price-policy scenarios are useful in
11 quantifying how sensitive the PVRR(d)results are to
12 these key assumptions and
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
278 Link,Di-Reb -21a
Rocky Mountain Power
1 provide a foundation for judging risk.O 2 Q.Monsanto recommends the low-natural-gas price
3 case be considered the base case for purposes of
4 evaluating the Combined Projects (Phillips Direct,page
5 18,lines 18-19.)How do you respond to this
6 recommendation?
7 A.I disagree.Monsanto relies on NYMEX Henry Hub
8 natural-gas futures to conclude this comparison shows
9 current market expectations most closely align with the
10 Company's low natural-gas forecast.But this conclusion
11 is misguided because it relies solely on NYMEX Henry Hub
12 natural-gas futures after 2022,which do not accurately
13 capture market expectations for long-term natural-gas
14 prices.Monsanto fails to consider the open interest in
15 NYMEX Henry Hub futures contracts,which quickly falls
16 for futures contracts further out in time.The sparsity
17 of open interest in the out period makes these futures
18 contracts an unreliable indicator of market expectations
19 for long-term natural-gas prices.
20 Each futures trade represents the creation of a
21 new contract and is indicative of new capital being
22 committed to the market.Figure 2 shows NYMEX Henry Hub
23 natural-gas open interest as of September 11,2017.
24 /
25 /
279 Link,Di-Reb -22
Rocky Mountain Power
1
2 Figure 2.NYMEX Henry Hub Natural Gas Futures
3 Open Interest as of September 11,2017
0·
12
13 This figure shows that open interest is greater
14 in the near term and significantly lower in the long
15 term.For instance,in 2018 open contracts average over
16 43,200.By 2023,open contracts average just over
17 2,600-approximately six percent of the open interest
18 observed for 2018 contracts.The concentration in the
19 earlier futures indicates the market is deeper and
20 stronger in the near term because fewer market
21 participants are willing to commit capital required to
22 enter and maintain long-term contracts.
23 There are very few contracts supporting NYMEX
24 Henry Hub natural-gas-futures prices over the period in
25 which Monsanto claims the market outlook most closely
280 Link,Di-Reb -23RockyMountainPower
1 aligns with the Company's low natural-gas price forecast
2 (i.e.,beyond 2024).Contracts with greater open interest
3 more accurately represent a market consensus of where
4 spot prices are likely to trade.Long-term prices are
5 shaped by a handful of participants who are lightly
6 committed.These participants are basing their decisions
7 on highly imperfect data.Short-term prices are shaped by
8 a large field of market
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
281 Link,Di-Reb -23a
Rocky Mountain Power
1 participants,who commit far more capital because there
2 is more transparency around the conditions and variables
3 that can impact prices.
4 Q.Do some parties claim that the Company's OFPC
5 reflects market prices that are too high?
6 A.Yes.PIIC claims that the Company's OFPC
7 systematically overstates future market prices.(Mullins
8 Direct,page 17,lines 17-18.)Monsanto and IIPA
9 similarly observe that the Company's OFPC has
10 historically exceeded the market.(Phillips Direct,page
11 19,lines 5-10;Yankel Direct,page 13,lines 15-22.)
12 Q.Does Staff agree?
13 A.No.Staff testifies that the "range of natural
14 gas forecasts used in [the Company's]analysis are
15 conservative when compared to the most recent Energy
16 Information Administration (EIA)forecasts."(Keller
17 Direct,page 16,lines 12-14.)
18 Q.Please respond to the intervenors'challenges
19 to the OFPC.
20 A.It is not reasonable to evaluate a forecast
21 error for OFPCs.The Company's OFPC is developed from a
22 combination of market forwards on a given quote date and
23 a long-term,fundamentals-based forecast as a proxy for
24 forward prices beyond the period in which observed market
25 forwards are not available.Forecast error is a measure
282 Link,Di-Reb -24
Rocky Mountain Power
1 of the difference between forecasted spot prices and
2 actual spot prices.Comparing forward prices to actual
3 spot prices is a misapplication of forecast error,
4 because market forwards,which are used in the first 84
5 months of the OFPC,are observed-not forecasted.Forward
6 prices represent transaction prices occurring at the time
7 of a future delivery date.
8 Market participants cannot transact on a
9 spot-price forecast.A spot-price
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
283 Link,Di-Reb -24a
Rocky Mountain Power
1 forecast merely represents a potential view of what
2 prices will be at some point in the future.Market
3 forwards reflect pricing for contracts that reflect the
4 price,on a given quote date,at which buyers and sellers
5 are transacting for future delivery.
6 Q.PIIC also claims:"If the OFPCs are reasonably
7 accurate,one would expect PacifiCorp's price forecast to
8 be an unbiased expectation of future spot prices."
9 (Mullins Direct,page 20,lines 14-15.)Is this true?
10 A.Not necessarily.It is not strictly true that
11 the forward prices will or should equal the expected
12 price.Forward buyers and sellers are considering the
13 trade-off between using a fixed forward price and simply
14 waiting to transact at a risky spot price.To avoid
15 arbitrage,these two have to be equal in present value,
16 not in delivery-date value.In general,it is likely that
17 spot prices are somewhat systematically risky,because
18 demand for most commodities tends to move with the
19 economy as a whole.Thus,it is unlikely that the
20 appropriate discount rate for taking the present value of
21 expected spot prices will be the risk-free rate that
22 applies to discounting the forward price.For the two
23 present values to be equal,the two future values have to
24 be somewhat different.
25 Q.PIIC argues that the historical difference
284 Link,Di-Reb -25
Rocky Mountain Power
1 between the forecasted and actual spot prices indicates
2 that there is a risk premium embedded in the OFPC.
3 (Mullins Direct,page 21,line 5-19.)How do you respond?
4 A.There may be a risk premium in the forward
5 prices,which are used in the first 84 months of the
6 OFPC,but that does not mean there is a risk premium
7 further out in the forecasted period.
8 Moreover,Mr.Mullins'position here is
9 contradicted by his testimony before the Oregon
10 Commission earlier this year.In the Company's annual
11 proceeding to
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
285 Link,Di-Reb -25a
Rocky Mountain Power
1 update power costs,Mr.Mullins testified that the
2 Company's electric market transactions entered more than
3 seven days before the settlement period (i.e.,hedging
4 transactions)systematically generate customer benefits
5 because the forward price curve is systematically lower
6 than actual spot market prices.
7 Q.PIIC claims that the Commission has expressed
8 skepticism about the accuracy of long-term forecasting
9 when it ordered a reduction in QF contract terms to
10 two-years.(Mullins Direct,page 22,lines 12-19.)Please
11 respond.
12 A.This argument is unpersuasive.First,the
13 Company's avoided cost prices in Idaho are set using the
14 OFPC.Despite the Commission's concern over the inherent
15 difficulty of forecasting,it has not implemented a
16 policy requiring the Company to use a lower forward price
17 curve for avoided-cost prices.Second,this argument
18 ignores the fact that all long-term resource planning
19 requires the use of long-term assumptions and forecasts.
20 The implication of PIIC's argument is that the Company
21 should be planning for only the next two years;but
22 taking that approach to resource planning would be
23 unacceptable.There is no doubt that there is uncertainty
24 in future wholesale market prices,which is precisely the
25 reason that the Company evaluated the Combined Projects
286 Link,Di-Reb -26
Rocky Mountain Power
1 across a range of different price-policy scenarios.O 2 Q.PIIC further claims that two gas hedging
3 contracts entered into in 2012 have been harmful to
4 customers.(Mullins Direct,page 23,lines 5-21.)How do
5 you respond?
6 A.PIIC inappropriately reviews the performance of
7 these two natural-gas hedges as financial trades.A
8 financial trade is executed based on a speculative market
9 view to earn a favorable return.A hedge is made to limit
10 exposure to market volatility,not to earn a favorable
11 return.The value of a hedge is not based on the
12 fixed-price exposure
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
287 Link,Di-Reb -26a
Rocky Mountain Power
1 of the hedge,but its effectiveness in limiting exposureO2tovolatilityinspotmarketprices.The effectiveness of
3 these hedge transactions have no relevance to the
4 validity of the Company's OFPC,which reflects the best
5 and unbiased representation of future market conditions
6 available at the time the OFPC is produced,and has no
7 relevance to the economic analysis of the Combined
8 Projects.
9 Q.Monsanto criticizes the Combined Projects
10 because,under most scenarios,they do not meet a
11 benefit-to-cost ratio of 1.15 or 1.25.(Phillips Direct,
12 pages 11-13.)Please respond.
13 A.To my knowledge,the Idaho Commission has never
14 required that supply-side investments meet a particular
15 benefit-to-cost ratio,and demand-side resources are
16 expected to meet a ratio of only 1.0-a ratio that
17 Monsanto acknowledges the Combined Projects meet under
18 nearly all scenarios.The premise of Monsanto's argument
19 is that the Combined Projects should be subject to a new,
20 higher standard for approval because they are not needed
21 to serve customers.This premise is false because the
22 Combined Projects meet a resource need and will
23 immediately be used to economically serve customers.
24 Q.PIIC claims the Company used supplemental GRID
25 studies to develop unrealistic assumptions that are a
288 Link,Di-Reb -27
Rocky Mountain Power
1 "key driver in the economic benefits"of the CombinedO2Projects.(Mullins Direct,page 26,line 8 to page 27,
3 line 8.)Is this true?
4 A.No.Contrary to PIIC's claim,the Company's
5 economic analysis supporting the Combined Projects does
6 not include any assumptions derived from the supplemental
7 GRID studies referenced by Mr.Mullins.The GRID studies
8 and assumptions referred to by Mr.Mullins were used in
9 the 2017 IRP,but not in the economic analysis included
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
289 Link,Di-Reb -27a
Rocky Mountain Power
1 in this case.O 2 Q.Does PIIC criticize the Company's assumed
3 charge for wind integration used in the economic analysis
4 supporting the Combined Projects?
5 A.Yes.PIIC notes that the Company's
6 wind-integration charge assumed in the economic analysis
7 supporting the Combined Projects is $0.63/megawatt-hour
8 ("MWh"),when the current rate is $3.06/MWh.PIIC claims
9 that the Company's recent filing to reduce the
10 wind-integration charge to $0.57/MWh is manipulative and
11 self-serving,and until the charge is reduced,the
12 Company should use the approved rate,which would
13 substantially reduce the economic benefits of the
14 Combined Projects.(Mullins Direct,pages 32-33).
15 Q.Please respond.
16 A.The Commission approved the Company's proposed
17 change to the wind integration rate on November 28,2017,
18 rendering PIIC's proposal moot.The change in
19 regulation-reserve costs is attributable to lower market
20 prices,transmission congestion as a result of sizeable
21 increases in solar capacity in the Company's portfolio,
22 and expanding the pool of regulation-reserve resources to
23 include 30-minute ramping capability,none of which are
24 disputed by PIIC.Thus,the wind-integration cost
25 assumptions developed in the Company's 2017 IRP are the
290 Link,Di-Reb -28
Rocky Mountain Power
1 most accurate estimate available,regardless of the
2 status of IRP acknowledgment or its inclusion in
3 published avoided-cost prices.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
291 Link,Di-Reb -28a
Rocky Mountain Power
1 Q.IIPA testifies that,given the presentO2politicalclimate,there may never be a carbon tax within
3 the timeframe of the Company's analysis,and the
4 scenarios with medium or high carbon prices should be
5 given little weight.(Yankel Direct,pages 22-23.)Do you
6 agree?
7 A.No.It is not reasonable to conclude that
8 today's policy environment is the best indicator of the
9 policy environment we can expect over the next three
10 decades.It is even more unreasonable to dismiss the
11 results of scenarios developed to quantify the economic
12 impact of potential environmental policy outcomes that
13 could impute a financial cost on CO2 emissions at some
14 point over the next three decades.
15 Q.Did parties criticize the Company for how it
16 evaluated risks related to projected net capacity factors
17 ("NCF")for the proposed new Wind Projects?
18 A.Yes.Monsanto criticizes the Company for not
19 providing sensitivity analysis around the projected NCF,
20 and asserts that even a small deviation in NCF (10
21 percent)could make the Combined Projects uneconomic.
22 (Phillips Direct,pages 26-30.)IIPA makes a similar
23 argument about this risk,noting that the Company showed
24 the material impact of capacity factor assumptions when
25 it reduced its estimates by 1.8 percent in its initial
292 Link,Di-Reb -29
Rocky Mountain Power
1 filing.(Yankel Direct,pages 19-20.)O 2 Q.How do you respond?
3 A.Monsanto and IIPA do not testify that
4 PacifiCorp's wind generation forecasts are invalid.They
5 simply assert a potential risk to the overall economics
6 if wind generation output is reduced.This one-sided risk
7 assessment fails to quantify the potential upside
8 benefits if wind generation exceeds the assumed forecast
9 used in the economic analysis.The Company retained an
10 independent expert to study and confirm the
11 reasonableness
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
293 Link,Di-Reb -29a
Rocky Mountain Power
1 of its NCF assumptions for specific projects bid into theO22017RRFP,and the findings of this review will be
3 reflected in the economic analysis of specific proposals,
4 which will be included in the Company's supplemental
5 filing.
6 Q.Monsanto argues that moving forward with the
7 Combined Projects now risks the loss of more economic
8 generation resources in the future.(Phillips Direct,
9 page 21,lines 3-11.)How do you respond?
10 A.The Combined Projects do not foreclose future
11 options.In fact,the 2017 IRP preferred portfolio
12 balances the benefits of near-term wind-resource
13 procurement with the upside of potential future
14 technological advancements that might lower renewable
15 resource costs.Near-term procurement of the wind
16 resources in the Combined Projects partially meets
17 near-term and long-term resource needs and over the long
18 term,the 2017 IRP preferred portfolio includes
19 additional renewable resources to partially meet
20 long-term resource needs.
21 Over the 2028-to-2036 timeframe,the 2017 IRP
22 preferred portfolio includes over 800 MW of incremental
23 new wind resources beyond those included in the Combined
24 Projects,and over 1,000 MW of incremental new solar
25 resources.After the Combined Projects are completed,the
294 Link,Di-Reb -30
Rocky Mountain Power
1 Company will retain sufficient future flexibility toO2respondtochangingdemandsandmarketplace
3 opportunities.
4 Second,Monsanto supports this claim by
5 pointing to the Utah Commission's suggestion that the
6 Company initiate a solar RFP to test whether alternative
7 resources could be more economic than the Combined
8 Projects.The Company issued the 2017S RFP,and its
9 results will be used to inform the outcome of the 2017R
10 RFP.
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
295 Link,Di-Reb -30a
Rocky Mountain Power
1 Q.PIIC argues that projected oversupply
2 conditions in the West pose a risk to the Combined
3 Projects that was not considered by PacifiCorp.(Mullins
4 Direct,page 13,lines 19-14,line 7.)Was this
5 considered?
6 A.The Company is aware of the development of
7 renewable resources across the West.However,oversupply
8 conditions are driven by the correlation between large
9 numbers of intermittent renewable resources.For
10 instance,wind resources in the Columbia River Gorge are
11 often either mostly on or mostly off,with appreciable
12 impacts on market prices in both directions.Similarly,
13 solar resources across the West are strongly correlated
14 with the position of the sun and thus each other,and
15 likewise impact market prices in both directions.
16 While wind resources in Wyoming are correlated
17 with each other,they are not strongly correlated with
18 wind resources in the Columbia River Gorge or solar
19 resources.The correlation of the proposed resources with
20 the rest of the wind in the Company's portfolio is
21 already accounted for in the Company's analysis and the
22 expected overall impact of renewable resource additions
23 in the West is accounted for in the Company's OFPC.Thus,
24 the Company's economic analysis reasonably accounts for
25 potential oversupply conditions applicable to the
296 Link,Di-Reb -31
Rocky Mountain Power
1 proposed resources.O 2 Moreover,the majority of the benefits
3 associated with the Combined Projects are a result of
4 fuel savings at PacifiCorp's plants,rather than market
5 transactions based on the OFPC,particularly in the first
6 few years.The costs associated with the Company's fuel
7 supply are less likely to be impacted by oversupply
8 conditions in the manner suggested by PIIC.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
297 Link,Di-Reb -31a
Rocky Mountain Power
1 Q.Monsanto,PIIC and IIPA also point out the riskO2associatedwithfederaltaxreform(Phillips Direct,page
3 21,lines 11-14;Mullins Direct,pages 33-34;Yankel
4 Direct,page 18.)How will the Company account for this
5 risk?
6 A.The Company's supplemental testimony will
7 account for the impact of tax reform,either based on the
8 final version of legislation enacted by that time,or
9 based on a sensitivity using reasonable assumptions about
10 the outcome of tax reform.The Company expects resolution
11 of the current uncertainty around tax reform in the
12 coming weeks.As discussed by Company witness Mr.Chad A.
13 Teply,the schedule for the Combined Projects will allow
14 the Company to evaluate tax impacts before moving forward
15 with construction,and utilize off-ramps if tax law
16 changes materially impact the economics of the Combined
17 Projects.
18 CONCLUSION AND RECOMMENDATION
19 Q.Do you recommend that the Commission approve
20 the Company's application?
21 A.Yes.The updated economic analysis that will be
22 included in the Company's January 16,2018 supplemental
23 filing will address a number of the specific issues
24 raised around the size and certainty of the economic
25 benefits of the Combined Projects,including the impact
298 Link,Di-Reb -32
Rocky Mountain Power
1 of changes to federal tax law.Despite claims to theO2contrary,PacifiCorp has near-term and long-term resource
3 needs that can be partially met with heavily discounted
4 Wind Projects that are lower cost than all other
5 near-term and long-term resource alternatives.The
6 Combined Projects are an element of PacifiCorp's
7 least-cost,least-risk resource plan and there is nothing
8 novel or unique about these resources that justifies
9 unprecedented cost-recovery treatment to assign all risk
10 to the Company.The Company's long-standing methodology
11 to develop its OFPC produces the best
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
299 Link,Di-Reb -32a
Rocky Mountain Power
1 representation of future market prices for the centralO2forecast,and alternative price-policy scenarios provide
3 a reasonable foundation for judging risk.
4 Q.Does this conclude your rebuttal testimony?
5 A.Yes.
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
300 Link,Di-Reb -33
Rocky Mountain Power
1 Q.Are you the same Rick T.Link who previously
2 provided direct and rebuttal testimony in this case on
3 behalf of Rocky Mountain Power ("Company"),a division of
4 PacifiCorp?
5 -A.Yes.
6 PURPOSE AND SUMMARY OF TESTIMONY
7 Q.What is the purpose of your supplemental direct
8 testimony?
9 A.In my testimony,I summarize the results of the
10 2017R Request for Proposals ("RFP").I also provide
11 updates to the economic analysis that demonstrate
12 increasing customer benefits from the new wind resources
13 ("Wind Projects")and construction of the Aeolus-to-
14 Bridger/Anticline line and network upgrades
15 ("Transmission Projects")(collectively,the "Combined
16 Projects").
17 Q.Please summarize your supplemental direct
18 testimony.
19 A.The 2017R RFP generated robust and competitive
20 responses from market participants.The final shortlist
21 includes four new wind projects located in Wyoming from
22 three different bidders.The total capacity of the four
23 projects is 1,170 megawatts ("MW")including three of the
24 benchmark facilities (TB Flats I and II,now combined as
25 a single project,and McFadden Ridge II),and two new
301 Link,Di-Supp -1
Rocky Mountain Power
1 facilities (Cedar Springs and Uinta).Uinta is a
2 build-transfer agreement ("BTA")totaling 161 MW,Cedar
3 Springs is one-half BTA and one-half power purchase
4 agreement ("PPA"),for a total of 400 MW,and TB Flats I
5 and II and McFadden Ridge II are Company-built
6 facilities,totaling 500 MW and 109 MW,respectively.
7 The results of the 2017R RFP and the extensive
8 modeling that supports it confirm that the Combined
9 Projects are the least-cost,least-risk path available to
10 serve
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
302 Link,Di-Supp -laRockyMountainPower
1 the Company's customers by meeting both near-term andO2long-term needs for additional resources.My supplemental
3 direct testimony explains the following:
4 °The Combined Projects provide net customer benefits
5 under all scenarios studied through 2036,and in
6 seven of the nine scenarios through 2050.
7 °Customer benefits increase to $151 million in the
8 medium case through 2050 (as compared to $137
9 million in the original filing),and range from $333
10 million to $349 million in the medium case through
11 2036.
12 °The analysis reflects changes in federal tax law
13 that were enacted in December 2017,and updated
14 best-and-final pricing from bidders received
15 December 21,2017,after the federal tax law changes
16 were known.
17 °The treatment of production tax credits ("PTCs")in
18 the system modeling scenarios extending out through
19 2036 has been changed to better reflect how the PTCs
20 will flow through to customers,which makes the
21 treatment consistent with the nominal revenue
22 requirement results that extend out through 2050.
23 Sensitivity analysis shows substantial benefits of
24 the Combined Projects persist when paired with
25 PacifiCorp's wind repowering project and are not
303 Link,Di-Supp -2
Rocky Mountain Power
1 displaced when considering the potential procurementO2ofsolarPPAbidssubmittedintotheon-going RFP
3 for solar resources,the 2017S RFP.
4 2017R RFP RESULTS
5 Q.To recap the status of the 2017R RFP,when was
6 it issued?
7 A.As described in my rebuttal testimony,
8 PacifiCorp issued the 2017R RFP on September 27,2017,
9 after it was approved by the Public Service Commission of
10 Utah ("Commission")on September 22,2017,and the Public
11 Utility Commission of Oregon
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
304 Link,Di-Supp -2aRockyMountainPower
1 ("Oregon Commission")on September 27,2017.O 2 Q.Was the scope of the 2017R RFP modified before
3 it was issued to include non-Wyoming wind projects?
4 A.Yes.The Company's original proposal limited
5 the RFP to wind resources capable of interconnecting to
6 or delivering on a firm basis to the Company's
7 transmission system in Wyoming.In response to issues
8 raised in the RFP approval process,and consistent with
9 the recommendations of Merrimack Energy Group,Inc.,the
10 Utah independent evaluator ("IE"),the Company expanded
11 the 2017R RFP to allow bids from non-Wyoming wind
12 projects capable of interconnecting to or delivering on a
13 firm basis to anywhere on the Company's transmission
14 system.
15 Q.In response to the Utah Commission's approval
16 order,did the Company decide to issue a solar RFP to run
17 concurrently with the 2017R RFP?
18 A.Yes.In its order approving the 2017R RFP,the
19 Utah Commission suggested,but did not require,a
20 modification to expand the 2017R RFP to solicit solar
21 resource bids.To maintain the 2017R RFP schedule while
22 addressing the Utah Commission's suggestion,the Company
23 issued a separate solicitation process for solar
24 resources,the 2017S RFP,on November 15,2017.The 2017S
25 RFP sought bids for solar resources up to 300 MW per
305 Link,Di-Supp -3
Rocky Mountain Power
1 individual project that can deliver energy and capacity
2 to the Company's transmission system.
3 Similar to the 2017R RFP,the Company retained
4 London Economics International,LLC ("Solar RFP IE")as
5 the IE to oversee the solar RFP process.The 2017S RFP
6 schedule allowed the Company to:(1)evaluate how solar
7 resource bids might impact the economic analysis of bids
8 selected to the final shortlist in the 2017R
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
306 Link,Di-Supp -3aRockyMountainPower
1 RFP without delaying the schedule for the 2017R RFP;and
2 (2)explore whether new solar resource opportunities
3 might provide all-in economic benefits for customers.
4 Q.When did the Company receive initial bids in
5 the 2017R RFP?
6 A.The Company received initial bids for Wyoming
7 wind projects on October 17,2017,and initial bids for
8 non-Wyoming wind projects on October 24,2017.The 2017R
9 RFP was well received by the market,as indicated by the
10 fact the Company received Wyoming wind proposals from
11 nine bidders offering 49 bid alternatives for 13 wind
12 projects.The Company also received non-Wyoming wind
13 proposals from five bidders offering 15 bid alternatives
14 for six wind projects.In aggregate,5,219 MW of new wind
15 resource capacity was bid into the 2017R RFP (4,624 MW of
16 Wyoming wind and 595 MW of non-Wyoming wind).
17 Q.When did the Company complete its initial
18 shortlist evaluation?
19 A.The Company completed its initial shortlist
20 evaluation and scoring and began a capacity factor
21 evaluation process,performed by Sapere Consulting,on
22 November 12,2017.The Utah IE and Bates White,LLC,the
23 Oregon IE,completed their review of the initial
24 shortlist on November 17,2017.Once the IEs completed
25 their review of the initial shortlist,the Company
307 Link,Di-Supp -4
Rocky Mountain Power
1 notified bidders whether their proposed projects wereO2selectedtotheinitialshortlistandprovidedan
3 opportunity for bidders selected to the initial shortlist
4 to update pricing.On November 22,2017,the Company
5 received best-and-final pricing for bids selected to the
6 initial shortlist.
7 Q.Did the Company use the best-and-final pricing
8 received on November 22,2017,to establish the 2017R RFP
9 final shortlist?
10 A.No.On November 16,2017,shortly after
11 best-and-final pricing was received,the U.S.
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
308 Link,Di-Supp -4a
Rocky Mountain Power
1 House of Representatives passed H.R.1,which included
2 changes in federal tax law reasonably expected to affect
3 bid pricing.On December 2,2017,the U.S.Senate passed
4 its own version of a tax-reform bill,setting the stage
5 for a conference committee to reconcile differences
6 between the two bills.On December 7,2017,the Company
7 notified bidders that it would request updated pricing to
8 reflect potential changes in federal tax law once the
9 reconciliation process initiated by Congress was
10 completed.On December 15,2017,the conference committee
11 approved its report on H.R.1,and on December 18,2017,
12 the Company notified bidders that updated best-and-final
13 pricing reflecting federal tax provisions outlined in the
14 conference committee's report on H.R.1 must be submitted
15 by December 21,2017.The updated best-and-final pricing
16 received on December 21,2017,was used to establish the
17 2017R RFP final shortlist.
18 Q.Were the provisions in the conference
19 committee's report on H.R.1 ultimately passed by
20 Congress and signed by the President?
21 A.Yes.Congress passed H.R.1 on December 20,
22 2017.The bill became law on December 22,2017 when it
23 was signed by President Trump.
24 Q.How did the Company select which bids to
25 include in the 2017R RFP final shortlist?
309 Link,Di-Supp -5
Rocky Mountain Power
1 A.Consistent with the bid evaluation and
2 selection process outlined in the Commission-approved
3 RFP,the final shortlist selection process was
4 implemented in two basic phases--the portfolio-
5 development phase and the scenario-risk phase.
6 Q.Please describe the portfolio-development
7 phase.
8 A.The portfolio-development phase identifies the
9 least-cost combination of bids using a methodology that
10 is consistent with the approach used to produce resource
11 portfolios
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
310 Link,Di-Supp -5a
Rocky Mountain Power
1 in the integrated resource plan ("IRP").The portfolio-
2 development phase was initiated by processing best-and-
3 final pricing for each bid into the cost-and-performance
4 data required as inputs to the System Optimizer ("SO")
5 model and the Planning and Risk model ("PaR").
6 The SO model was then used to develop bid
7 portfolios containing the least-cost combination of bids
8 over a twenty-year planning horizon (2017 through 2036).
9 When choosing the least-cost combination of bids,the SO
10 model was configured to select from all of the bids and
11 bid alternatives included in the initial shortlist and
12 all other proxy-resource alternatives used to develop
13 resource portfolios in the PacifiCorp's 2017 IRP (i.e.,
14 front-office transactions or "FOTs",demand-side
15 management resources,new thermal resources,etc.).The
16 Company did not force the SO model to select any bid or
17 any combination of bids.
18 The Company developed bid portfolios for nine
19 price-policy scenarios,which,as described in my direct
20 testimony,are developed by pairing three natural-gas
21 price forecasts (low,medium,and high)with three carbon
22 dioxide ("CO2")price forecasts (zero,medium,and high).
23 I describe updates made to these price-policy scenarios
24 since the Company's original filing later in my
25 testimony.
311 Link,Di-Supp -6
Rocky Mountain Power
1 For each price-policy scenario,the Company
2 also calculated the present-value revenue-requirement
3 differential ("PVRR(d)")between two system
4 simulations-one that includes 2017R RFP bids and the
5 Transmission Projects and one without.These studies were
6 prepared using the SO model and PaR and are used to
7 quantify the economic impact of top-performing bid
8 portfolios.
9 The combination of bids selected by the SO
10 model across each of the nine price-
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
312 Link,Di-Supp -6aRockyMountainPower
1 policy scenarios and the accompanying PVRR(d)results,
2 calculated using the SO model and PaR,identifies the bid
3 portfolios expected to deliver economic benefits for
4 customers.Specific to the 2017R RFP,this process
5 identified two bid portfolios that were then further
6 evaluated in the scenario-risk analysis phase of the
7 bid-selection process.
8 Q.When developing bid portfolios,how much new
9 wind capacity could the SO model select in eastern
10 Wyoming?
11 A.Consistent with the assumptions in my direct
12 testimony,the Company assumed that the Aeolus-to-
13 Bridger/Anticline transmission line will enable
14 interconnection of up to 1,270 MW of additional wind
15 resources to PacifiCorp's transmission system in eastern
16 Wyoming.Considering that there is a transmission
17 customer in the interconnection queue with an executed
18 interconnection agreement for a 240 MW qualifying
19 facility ("QF")in the area,the Company assumed that
20 sufficient interconnection capacity must be reserved for
21 this transmission customer.Consequently,the Company
22 restricted new wind resource bids in eastern Wyoming to
23 1,030 MW (1,270 MW less 240 MW).
24 Q.Please describe the scenario-risk-analysis
25 phase of the final shortlist bid-evaluation process.
313 Link,Di-Supp -7
Rocky Mountain Power
1 A.The scenario-risk phase of the bid-evaluationO2processensuresthatthetwotop-performing bid
3 portfolios identified in the portfolio-development phase
4 of the selection process are analyzed among all nine
5 price-policy scenarios.For instance,one of the bid
6 portfolios identified in the portfolio-development phase
7 includes a consistent set of bids selected by the SO
8 model in five of the nine price-policy scenarios.The
9 second bid portfolio,which includes the same bids that
10 are in the first bid portfolio plus an
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
314 Link,Di-Supp -7a
Rocky Mountain Power
1 additional bid,was selected by the SO model in the otherO2fourprice-policy scenarios.In the scenario-risk phase
3 of the bid-selection process,the first bid portfolio was
4 analyzed in the four price-policy scenarios where it was
5 not selected as the least-cost bid portfolio.Similarly,
6 the second bid portfolio was analyzed in the five
7 price-policy scenarios where it was not selected as the
8 least-cost bid portfolio.
9 As in the portfolio-development phase,these
10 studies were performed using the SO model and PaR.The
11 outputs from these studies were used to calculate the
12 PVRR(d)between two system simulations-one that includes
13 2017R RFP bids and the Transmission Projects and one
14 without.The Company then used the PVRR(d)results to
15 initially identify the least-cost,least-risk bid
16 portfolio.
17 Q.Did the Company identify any issues in the
18 modeling initially used in the portfolio-development
19 phase and scenario-risk phase of the bid-selection
20 process?
21 A.Yes.On-going due-diligence review of the
22 least-cost,least-risk bid portfolio allowed the Company
23 to identify two issues with specific bids that affected
24 the initial economic analysis.First,the Company
25 discovered that capacity factor adjustments applied to
315 Link,Di-Supp -8
Rocky Mountain Power
1 two bids were only partially captured in the SO model and
2 PaR simulations.Consistent with recommendations from
3 Sapere Consulting,the net capacity factor for two
4 projects were assessed at 92 percent of the net capacity
5 factor proposed by (redacted).When applying the
6 net-capacity-factor adjustment in the SO model and PaR,
7 its impact on federal PTC benefits and bid costs were
8 accurately captured.However,its impact on the expected
9 energy output was not captured.This had the effect of
10 overstating net power cost ("NPC")benefits associated
11 with these bids,one of which was included in the initial
12 least-cost,least-risk bid portfolio.
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
316 Link,Di-Supp -8a
Rocky Mountain Power
1 The second issue was identified when reviewingO2redlineeditsmadeby(redacted)to the 2017R RFP
3 pro-forma BTA.Specifically,the Company noticed that
4 (redacted),which submitted several BTA bids,with two of
5 these bids initially included in the least-cost,
6 least-risk bid portfolio,struck language specifying that
7 it would be responsible for applicable sales taxes.
8 (redacted)subsequently confirmed that its price
9 proposals did not include sales tax,and the Company
10 confirmed that it did not include sales tax in its
11 evaluation of costs for any of the (redacted)BTA bids.
12 Q.How did the Company evaluate the impact of
13 these two issues in the bid-selection process?
14 A.The Company first corrected the
15 net-capacity-factor inputs for the two projects proposed
16 by (redacted)and included the estimated cost of sales
17 tax on all of the (redacted)BTA bids.Once these
18 corrections were made,the Company reran the SO model
19 portfolio-development studies for two price-policy
20 scenarios-one pairing low natural gas prices with zero
21 CO2 prices and one pairing medium natural gas prices with
22 medium CO2 prices.
23 Q.Did the correction to the net-capacity-factor
24 inputs for the (redacted)bids cause a change in the bid
25 portfolio in these updated SO model studies?
317 Link,Di-Supp -9
Rocky Mountain Power
1 A.No.The (redacted)bid that was included in the
2 original least-cost,least-risk bid portfolio continued
3 to be selected by the SO model in both price-policy
4 scenarios.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
318 Link,Di-Supp -9a
Rocky Mountain Power
1 Q.Did the application of sales tax to the
2 (redacted)BTA bids cause a change in the bid portfolio
3 in these updated SO model studies?
4 A.Yes.When sales tax was added to the cost of
5 the (redacted)BTA bids,one of its two projects that was
6 originally included in the initial least-cost,least-risk
7 bid portfolio was replaced with another bid.
8 Specifically,(redacted)BTA bid for the (redacted)was
9 replaced with (redacted)for the (redacted).
10 Q.Did the Company update its economic analysis to
11 account for this update to the bid portfolio?
12 A.Yes.The economic analysis among all nine
13 price-policy scenarios was refreshed to reflect this
14 updated bid portfolio,representing the 2017R RFP final
15 shortlist,with corrected cost-and-performance inputs.
16 This analysis was updated using the SO model and PaR.I
17 describe the Company's updated economic analysis,for the
18 Combined Projects including the 2017R RFP final
19 shortlist,later in my testimony.
20 Q.Did the Company inform the Utah and Oregon IEs
21 of changes to the 2017R RFP final shortlist resulting
22 from the corrections applied to the modeling described
23 above?
24 A.Yes.When issues related to the application of
25 net-capacity factor adjustments and the omission of sales
319 Link,Di-Supp -10
Rocky Mountain Power
1 tax in the economic analysis were discovered,the Company
2 notified the Utah and Oregon IEs to explain the impact on
3 the 2017R RFP final shortlist and the impact on the
4 economic analysis.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
320 Link,Di-Supp -10aRockyMountainPower
1 Q.Did the Oregon IE request any additional
2 sensitivity studies during its review of the 2017R RFP
3 final shortlist analysis?
4 A.Yes.As I will address more fully later in my
5 testimony,the Company's bid-selection modeling,
6 performed using the SO model and PaR,reflects nominal
7 federal PTC inputs,to be consistent with how federal PTC
8 benefits will flow into customer rates,where applicable,
9 rather than levelized federal PTC inputs.To understand
10 the impact of this assumption on bid selections,the
11 Oregon IE requested that the Company produce an SO model
12 sensitivity,with levelized PTCs,using medium natural
13 gas price and medium CO2 price assumptions to understand
14 how treatment of federal PTCs affects bid selection.The
15 Utah IE also expressed interest in seeing this
16 sensitivity.
17 Q.What were the findings from this IE
18 sensitivity?
19 A.When federal PTCs applicable to BTA bids and
20 benchmark bids are levelized,the SO model replaces two
21 BTA bids and a benchmark bid with two PPA bids.The
22 PVRR(d)net benefits in the IE sensitivity,calculated
23 from projected system costs through 2036 from the SO
24 model,are lower in the IE sensitivity than they are in
25 the economic analysis using the 2017R RFP final
321 Link,Di-Supp -11
Rocky Mountain Power
1 shortlist.In reviewing these results with the IEs,theO2Companyalsohighlightedthatthebidportfoliointhe IE
3 sensitivity produces higher nominal costs when compared
4 to the economic analysis based on the 2017R RFP final
5 shortlist.
6 Q.Did the Company change its 2017R RFP final
7 shortlist based on the IE sensitivity?
8 A.No.While the IE sensitivity shows a change in
9 the bid portfolio,this portfolio is selected based on
10 federal PTC inputs that are inconsistent with how PTC
11 benefits will be treated in customer rates.Moreover,the
12 net benefits from the bid portfolio in the IE
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
322 Link,Di-Supp -lla
Rocky Mountain Power
1 sensitivity produce lower PVRR(d)benefits and lower
2 near-term nominal net-benefits than the bid portfolio
3 reflected in the 2017R RFP final shortlist.
4 Q.Please describe the final shortlist of winning
5 bids from the 2017R RFP.
6 A.The 2017R RFP final shortlist includes four new
7 wind projects located in Wyoming from three different
8 bidders.The total capacity of the four projects is 1,170
9 MW.The projects included in the final shortlist are
10 summarized in Table 1-SD.
11
12
O 13 Project Name (Bidder)Location Capacity (MW)
TB Flats I &II (PacifiCorp)Carbon &Albany Counties,WY 500
14 Cedar Springs (NextEra Energy Converse County,WY 400
15 McFadden Ridge II (PacifiCorp)Carbon &Albany Counties,WY 109
Uinta (Invenergy Wind Uinta County,WY 161
17
18
19 Q.Are any of the winning bids the Company's
20 benchmark resources?
21 A.Yes.The TB Flats I and II and McFadden Ridge
22 II projects are Company-benchmark resources that will be
23 developed under engineer,procure,and construction
24 ("EPC")agreements.The Uinta project is being developed
6"25 by Invenergy Wind Development under BTA.The Cedar
323 Link,Di-Supp -12
Rocky Mountain Power
1 Springs project is being developed by NextEra EnergyO2Acquisitionsasa50-percent BTA and a 50-percent PPA.In
3 total,the final shortlist includes 361 MW that will be
4 developed under BTAs,609 MW of benchmark capacity that
5 will be developed under EPC agreements,and 200 MW that
6 will deliver energy and capacity under a PPA.
7 Q.Please summarize the cost-and-performance
8 attributes of the winning bids.
9 A.The total in-service capital cost for the
10 winning bids is $1.30 billion,down from the $1.37
11 billion assumed in the Company's initial filing.
12 Considering that the winning bids
i
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
324 Link,Di-Supp -12a
Rocky Mountain Power
1 represent an increase in total owned-wind capacity (fromO2justover860MWintheCompany's initial filing to
3 approximately 970 MW),the per-unit capital cost for
4 final shortlist bids is down approximately 17 percent
5 from $1,590/kW to $1,320/kW.
6 In addition to these capital costs,the PPA
7 price that will be paid to NextEra Energy Acquisitions
8 for 50 percent of the output from the Cedar Springs
9 project is expected to add approximately (redacted)to
10 total-system NPC (redacted).These costs are
11 significantly lower than proxy PPA costs that were based
12 off of certain QF projects that were included in the
13 Company's initial filing,which were assumed to add
14 (redacted)to total-system NPC beginning 2022,rising to
15 (redacted)by the end of 2041.This proxy QF project,
16 which requires interconnection facilities beyond the
17 Aeolus-to-Bridger/Anticline transmission line that cannot
18 be built until 2024,is no longer included in the
19 Company's economic analysis of the Combined Projects.
20 In aggregate,the winning bids are expected to
21 operate at a capacity-weighted average-annual capacity
22 factor of 40.3 percent.
23 The in-service cost for network upgrades
24 required to interconnect the final shortlist projects
25 total (redacted),and the cost to build the Aeolus-
325 Link,Di-Supp -13
Rocky Mountain Power
1 to-Bridger/Anticline transmission line remains at
2 (redacted).The expected cost-and-performance attributes
3 for the winning bids and the Transmission Project is
4 summarized in more detail in Confidential Exhibit No.37.
5 Q.How did the Company verify the forecasted
6 capacity factors in its review of bids during the 2017R
7 RFP?
8 A.The Company retained an independent third-party
9 expert,Sapere Consulting,to
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
326 Link,Di-Supp -13a
Rocky Mountain Power
1 evaluate the capacity factors proposed for each bid
2 selected to the initial shortlist.Sapere Consulting's
3 report is attached as Confidential Exhibit No.38.
4 Q.Did the Company adjust any of the performance
5 data for bids included in the initial shortlist based on
6 the report prepared by Sapere Consulting?
7 A.Yes.Consistent with recommendations from
8 Sapere Consulting,the net capacity factor for the
9 (redacted)bids were assessed at 92 percent of the net
10 capacity factor proposed by (redacted).No adjustments
11 were applied to any of the other bids.
12 Q.As part of the 2017R RFP process,did the
13 Company perform any preliminary viability assessments for
14 the projects included in the final shortlist?
15 A.Yes.The Company reviewed each project's place
16 in the transmission interconnection queue and how each
17 project will qualify for federal PTCs.The Company also
18 reviewed bid materials to evaluate site control,progress
19 in collecting avian data,and permitting timelines.All
20 of the projects have either initiated or received system
21 impact studies and are expected to be able to execute
22 interconnection agreements that support the proposed
23 commercial operation dates.All of the projects will
24 qualify for the full value of PTCs by having secured
25 safe-harbor equipment and by meeting continuity-of-
327 Link,Di-Supp -14
Rocky Mountain Power
1 construction requirements,as described in Ms.Nikki L.
2 Kobliha's testimony,by coming online by the end of 2020.
3 All of the final shortlist projects have demonstrated
4 they have site control,have reasonable permitting
5 timelines that will allow the projects to be place in
6 service by the end of 2020 and have initiated collection
7 of avian data.
8 Q.What is the status of the 2017S RFP?
9 A.The Company received initial bids for new solar
10 resources on December 11,2017.On
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
328 Link,Di-Supp -14a
Rocky Mountain Power
1 January 8,2018,PacifiCorp established an initial
2 shortlist,considering both price and non-price scoring
3 elements,which was subsequently submitted to the Solar
4 RFP IE for review.As was the case with the 2017R RFP,
5 the market response to the 2017S RFP was robust.The
6 Company received solar resource proposals from 31 bidders
7 offering 109 bid alternatives for 46 solar projects.In
8 aggregate,6,496 MW of new solar resource capacity was
9 bid into the 2017S RFP.After completing its bid-
10 eligibility screening,a process that ensures all bids
11 satisfy minimum-bid requirements that are specified in
12 the 2017S RFP,the Company disqualified 32 bid
13 alternatives,which equates to 3,039 MW of new solar
14 resource capacity.
15 Q.Did the Company review those bid alternatives
16 that did not meet minimum-bid requirements with the Solar
17 RFP IE?
18 A.Yes.The Solar RFP IE reviewed the Company's
19 minimum-eligibility criteria and determined that these
20 criteria are consistent with other renewable resource
21 RFPs.The Solar RFP IE also reviewed the specific bid
22 alternatives that were disqualified,and in all
23 instances,found that the disqualified bids clearly did
24 not meet the minimum-eligibility criteria listed in the
25 RFP.
329 Link,Di-Supp -15
Rocky Mountain Power
1 Q.Has the Solar RFP IE commented on any otherO2elementsoftheon-going RFP process?
3 A.Yes.On January 10,2018,the Solar RFP IE
4 submitted its first status report,where it concluded
5 that the 2017S RFP documents are clear and the 2017S RFP
6 has been conducted in a clear and transparent manner.
7 Q.Please summarize the bids selected to the
8 initial shortlist from the 2017S RFP.
9 A.The 2017S RFP initial shortlist includes PPAs
10 bids from 10 projects proposed by seven
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
330 Link,Di-Supp -15a
Rocky Mountain Power
1 bidders totaling 1,629 MW.The majority of the projects
2 (1,414 MW)are located in Utah,and the remaining initial
3 shortlist bids are located in Oregon (114 MW)and
4 Washington (100 MW).All of the bids on the 2017S RFP
5 initial shortlist have proposed PPAs with commercial
6 operation dates ranging between November 2020 and January
7 2021-approximately one year before the initial ramp down
8 in investment-tax credits.
9 Q.Has the Company determined whether it will
10 pursue any bids from the 2017S RFP?
11 A.No.The Company continues to evaluate potential
12 bids in the 2017S RFP and has not yet established a final
13 shortlist.There are several outstanding milestones that
14 have to be met before establishing a final shortlist.
15 Under the 2017S RFP schedule,the Solar RFP IE will
16 complete its review of the initial shortlist no later
17 than January 29,2018,and then bidders will be asked to
18 submit best-and-final pricing no later than February 5,
19 2018.Once best-and-final pricing is received,the
20 Company plans to identify a final shortlist by mid-March
21 2018.
22 Q.Has the Company analyzed how the potential
23 selection of bids from the 2017S RFP might affect the
24 economic analysis of the 2017R RFP final shortlist?
25 A.Yes.Using cost-and-performance data from the
331 Link,Di-Supp -16
Rocky Mountain Power
1 bids submitted into the 2017S RFP,the Company has
2 analyzed how the potential selection of these bids would
3 impact the economic analysis of the winning bids from the
4 2017R RFP.I describe this sensitivity analysis later in
5 my testimony.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
332 Link,Di-Supp -16a
Rocky Mountain Power
1 UPDATED ECONOMIC ANALYSISO2Q.What assumptions did the Company update before
3 refreshing its economic analysis of the Combined
4 Projects?
5 A.The models were updated to reflect:(1)
6 cost-and-performance assumptions for the Wind Projects
7 consistent with the winning bids selected to the 2017R
8 RFP final shortlist as summarized earlier in my
9 testimony;(2)current load-forecast projections;(3)
10 current price-policy scenario assumptions;and (4)recent
11 changes in federal tax rate for corporations.
12 Q.Please describe the updated
13 cost-and-performance estimates for the Wind Projects.
14 A.The updated economic analysis includes the
15 capital costs associated with the winning bids,the costs
16 associated with the Cedar Springs PPA,and the updated
17 net capacity factors,as described above.The updated
18 economic analysis also captures terminal-value benefits
19 from BTA and EPC-benchmark bids,where the Company
20 retains control of the site at the end of the asset life.
21 These benefits were considered in the 2017R RFP
22 bid-selection process,consistent with the bid-evaluation
23 methodology described in the RFP,and therefore,they are
24 applied in the updated economic analysis.
25 Q.What is captured by the terminal value applied
333 Link,Di-Supp -17
Rocky Mountain Power
1 to BTA and EPC-benchmark bids?O 2 A.When a wind asset reaches the end of its life
3 (assumed to be 30 years),equipment associated with the
4 wind asset itself has been fully depreciated.However,
5 transmission assets required to interconnect the wind
6 facility have a longer life (assumed to be 62 years).At
7 the time the wind asset reaches the end of its life,the
8 transmission assets required for interconnection have
9 approximately 32 years of additional life remaining.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
334 Link,Di-Supp -17a
Rocky Mountain Power
1 With an owned-wind facility where the Company
2 retains control of the site,whether developed as a BTA
3 or an EPC-benchmark,that site can be redeveloped using
4 existing transmission assets that have not been fully
5 depreciated.Consequently,relative to the future
6 development of a new greenfield wind project,the
7 redevelopment of an existing site limits incremental
8 transmission interconnection costs.Similarly,with an
9 owned facility,an existing site can be redeveloped with
10 limited incremental project-development costs,thereby
11 reducing the cost to acquire development rights relative
12 to a new site.These terminal-value benefits are not
13 applicable to a PPA bid,where a third-party retains
14 control of the site.
15 Q.Please describe the new load forecast
16 assumptions included in the updated economic analysis.
17 A.The load forecast used in the economic analysis
18 summarized in my direct testimony is the same load
19 forecast used in PacifiCorp's 2017 IRP.This 2017 IRP
20 load forecast was finalized in December 2016.The updated
21 economic analysis uses the Company's new load forecast
22 completed in the summer of 2017,after the Company made
23 its initial filing.
24 Figure 1-SD compares the load forecast from the
25 2017 IRP used in my original economic analysis to the new
335 Link,Di-Supp -18
Rocky Mountain Power
1 load forecast.The updated system energy forecast is down
2 by 2.2 percent in 2021 and down by 6.3 percent in 2036
3 relative to the 2017 IRP forecast.The updated coincident
4 summer peak forecast is down by 4.1 percent in 2021 and
5 down by 7.2 percent in 2036 relative to the 2017 IRP
6 forecast.
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
336 Link,Di-Supp -18a
Rocky Mountain Power
lib 21
3 Figure 1-SD.Comparison of the 2017 IRP and Updated Load Forecast Assumptions
4 Energy (GWh)Summer Coincident Peak (MW)
80,000 14,000
5 70,000 ----12,000 ga....-
60,000 10,ooo ------"'~E
50,0006 BAN40,000
30,000 6,000
7 2o.ooo 4,000
10,000 -2,000
9 ----2017 IRP --SupplementalDirect ----2017 IRP -Supplemental Direct
10
11
12 Changes in the load forecast are primarily
13 driven by:(1)a reduction in Utah and Wyoming industrial
14 loads principally due to reduced usage projections for a
15 number of large customers;(2)increases in the growth of
-16 customer generation from 2017 to 2018,contributing to
17 reductions in Utah residential customer usage;and (3)
18 updated appliance saturation and efficiency assumptions
19 with refinements to miscellaneous device sales data
20 (i.e.,televisions,pool heaters,personal computers,and
21 other plug-in devices),contributing to reductions in
22 Utah residential customer usage.
23 Q.Please describe the new price-policy
24 assumptions included in the updated economic analysis.
25 A.In my direct testimony,I described nine
337 Link,Di-Supp -19
Rocky Mountain Power
1 price-policy scenarios,developed by pairing threeO2natural-gas price forecasts (low,medium,and high)with
3 three CO2 price forecasts (Zero,medium,and high).The
4 medium natural-gas price assumptions were derived from
5 the Company's official forward price curve ("OFPC").In
6 the economic analysis summarized in my direct testimony,
7 the Company used its April 26,2017 OFPC.
8 The Company's most recent OFPC is dated
9 December 30,2017,which reflects more current market
10 forwards and an updated forecast from (redacted).Figure
11 2-SD
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
338 Link,Di-Supp -19a
Rocky Mountain Power
1 compares Henry Hub natural-gas prices from the April 26,O 2 2017 OFPC,as used to support the economic analysis in my
3 direct testimony,with Henry Hub natural-gas prices from
4 the updated December 30,2017 OFPC.Over the period 2018
5 through 2036 and using the most current discount rate,
6 the nominal levelized price for Henry Hub natural-gas
7 prices has decreased by approximately three percent from
8 $4.06/MMBtu to $3.94/MMBtu.
9
10 Figure 2-SD.Comparison of the April 2017 and December 2017 OFPC Henry Hub
Natural Gas Price Forecasts
11
12 I
$713
$6
14
15 $4 .
17 $2
$118
$0
o o o o o o o o o o o o o o o o o o o
20
Med Gas (Apr 2017 OFPC)---Med Gas (Dec 2017 OFPC)
21 |
22
23
24 The updated OFPC reflects market forwards as of
25 December 30,2017 over the period January 2018 through
339 Link,Di-Supp -20
Rocky Mountain Power
1 January 2024.The decrease in levelized prices between
2 the updated OFPC and the April OFPC used in the Company's
3 original economic analysis is primarily driven by a
4 reduction in market forwards.Prices in the updated
5 market fundamentals forecast from (redacted),which are
6 used exclusively in the OFPC beyond January 2025,track
7 closely with those assumed in the April 2017 OFPC.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
340 Link,Di-Supp -20a
Rocky Mountain Power
1 The Company continues to blend market forwards from month
2 61 (February 2023)through month 72 (January 2024)with
3 the fundamentals-based forecast from month 85 (February
4 2025)through month 96 (January 2026)to establish prices
5 in month 73 (February 2024)through month 84 (January
6 2025).
7 Q.Did the Company update the low and high
8 natural-gas price scenarios used in the updated economic
9 analysis?
10 A.Yes.Consistent with the Company's approach to
11 develop low and high natural-gas price scenarios used in
12 the original economic analysis,low and high natural-gas
13 price assumptions were updated after reviewing the range
14 in more recent forecasts developed by (redacted),
15 (redacted)and the U.S.Department of Energy's Energy
16 Information Administration.Exhibit No.39 shows the
17 range in natural-gas price assumptions from these
18 third-party forecasts relative to those adopted for the
19 price-policy scenarios in the Company's updated economic
20 analysis of the Combined Projects.
21 Figure 3-SD shows the range between the low and
22 high natural-gas price scenarios used in the Company's
23 original economic analysis alongside the updated low and
24 high natural-gas price assumptions.Nominal levelized
25 prices in the low and high scenarios are $2.95/MMBtu
341 Link,Di-Supp -21
Rocky Mountain Power
1 (down by approximately seven percent)and $5.60/MMBtu
2 (down by approximately four percent),respectively.
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
342 Link,Di-Supp -21a
Rocky Mountain Power
21
Figure 3-SD.Updated Low and High Natural-Gas Price Assumptions
3
$12
4
10 $0
o o o o o o e o o o o o o o o o o o o
12 ----Range (Direct)--UpdatedLowGas -+-UpdatedBigh Gas
13
14
15 Q.Did the Company update its CO2 price scenarios
16 used in its updated economic analysis?
17 A.Yes.As with natural-gas price assumptions and
18 consistent with the Company's approach to develop low and
19 high CO2 price scenarios used in the original economic
20 analysis,low and high CO2 price assumptions were updated
21 after reviewing the range in more recent forecasts
22 developed by (redacted)and (redacted).To bracket the
23 low end of potential-policy outcomes,the Company
24 continues to assume there are no future policies adopted
25 that would require incremental costs to achieve emission
343 Link,Di-Supp -22RockyMountainPower
1 reductions in the electric sector.For this scenario,the
2 assumed CO2 price is zero.
3 Figure 4-SD shows the range between the medium
4 and high CO2 price scenarios used in the Company's
5 original economic analysis alongside the updated medium
6 and high CO2 price assumptions.The updated medium and
7 high CO2 price assumptions are
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
344 Link,Di-Supp -22a
Rocky Mountain Power
1 lower and start later relative to the assumptions
2 summarized in my direct testimony.Updated CO2 prices in
3 the medium scenario begin in 2030 (five years later)at
4 $4.49/ton and rise to $7.95/ton by 2036.Updated prices
5 in the high scenario begin in 2026 (one year later)at
6 $3.62/ton,rise to $16.55/ton by 2030,and reach
7 $19.23/ton by 2036.
8
9
Figure 4-SD.Updated Medium and High CO2 Price Assumptions
10
11 $45
12 $40
$35 -
13 $30
14 g $25
15 Ë$20
$15
16 $10
17 $5
$0
o o o o o o o o o o o o o o o o o o o
19
2 0 ----Range(Direct)---Updated Medium CO2 -e-Updated High CO2
21
22
23 Q.Please describe the updated federal tax rate
24 for corporations that was included in the updated
25 economic analysis of the Combined Projects.
345 Link,Di-Supp -23
Rocky Mountain Power
1 A.The Company's updated analysis assumes a 21
2 percent federal income tax rate.Based on an assumed net
3 state income tax rate of 4.54 percent,the effective
4 combined federal and state income tax rate used in the
5 updated analysis is 24.587 percent.
6 Q.Please describe how the effective combined
7 federal and state income tax rate assumption is applied
8 in the SO model and PaR in the updated economic analysis.
9 A.The effective combined federal and state income
10 tax rate affects the Company's post-
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
346 Link,Di-Supp -23aRockyMountainPower
1 tax weighted average cost of capital ("post-tax WACC"),
2 which is used as the discount rate in the SO model and
3 PaR.With the changes in tax law,the Company's discount
4 rate has been updated from 6.57 percent to 6.91 percent.
5 The modified income tax rate also affects the
6 capital revenue requirement for all new resource options
7 available for selection in the SO model,including the
8 selection of bids from the 2017R RFP.As described in my
9 direct testimony,capital revenue requirement is
10 levelized in the SO and PaR models to avoid potential
11 distortions in the economic analysis of capital-intensive
12 assets that have different lives and in-service dates.
13 This is achieved through annual capital recovery factors,
14 which are expressed as a percentage of the initial
15 capital investment for any given resource alternative in
16 any given year.Capital recovery factors,which are based
17 on the revenue requirement for specific types of assets,
18 are differentiated by each asset's assumed life,
19 book-depreciation rates,and tax-depreciation rates.
20 Because capital revenue requirement accounts for the
21 impact of income taxes on rate-based assets,the capital
22 recovery factors applied to new resource costs in the SO
23 model were updated for each of the Company's system
24 simulations.
25 Finally,the updated income tax rate affects
347 Link,Di-Supp -24
Rocky Mountain Power
1 the tax gross-up of all PTC-eligible resources.As notedO2inmydirecttestimony,the current value of federal PTCs
3 is $24/MWh,which equates to a $38.68/MWh reduction in
4 revenue requirement assuming an effective combined
5 federal and state income tax rate of 37.95 percent.The
6 updated combined federal and state income tax rate
7 reduces the revenue requirement associated with federal
8 PTCs from $38.68/MWh to $31.82/MWh,adjusted for
9 inflation over time.The impact of the updated income tax
10 rate assumptions were applied to all
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
348 Link,Di-Supp -24a
Rocky Mountain Power
1 PTC-eligible resource alternatives available in the SOO2model.
3 Q.How were these assumption updates captured in
4 the updated economic analysis of the Combined Projects?
5 A.The Company updated the SO model and PaR to
6 reflect these updated assumptions.As was done in the
7 original analysis summarized in my direct testimony,
8 these models were used to calculate the PVRR(d)between a
9 simulation with and without the Combined Projects after
10 applying the modeling updates.These simulations continue
11 to cover a forecast horizon out through 2036.The Company
12 also updated its calculation of the PVRR(d)from the
13 change in nominal revenue requirement due to the Combined
14 Projects through 2050.
15 Q.In addition to the assumption updates described
16 above,did the Company change how it applied federal PTC
17 benefits in its system modeling using the SO model and
18 PaR configured to forecast system costs through 2036?
19 A.Yes.When establishing the 2017R RFP final
20 shortlist,the Company applied PTC benefits for
21 applicable bids (BTAs and benchmark-EPC bids)on a
22 nominal basis rather than on a levelized basis.This
23 approach better reflects how the federal PTC benefits for
24 these bids will flow through to customers and aligns the
25 treatment of federal PTC benefits in the system modeling
349 Link,Di-Supp -25
Rocky Mountain Power
1 results extending out through 2036 with the nominal
2 revenue requirement results extending out through 2050.
3 It also ensures the 2017R RFP bid selections from the SO
4 model more accurately reflect the difference in how BTA
5 and benchmark-EPC bids are expected to impact customer
6 rates.
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
350 Link,Di-Supp -25a
Rocky Mountain Power
1 Q.Did the Company continue to apply revenue
2 requirement associated with capital costs on a levelized
3 basis in its system modeling using the SO model and PaR
4 configured to forecast system costs through 2036?
5 A.Yes.When setting rates,revenue requirement
6 from capital costs is depreciated over the book life of
7 the asset,effectively spreading the cost of capital
8 investments over the life of the asset.Because revenue
9 requirement from capital projects is spread over the life
10 of the asset in rates,these costs continue to be treated
11 as a levelized cost in the SO model and PaR simulations.
12 As was done in the Company's original economic analysis
13 to estimate the nominal revenue requirement impacts from
14 the Combined Projects,revenue requirement from capital
15 associated with the Combined Projects is treated as a
16 nominal cost when the results are extrapolated out
17 through 2050.
18 UPDATED SYSTEM MODELING PRICE-POLICY RESULTS
19 Q.Please summarize the updated PVRR(d)results
20 calculated from the SO model and PaR through 2036.
21 A.Table 2-SD summarizes the updated PVRR(d)
22 results for each price-policy scenario.The PVRR(d)
23 between cases with and without the Combined Projects,
24 reflecting winning bids from the 2017R RFP,are shown for
25 the SO model and for PaR,which was used to calculate
351 Link,Di-Supp -26
Rocky Mountain Power
1 both the stochastic-mean PVRR (d)and the risk-adjusted
2 PVRR(d).The data used to calculate the PVRR(d)results
3 shown in the table are provided as Exhibit No.40.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
352 Link,Di-Supp -26a
Rocky Mountain Power
2
3 CORRECTED Table 2-SD Updated SO Model and PaR PVRR(d)
(Benefit)/Cost of the Combined Projects ($million)
4
5
6
Low Gas,Zero CO2 $145 $126 $131
7
Low Gas,Medium CO2 $186 $146 $152
8 Low Gas,Hi CO2 $297)$280 ($294
9 MediumGas,ZeroCO2 $306 $268 $280
10 Medium Gas,Medium CO2 ($343 ($333 $349
11 .Medium Gas,Hi CO2 $430 $409 ($428
12 Hi Gas,Zero CO2 $619 ($531 ($557
13 Hi Gas,Medium CO2 $636 ($561 $588
14 Hi Gas,Hi CO2 $696 $627 $658
15
16
17 Over a 20-year period,the Combined Projects
18 reduce customer costs in all nine price-policy scenarios.
19 This outcome is consistent in both the SO model and PaR
20 results.Under the central price-policy scenario,
21 assuming medium natural-gas prices and medium CO2 prices,
22 the PVRR (d)net benefits range between $333 million,when
23 derived from PaR stochastic-mean results,and $349
24 million,when derived from PaR risk-adjusted results.
25 Q.What trends do you observe in the modelingO
353 Link,Di-Supp -27
Rocky Mountain Power
1 results across the different price policy scenarios?
2 A.Projected system net benefits increase with
3 higher natural-gas price assumptions,and similarly,
4 increase with higher CO2 price assumptions.Conversely,
5 system net benefits decline when low natural-gas prices
6 and low CO2 prices are assumed.This trend holds
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
354 Link,Di-Supp -27a
Rocky Mountain Power
1 true when looking at the results from the two simulations
2 used to calculate the PVRR(d)for all nine of the
3 price-policy scenarios.Importantly,both models continue
4 to show that the net benefits from the Combined Projects
5 are robust across a range of price-policy assumptions.
6 Q.Did you update the potential upside to these
7 PVRR(d)results associated with renewable energy credit
8 ("REC")revenues?
9 A.Yes.Consistent with my direct testimony,the
10 PVRR(d)results presented in Table 2-SD do not reflect
11 the potential value of RECs generated by the incremental
12 energy output from the Wind Projects.Accounting for the
13 updated performance estimates discussed above,customer
14 benefits for all price-policy scenarios would improve by
15 approximately $31 million for every dollar assigned to
16 the incremental RECs that will be generated from the Wind
17 Projects through 2036 (up from $26 million in my original
18 analysis).Quantifying the potential upside associated
19 with incremental REC revenues is simply intended to
20 simply communicate that the net benefits from the
21 Combined Projects could improve if the incremental RECs
22 can be monetized in the market.
23 Q.Is there additional upside to the net benefits
24 shown in Table 2-SD?
25 A.Yes.Before receiving bids submitted into the
355 Link,Di-Supp -28
Rocky Mountain Power
1 2017R RFP,the Company locked down with the IEs default
2 operations and maintenance ("O&M")assumptions that were
3 applied to BTA and benchmark-EPC bids beyond proposed O&M
4 agreement periods.These assumptions were based on the
5 Company's experience in operating and maintaining the
6 existing fleet of owned-wind facilities and were used in
7 the bid-selection process and the economic analysis
8 summarized above.
9 Since construction of the Company's existing
10 fleet of wind facilities,wind
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
356 Link,Di-Supp -28a
Rocky Mountain Power
1 technology has evolved and turbine sizes have increased.
2 With the increase in turbine size,O&M costs are expected
3 to be lower than actual experience because there are
4 fewer turbines on a given site.The range in cost savings
5 is expected to vary between 31 to 42 percent of certain
6 O&M cost elements (i.e.,materials and O&M contract
7 costs).Two of the winning bids-Invenergy Wind
8 Development's Uinta project and PacifiCorp's TB Flats I
9 and II project-will use larger-turbine equipment for a
10 portion of the wind turbines on each site.If the O&M
11 cost elements applicable to the larger-turbine equipment
12 are reduced by 42 percent,which is equivalent to an
13 approximately 18 percent reduction in total O&M costs,
14 beyond the proposed O&M agreement period,customer
15 benefits calculated through 2036 for all price-policy
16 scenarios would improve by approximately $13 million.
17 UPDATED REVENUE REQUIREMENT MODELING PRICE-POLICY RESULTS
18 Q.Did the Company update its revenue requirement
19 modeling among different price-policy scenarios to
20 reflect the modeling updates described above?
21 A.Yes.Using the same annual revenue requirement
22 modeling methodology described in my direct testimony,
23 the Company updated its forecast of the change in nominal
24 annual revenue requirement due to the Combined Projects,
25 incorporating the modeling updates described earlier my
357 Link,Di-Supp -29
Rocky Mountain Power
1 testimony.O 2 Q.Please summarize the updated PVRR(d)results
3 calculated from the change in annual revenue requirement
4 through 2050.
5 A.Table 3-SD summarizes the updated PVRR(d)
6 results for each price-policy scenario calculated off of
7 the change in annual nominal revenue requirement through
8 2050.The annual data over the period 2017 through 2050
9 that was used to calculate the PVRR(d)
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
358 Link,Di-Supp -29a
Rocky Mountain Power
1 results shown in the table are provided as Exhibit No 41.O 2 CORRECTED Table 3-SD.Updated Nominal Revenue RequirementPVRR(d)(Benefit)/Cost of the Combined Projects ($million)
3
4
5
6 Low Gas,Zero CO2 $195
7 Low Gas,Medium CO2 $159
8
Low Gas,Hi h CO2 $79
Medium Gas,Zero CO2 ($34
9
Medium Gas,Medium CO2 $151
10 Medium Gas,Hi CO2 $275
11 Hi Gas,Zero CO2 $411
12 Hi h Gas,Medium CO2 ($453
O 13 Hi Gas,H CO2 $559
14 When system costs and benefits from the
15 Combined Projects are extended out through 2050,covering
16 the full depreciable life of the owned-wind projects
17 included in the 2017R RFP final shortlist,the Combined
18 Projects reduce customer costs in seven out of nine
19 price-policy scenarios.Customer benefits,range from $34
20 million in the medium natural gas,zero CO2 scenario to
21 $559 million in the high natural gas,high CO2 scenario.
22 Under the central price-policy scenario,assuming medium
23 natural-gas prices and medium CO2 prices,the PVRR(d)
24 benefits of the Combined Projects are $151 million.The
25 Combined Projects provide significant customer benefits
359 .Link,Di-Supp -30
Rocky Mountain Power
1 in all price-policy scenarios,and the net benefits areO2unfavorableonlywhenlownatural-gas prices are paired
3 with zero or medium CO2 prices.These results show that
4 upside benefits far outweigh downside risks.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
360 Link,Di-Supp -30a
Rocky Mountain Power
1 Q.Is there additional potential upside to theseO2PVRR(d)results associated with REC revenues?
3 A.Yes.Consistent with my direct testimony,the
4 PVRR(d)results presented in Table 3-SD do not reflect
5 the potential value of RECs generated by the incremental
6 energy output from the Wind Projects.Accounting for the
7 updated performance,customer benefits for all price-
8 policy scenarios would improve by approximately $39
9 million for every dollar assigned to the incremental RECs
10 that will be generated from the Wind Projects through
11 2050 (up from $34 million in my original analysis).
12 Q.Is there additional potential upside to these
13 PVRR(d)results associated with reduced O&M costs?
14 A.Yes.As discussed above,the Company
15 anticipates O&M costs for those projects that will
16 install larger turbine equipment to be lower than what
17 has been reflected in the updated economic analysis.
18 Accounting for these cost savings,customer benefits for
19 all price-policy scenarios would improve by approximately
20 $22 million when calculated from projected operating
21 costs through 2050.
22 Q.Please describe the change in annual nominal
23 revenue requirement from the Combined Projects.
24 A.Figure 5-SD shows the updated change in nominal
25 revenue requirement due to the Combined Projects for the
361 Link,Di-Supp -31RockyMountainPower
1 medium natural gas,medium CO2 price-policy scenario on a
2 total-system basis.These results are shown alongside the
3 same results from the original economic analysis
4 summarized in my direct testimony.The change in nominal
5 revenue requirement shown in the figure reflects updated
6 costs,including capital revenue requirement (i.e.,
7 depreciation,return,income taxes,and property taxes),
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
362 Link,Di-Supp -31a
Rocky Mountain Power
1 O&M expenses,the Wyoming wind-production tax,and PTCs.
2 The project costs are netted against updated system
3 impacts from the Combined Projects,reflecting the change
4 in NPC,emissions,non-NPC variable costs,and system
5 fixed costs that are affected by,but not directly
6 associated with,the Combined Projects.
7
8 CORRECTED Figure 5-SD Updated Total-System Annual Revenue Requirement
With the Combined Projects (Benefit)/Cost ($million)
9
$8010$60
$4011$20
12
($20)
13 ($40)
($66)
14 (880)
($100)
15 ($120)
16
Updated ficonomic Analysis ---Direct Testimony
18
19
20 The data shown in this figure for the updated
21 economic analysis have the same basic profile as the data
22 from the original economic analysis summarized in my
23 direct testimony.This profile shows that despite a
24 reduction in PTC benefits associated with changes in
O 25 federal tax law,the reduced costs from winning bids from
363 Link,Di-Supp -32RockyMountainPower
1 the 2017R RFP continue to generate substantial near-term
2 customer benefits,reduce the magnitude and shorten the
3 duration over which costs increase after federal PTCs for
4 new wind resources expire,and continue to contribute to
5 customer benefits over the long-term.
6 The year-on-year reduction in net benefits from
7 2036 to 2037 is driven by the Company's conservative
8 approach to extrapolate benefits from 2037 through 2050
9 based on modeled results from the 2028 through 2036
10 timeframe.This leads to an
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
364 Link,Di-Supp -32a
Rocky Mountain Power
1 abrupt reduction in the benefits in 2037,and a
2 subsequent year-on-year reduction to net benefits,which
3 breaks from the trend observed in the model results over
4 the 2033 to 2036 time frame.This extrapolation
5 methodology is conservative because it results in project
6 benefits not matching the levels observed in the model
7 results for 2036 until 2044.
8 SOLAR SENSITIVITY
9 Q.Please describe the sensitivity studies that
10 analyzed the impact of the solar bids received in the
11 2017S RFP on the economics of the Combined Projects.
12 A.The Company's solar sensitivity analysis used
13 the SO model and PaR simulations to determine the PVRR(d)
14 based on two model runs-one with solar PPA bids and the
15 Combined Projects and one with solar PPA bids but without
16 the Combined Projects.In the sensitivity where PPA bids
17 are pursued with the Combined Projects,the SO model
18 continues to choose the winning bids included in the
19 2017R RFP final shortlist as part of the least-cost bid
20 portfolio.Depending upon the price-policy scenario,
21 between 1,118 MW and 1,315 MW of solar PPA bids,from new
22 projects all located in Utah,are added to the system by
223the SO modWhat
were the results of the solar sensitivity
25 where solar PPA bids are assumed to be pursued in lieu of
365 Link,Di-Supp -33
Rocky Mountain Power
1 the Combined Projects?
2 A.Table 4-SD summarizes PVRR(d)results for the
3 solar sensitivity where solar PPA bids are assumed to be
4 pursued without any investments in the Combined Projects.
5 This sensitivity was developed using SO model and PaR
6 simulations through 2036 for the medium natural gas,
7 medium CO2 and the low natural gas,zero CO2 price-policy
8 scenarios.The results are shown alongside the benchmark
9 study in which the Combined
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
366 Link,Di-Supp -33a
Rocky Mountain Power
1 Projects were evaluated without solar PPA bids.
2
3 CORRECTED Table 4-SD Solar Sensitivitywith Solar PPAs Included
in lieu of the Combined Projects (Benefit)/Cost ($million)
4
Sensitivity Benchmark Change in
5 PVRR(d)PVRR(d)PVRR(d)
6 Medium Gas,Medium CO2
SO Model $334 $343 $9
7 PaR Stochastic Mean $222 $333 $111
8 PaR Risk Adjusted ($233)($349)$116
9 Low Gas,Zero CO2
SO Model $206 $145 ($6110PaRStochasticMean$141 $126 $15
11 PaR Risk Adjusted ($148)($131)($17)
12
13 In the medium natural gas,medium CO2
14 price-policy scenario,a portfolio with the Combined
15 Projects delivers greater customer benefits relative to a
16 portfolio that adds solar PPA bids without the Combined
17 Projects.Customer benefits are greater when the resource
18 portfolio includes the Combined Projects without solar
19 PPA bids by $116 million in the medium natural gas,
20 medium CO2 price-policy scenario based on the
21 risk-adjusted PaR results.In the low natural gas,zero
22 CO2 price-policy scenario,the portfolio with solar PPA
23 bids and without the Combined Projects has higher net
24 customer benefits relative to a portfolio containing just
25 the Combined Projects.The increase in net benefits in
367 Link,Di-Supp -34RockyMountainPower
1 the solar PPA portfolio is $17 million based on the
2 risk-adjusted PaR results.
3 Q.What were the results of the solar sensitivity
4 where solar PPA bids are pursued with the Combined
5 Projects?
6 A.Table 5-SD summarizes PVRR (d)results for the
7 solar sensitivity where solar PPA bids
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
368 Link,Di-Supp -34a
Rocky Mountain Power
1 are assumed to be pursued along with the proposed
2 investments in the Combined Projects.This sensitivity
3 was developed using SO model and PaR simulations through
4 2036 for the medium natural gas,medium CO2 and the low
5 natural gas,zero CO2 price-policy scenarios.The results
6 are shown alongside the benchmark study in which the
7 Combined Projects were evaluated without solar PPA bids.
8 CORRECTED Table 5-SD Solar Sensitivitywi h Solar PPAs Included
9 With the Combined Projects (Benefit)/ost ($million)
10 Sensitivity Benchmark Change in
11 PVRR(d)PVRR(d)PVRR(d)
Medium Gas,Medium CO2
12
SO Model $602 $343 $259
13 PaR Stochastic Mean $482 $333 $149
14 PaR Risk Adjusted ($504)($349)($155)
15 LowG-as,2%roCO2
16 SO Model $286 $145)$141
PaR Stochastic Mean $217 $126 $9117
PaR Risk Adjusted ($227)($131)($96)
18 -
19 When the solar PPAs are pursued in addition to
20 the Combined Projects,the total benefits increase,but
21 are diluted (i.e.,the aggregate net benefits are less
22 than the sum of the benefits for the cases where Combined
23 Projects or solar PPAs are pursued independently).
24 Q.What conclusions can you draw from these solar
25 sensitivity analyses?
369 Link,Di-Supp -35RockyMountainPower
1 A.These sensitivities demonstrate that should theO2Companychoosetopursuesolarbidsthroughthe2017S
3 RFP,the resulting solar PPAs would not displace the
4 Combined Projects as an alternative means to deliver
5 economic savings for customers.
6 While the sensitivity with a portfolio
7 containing solar PPAs without the
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
370 Link,Di-Supp -35a
Rocky Mountain Power
1 Combined Projects produces a PVRR(d)with net benefits
2 that are slightly higher than a portfolio without the
3 solar PPAs in the low natural-gas,zero CO2 price-policy
4 scenario,both portfolios deliver customer benefits.This
5 sensitivity does not support an alternative resource
6 procurement strategy to pursue solar PPA bids in lieu of
7 the Combined Projects.This would leave the significant
8 benefits from the Combined Projects,which include
9 building a much-needed transmission line,on the table.
10 Importantly,the sensitivity that evaluates the Combined
11 Projects with the solar PPAs produces net benefits that
12 are greater than the net benefits from the Combined
13 Projects without the solar PPAs.This confirms that
14 near-term renewable procurement is not a matter of
15 whether the company should pursue the Combined Projects
16 or the solar PPAs,but whether the company should
17 consider both opportunities.At this time,it is clear
18 that the Combined Projects provide significant net
19 benefits,and that these benefits are not eliminated if
20 the company were to also pursue solar PPA bids through
21 the 2017S RFP.
22 WIND REPOWERING SENSITIVITY
23 Q.Has the Company updated its sensitivity
24 analysis related to the wind repowering project?
25 A.Yes.Based on the updates discussed above,
371 Link,Di-Supp -36
Rocky Mountain Power
1 coupled with the updated cost-and performance-estimates
2 for the wind repowering project,the Company performed a
3 sensitivity that includes the repowered wind facilities
4 assuming they continue to operate within the limits of
5 their large generator interconnection agreements
6 ("LGIAs").
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
372 Link,Di-Supp -36a
Rocky Mountain Power
1 Q.What were the results of the wind-repowering
2 sensitivity?
3 A.Table 6-SD summarizes PVRR(d)results for this
4 wind-repowering sensitivity.This sensitivity was
5 developed using SO model and PaR simulations through 2036
6 for the medium natural gas,medium CQ2 and the low
7 natural gas,zero CO2 price-policy scenarios.The results
8 are shown alongside the benchmark study in which the
9 Combined Projects were evaluated without wind repowering.
10
11 CORRECTED Table 6-SD Wind-Repowering
Sensitivity(Benefit)/Cost ($million)
12
Sensitivity Benchmark Change in
13 PVRR(d)PVRR(d)PVRR(d)
14 Medium Gas,Medium CO2
SO Model $541 $343 ($198
15 PaR Stochastic Mean ($497 $333)($164
16 PaR Risk Adjusted ($520)($349)($171)
17 Low Gas,Zero CO2
SO Model $313 $145 $169
18 PaR Stochastic Mean $277 $126 $152
19 PaR Risk Ad usted $290 $131 ($159
20
21 In the wind-repowering sensitivity,customer
22 benefits increase significantly when the wind repowering
-23 project is implemented with the Combined Projects in both
24 the medium natural gas,medium CO2 and the low natural
25 gas,zero CO2 price-policy scenarios.These results
373 Link,Di-Supp -37
Rocky Mountain Power
1 demonstrate that customer benefits not only persist,but
2 increase,if both the wind-repowering project and the
3 Combined Projects are completed.
4 Q.Please summarize the conclusion of your
5 supplemental direct testimony.
6 A.The results of the 2017R RFP confirmed that the
7 Combined Projects are the least-cost,
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
374 Link,Di-Supp -37a
Rocky Mountain Power
1 least-risk customer resources.The substantial volume ofO2bidsintothe2017RRFPdrovedowncapitalcosts,thus,
3 allowing the Company to obtain greater generating
4 capacity for lower overall Wind Project capital costs.
5 The Combined Projects show net customer benefits under
6 all scenarios through 2036 and in seven of nine scenarios
7 through 2050.The Company's updated sensitivities further
8 demonstrate that the Combined Projects are not displaced
9 by solar resources that bid into the 2017S RFP and that
10 the Combined Projects remain economic when combined with
11 repowering.
12 Q.Does this conclude your supplemental direct
13 testimony?
14 A.Yes.
15
16
17
18
19
20
21
22
23
24
25
375 Link,Di-Supp -38
Rocky Mountain Power
1 Q.Are you the same Rick T.Link who previously
2 provided testimony in this case on behalf of Rocky
3 Mountain Power,a division of PacifiCorp?
4 A.Yes.
5 PURPOSE AND SUMMARY OF TESTIMONY
6 Q.What is the purpose of your second supplemental
7 direct testimony?
8 A.I summarize the updated results of the 2017R
9 Request for Proposals ("RFP").I also provide updates to
10 the economic analysis that demonstrate increasing
11 customer benefits from the new wind resources ("Wind
12 Projects")and construction of the
13 Aeolus-to-Bridger/Anticline line and network upgrades
14 ("Transmission Projects")(collectively,the "Combined
15 Projects").
16 Q.Please summarize your second supplemental
17 direct testimony.
18 A.The updated 2017R RFP final shortlist replaces
19 the company's McFadden Ridge II benchmark bid with the
20 Ekola Flats benchmark bid.All of the other winning bids
21 included in the original final shortlist remain in the
22 updated final shortlist.The total capacity of the
23 winning bids in the updated final shortlist is 1,311 MW,
24 which includes three of the benchmark facilities (TB
25 Flats I and II,now combined as a single project,and
376 Link,Di-2nd Supp -1
Rocky Mountain Power
1 Ekola Flats),and two new facilities (Cedar Springs and
2 Uinta).Uinta is a build-transfer agreement ("BTA")
3 totaling 161 MW,Cedar Springs is one-half BTA and
4 one-half power-purchase agreement ("PPA"),for a total of
5 400 MW,and TB Flats I and II and Ekola Flats are
6 company-built facilities,totaling 500 MW and 250 MW,
7 respectively.
8 The updated results of the 2017R RFP and the
9 extensive modeling that supports it continue to confirm
10 that the Combined Projects are the least-cost,least-risk
11 path
12 /
13
14 /
15
16 /
17
18
19
20
21
24
25
377 Link,Di-2nd Supp -la
Rocky Mountain Power
1 available to serve the company's customers by meeting
2 both near-term and long-term needs for additional
3 resources.My second supplemental direct testimony
4 explains the following:
5 o The Combined Projects continue to provide net
6 customer benefits under all scenarios studied
7 through 2036,and in seven of the nine
8 scenarios through 2050.
9 o Customer benefits increase to $167 million in
10 the medium case through 2050 (as compared to
11 $151 million in the supplemental direct
12 filing),and range from $357 million to $405
13 million in the medium case through 2036.
14 o The analysis reflects consideration of an
15 interconnection-restudy process,that:1)
16 eliminated certain bids,including the
17 company's McFadden Ridge II benchmark bid,from
18 consideration in the 2017R RFP;and 2)
19 supported an increase to the assumed level of
20 interconnection capacity in the constrained
21 area of PacifiCorp's system in eastern Wyoming.
22 o Sensitivity analysis continues to show
23 substantial benefits of the Combined Projects
24 persist when paired with PacifiCorp's wind
25 repowering project and are not displaced or
378 Link,Di-2nd Supp -2
Rocky Mountain Power
1 reduced when considering the potential
2 procurement of solar PPA bids,updated with
3 best-and-final pricing,submitted into the
4 on-going RFP for solar resources,the 2017S
5 RFP.
6 UPDATED 2017R RFP FINAL SHORTLIST
7 Q.Did the company update the list of winning bids
8 from the 2017R RFP?
9 A.Yes.The company's 109 MW McFadden Ridge II
10 benchmark resource was removed from the final shortlist
11 and replaced with the company's 250 MW Ekola Flats
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
379 Link,Di-2nd Supp -2a
Rocky Mountain Power
1 benchmark resource.All of the other winning bids
2 included in the original final shortlist remain in the
3 updated final shortlist.The total capacity of the
4 winning bids in the updated final shortlist is 1,311 MW.
5 The winning bids included in the updated final shortlist
6 are listed in Table 1-SS.
7
Table 1-SS.Updated 2017R RFP Final Shortlist
8
Project Name (Bidder)Location Capacity (MW)
9
TB Flats I &II (PacifiCorp)Carbon &Albany 500Counties,MY10CedarSprings(NextEra Converse County'400EnergyAcquisitions)WY11
---Ekola Flats (PacifiCorp)Carbon County,WY 250
12 Uinta (Invenergy Wind Uinta County,W 161
Development)O 13
14 The TB Flats I &II and Ekola Flats projects
15 are company-benchmark resources that will be developed
16 under engineer,procure,and construction ("EPC")
17 agreements.The Uinta project is being developed by
18 Invenergy Wind Development under a BTA.The Cedar Springs
19 project is being developed by NextEra Energy Acquisitions
20 as a 50-percent BTA and a 50-percent PPA.In total,the
21 updated final shortlist includes 361 MW that will be
22 developed under BTAs,750 MW of benchmark capacity that
23 will be developed under EPC agreements,and 200 MW that
24 will deliver energy and capacity under a PPA.
25 Q.Please summarize the cost-and-performance
380 Link,Di-2nd Supp -3
Rocky Mountain Power
1 attributes of the winning bids.
2 A.The total in-service capital cost for the
3 winning bids is $1.46 billion.Considering that the
4 winning bids represent an increase in total owned-wind
5 capacity (from just over 860 MW in the company's initial
6 filing to approximately 1,111 MW),the per-unit
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
381 Link,Di-2nd Supp -3a
Rocky Mountain Power
1 capital cost for the updated final shortlist is down
2 approximately 18 percent from $1,590/kW to $1,310/kW.
3 In addition to these capital costs,the PPA
4 price that will be paid to NextEra Energy Acquisitions
5 for 50 percent of the output from the Cedar Springs
6 project is expected to add approximately (redacted)to
7 total-system net power costs ("NPC")(redacted).These
8 costs are significantly lower than proxy PPA costs that
9 were based off of certain qualifying facility ("QF")
10 projects that were included in the company's initial
11 filing,which were assumed to add (redacted)to
12 total-system NPC beginning 2022,rising to (redacted)by
13 the end of 2041.This proxy QF project,which requires
14 interconnection facilities beyond the Aeolus-to-Bridger/
15 Anticline transmission line that cannot be built until
16 2024,is no longer included in the company's economic
17 analysis of the Combined Projects.
18 In aggregate,the winning bids are expected to
19 operate at a capacity-weighted average annual capacity
20 factor of 39.4 percent.
21 The in-service cost for network upgrades
22 required to interconnect the final shortlist projects
23 total (redacted),and the cost to build the Aeolus-
24 to-Bridger/Anticline transmission line remains at
25 (redacted).The expected cost-and-performance attributes
382 Link,Di-2nd Supp -4RockyMountainPower
1 for the winning bids and the Transmission Project is
2 summarized in more detail in Confidential Exhibit No.54.
3 Q.Why was the 2017R RFP final shortlist updated?
4 A.The 2017R RFP final shortlist was updated to
5 account for the results of an interconnection-restudy
6 process.As described in Mr.Rick A.Vail's second
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
383 Link,Di-2nd Supp -4a
Rocky Mountain Power
1 supplemental direct testimony,the company completed an
2 interconnection-restudy process to ensure that
3 interconnection studies reflected the most current
4 long-term transmission plan to construct the Aeolus-
5 to-Bridger/Anticline D.2 segment of the Energy Gateway
6 project by the end of 2020.PacifiCorp transmission
7 restudied,in serial interconnection-queue order,
8 interconnection requests that do not already have an
9 interconnection agreement to determine whether the
10 staging of the Energy Gateway West project would affect
11 the cost or timing of projects whose previous
12 interconnection studies depended on Gateway West in its
13 entirety.Affected projects located in the constrained
14 area of PacifiCorp's transmission system in eastern
15 Wyoming were restudied through the point in the
16 interconnection queue where additional segments of the
17 Energy Gateway project beyond just the Aeolus-to-Bridger/
18 Anticline D.2 segment would be required to interconnect.
19 PacifiCorp transmission posted the restudied
20 system-impact studies ("SISs")on PacifiCorp's open
21 access same-time information system ("OASIS")on January
22 29,2018,as well as certain updated restudied SISs on
23 February 9,2018.
24 Q.How did the interconnection-restudy process
25 affect 2017R RFP winning bid selections?
384 Link,Di-2nd Supp -5
Rocky Mountain Power
1 A.As described by Mr.Vail,the interconnection-O 2 restudy process confirmed that 2017R RFP bids located in
3 eastern Wyoming with an interconnection-queue position
4 greater than Q0712 trigger the need for Energy Gateway
5 South,which is not planned to be placed in service by
6 the end of 2020.Consequently,any bid proposing a
7 project in the constrained area of PacifiCorp's
8 transmission system with an interconnection-queue
9 position greater than Q0712 cannot receive
10 interconnection service and achieve
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
385 Link,Di-2nd Supp -5a
Rocky Mountain Power
1 commercial operation by the end of 2020 as required in
2 the 2017R RFP.This includes the company's McFadden Ridge
3 II benchmark bid that was originally selected to the
4 final shortlist.All other bids originally selected to
5 the final shortlist can secure interconnection service
6 either because they hold an interconnection-queue
7 position that does not require Energy Gateway South
8 (Ekola Flats,TB Flats I and II,and Cedar Springs)or
9 because the project is not located in the constrained
10 area of the company's eastern Wyoming transmission system
11 (Uinta).
12 Q.Were there other findings from the
13 interconnection-restudy process that affected selection
14 of winning bids to the updated 2017R RFP final shortlist?
15 A.Yes.As noted by Mr.Vail,the interconnection-
16 restudy process shows that the Aeolus-to-Bridger/
17 Anticline transmission line will enable interconnection
18 of up to 1,510 MW of new wind capacity within the
19 constrained area of PacifiCorp's transmission system in
20 eastern Wyoming.This is up from the 1,270 MW assumed in
21 the bid-selection process summarized in my supplemental
22 direct testimony.
23 As stated in my supplemental direct testimony,
24 there is a 240 MW QF project with an executed
25 interconnection agreement that does not require
386 Link,Di-2nd Supp -6
Rocky Mountain Power
1 construction of Energy Gateway West and South to
2 accommodate the QF's interconnection.To honor this
3 agreement,the company must reserve sufficient
4 interconnection capacity for this interconnection
5 customer.After setting aside interconnection capacity
6 for this interconnection customer,the interconnection-
7 restudy process shows that the Aeolus-to-Bridger/
8 Anticline transmission line can enable interconnection of
9 up to 1,270 MW of new wind located in the constrained
10 area of PacifiCorp's transmission system in eastern
11 Wyoming.This is up from the 1,030 MW assumed in the
12 bid-selection process
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
387 Link,Di-2nd Supp -6a
Rocky Mountain Power
1 summarized in my supplemental direct testimony.
2 Q.Why did the company not consider the
3 interconnection-queue position of bids when it originally
4 identified bids selected to the final shortlist?
5 A.The company has been aware that it would need
6 to factor interconnection requirements into its
7 evaluation of the 2017R RFP bids since the beginning of
8 the RFP process.Indeed,the company originally included
9 a completed SIS as one of the minimum bid-eligibility
10 requirements.In response,however,to recommendations
11 from the Utah independent evaluator ("IE"),the company
12 agreed to remove the requirement that a bidder have a
13 completed SIS to be eligible to submit a proposal.
14 Q.Did elimination of the SIS requirement benefit
15 the 2017R RFP process?
16 A.Yes.While the removal of the SIS requirement
17 meant that the company could not fully evaluate the
18 relative interconnection requirements of the bids early
19 in the process,it agreed to relax the requirement that
20 bidders have a completed SIS to broaden market
21 participation in the 2017R RFP because bidders could
22 participate without regard to their interconnection queue
23 position.This enhances competition and provides an
24 incentive for bidders to offer low-cost proposals.In
25 addition,the interconnection queue can change over time
388 Link,Di-2nd Supp -7
Rocky Mountain Power
1 as generator-interconnection customers change project
2 details,request commercial operation date extensions or
3 suspensions,or even withdraw from the queue altogether.
4 Had the requirement that bidders have a SIS been
5 retained,the pool of eligible bidders would have been
6 limited based on the then-current snapshot of the
7 interconnection queue,which would have reduced
8 competitive forces that drive least-cost bidding.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
389 Link,Di-2nd Supp -7a
Rocky Mountain Power
1 Q.How did the company establish its updated finalO2shortlistthataccountsforthefindingsfromthe
3 interconnection-restudy process?
4 A.The company produced updated portfolio-
5 development studies using the System Optimizer ("SO")
6 model to create a bid portfolio containing the least-cost
7 combination of viable bids.In choosing the least-cost
8 combination of bids,the SO model was configured to
9 select from all viable bid alternatives,excluding bids
10 located in the constrained area of PacifiCorp's
11 transmission system in eastern Wyoming,that have an
12 interconnection-queue position greater than Q0712.
13 Consistent with the increased interconnection capability
14 identified during the interconnection-restudy process,
15 the SO model was also configured to select up to 1,270 MW
16 of bids located in this area of PacifiCorp's transmission
17 system.The updated portfolio-development studies were
18 developed under two price-policy scenarios-low natural
19 gas,zero CO2 and medium natural gas,medium CO2-
20 Q.Did the company update its price-policy
21 scenario assumptions?
22 A.No.The price-policy scenario assumptions
23 summarized in my supplemental direct testimony remain
24 valid and were not updated for this analysis.
25 Q.Why did the company update its
390 Link,Di-2nd Supp -8
Rocky Mountain Power
1 portfolio-development studies using only the low natural
2 gas,zero CO2 and medium natural gas,medium CO2
3 price-policy assumptions?
4 A.As described in my supplemental direct
5 testimony,the company originally produced least-cost bid
6 portfolios for all nine price-policy scenarios.That
7 analysis identified a bid portfolio that included the
8 original final shortlist of projects plus an additional
9 bid.The additional bid was included in the bid portfolio
10 only in the medium natural gas,
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
391 Link,Di-2nd Supp -8a
Rocky Mountain Power
1 high CO2 price-policy scenario and in the threeO2price-policy scenarios that assume high natural gas price
3 assumptions.The bid portfolio with the incremental bid
4 did not generate favorable net benefits for customers
5 relative to the portfolio containing the original final
6 shortlist of projects when applying low natural gas
7 price-policy assumptions or when applying price-policy
8 assumptions paring medium natural gas prices with zero or
9 medium CO2 prices.Based on these results,the company
10 evaluated bid selections assuming base case (medium
11 natural gas,medium CO2 price)and worst case (low
12 natural gas,zero CO2)price-policy assumptions.
13 Q.Did the company update any bid-cost assumptions
14 when developing its updated portfolio-development
15 studies?
16 A.Yes.The company updated bid-cost assumptions
17 to align interconnection network upgrade costs with those
18 identified in the SISs posted on PacifiCorp's OASIS.The
19 company also updated sales-tax estimates for all bids
20 submitted by (redacted)-replacing the company's sales-tax
21 estimates assumed when establishing the original final
22 shortlist with sales-tax costs supplied by the bidder.
23 Q.What bids were selected by the SO model in the
24 updated portfolio-development studies?
25 A.The SO model selected the same four bids,
392 Link,Di-2nd Supp -9RockyMountainPower
1 included in the company's updated final shortlist as
2 summarized in Table 1-SS,in the low natural gas,zero
3 CO2 and the medium natural gas,medium CO2 price-policy
4 scenarios.
5 Q.Did the company update its economic analysis to
6 account for the updated final shortlist?
7 A.Yes.The economic analysis among all nine
8 price-policy scenarios was refreshed to
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
393 Link,Di-2nd Supp -9a
Rocky Mountain Power
1 reflect those bids selected in the updated 2017R RFPO2finalshortlist.This analysis was updated using the SO
3 model and the Planning and Risk model ("PaR").I describe
4 the company's updated economic analysis later in my
5 testimony.
6 Q.Did the company inform the Utah and Oregon IEs
7 of changes to the 2017R RFP final shortlist resulting
8 from the interconnection-restudy process described above?
9 A.Yes.On January 19,2018,the company discussed
10 the potential impacts of the interconnection-restudy
11 process with the Utah and Oregon IEs.Specifically,the
12 company explained that,although no definitive
13 determinations could be made until restudy process was
14 completed,certain bids with a relatively high
15 interconnection-queue position located in eastern
16 Wyoming,including the company's McFadden Ridge II
17 benchmark,may not be viable.On February 12,2018,after
18 the interconnection-restudy process and bid-selection
19 analysis was completed,the company submitted its updated
20 final shortlist recommendation to the Utah and Oregon
21 IEs.
22 Q.Did the Utah and Oregon IEs request any
23 additional sensitivity studies as the company was
24 finalizing its updated final shortlist recommendation?
25 A.Yes.The Utah and Oregon IEs requested a
394 Link,Di-2nd Supp -10
Rocky Mountain Power
1 sensitivity to assess how projected net benefits from theO2updatedfinalshortlistwouldbeaffectedif
3 (redacted)///////////////////////////////////////////.
4 The Utah and Oregon IEs requested that this sensitivity
5 be developed using the SO model with medium natural gas,
6 medium CO2 price-policy scenario assumptions.
7 Q.What were the findings from this IE
8 sensitivity?
9 A.The present-value revenue requirement
10 differential ("PVRR(d)")based on SO model
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
395 Link,Di-2nd Supp -10a
Rocky Mountain Power
1 results through 2036 under the IE sensitivity showed a
2 $25 million reduction in net customer benefits if
3 (redacted)///////////////////////////////////////////////
4 ///////////.The IE sensitivity also showed customer
5 costs would increase over both the near term and long
6 term if (redacted)/////////////////////////////////
8 Q.Did the company change its updated 2017R RFP
9 final shortlist based on the IE sensitivity?
10 A.No.
11 Q.Does the Utah IE report on the 2017R RFP final
12 shortlist,dated February 15,2018,support the final
13 shortlist?
14 A.Yes.The IE concluded that the Company
15 conducted the 2017R RFP in a consistent and fair manner
16 and agreed that the Company's final shortlist was
17 reasonable.
18 UPDATED ECONOMIC ANALYSIS
19 Q.Did the company refresh any other assumptions
20 not already identified above in the updated final
21 shortlist economic analysis?
22 A.No.
23 Q.Did the company continue to apply production
24 tax credit ("PTC")benefits applicable to BTAs and
25 benchmark-EPC bids on a nominal basis in its system
396 Link,Di-2nd Supp -11
Rocky Mountain Power
1 modeling using the SO model and PaR configured to
2 forecast system costs through 2036?
3 A.Yes.As described in my supplemental direct
4 testimony,this approach better reflects how the federal
5 PTC benefits for.these bids will flow through to
6 customers and aligns the treatment of federal PTC
7 benefits in the system modeling results extending out
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
397 Link,Di-2nd Supp -lla
Rocky Mountain Power
1 through 2036 with the nominal revenue requirement results
2 extending out through 2050.It also ensures the 2017R RFP
3 bid selections from the SO model more accurately reflect
4 the difference in how BTA and benchmark-EPC bids are
5 expected to impact customer rates.
6 Q.Did the company continue to apply revenue
7 requirement associated with capital costs on a levelized
8 basis in its system modeling using the SO model and PaR
9 configured to forecast system costs through 2036?
10 A.Yes.As discussed in my supplemental direct
11 testimony,when setting rates,revenue requirement from
12 capital costs is depreciated over the book life of the
13 asset,effectively spreading the cost of capital
14 investments over the life of the asset.Because revenue
15 requirement from capital projects is spread over the life
16 of the asset in rates,these costs continue to be treated
17 as a levelized cost in the SO model and PaR simulations.
18 Q.Did the company update its revenue-requirement
19 modeling among different price-policy scenarios to
20 reflect the updated final shortlist and modeling updates
21 described above?
22 A.Yes.Using the same annual revenue-requirement
23 modeling methodology described in my direct and
24 supplemental direct testimony,the company updated its
25 forecast of the change in nominal annual revenue
398 Link,Di-2nd Supp -12
Rocky Mountain Power
1 requirement due to the Combined Projects.As was done in
2 the economic analysis summarized in my direct and
3 supplemental direct testimony,revenue requirement from
4 capital associated with the Combined Projects is treated
5 as a nominal cost when the results are extrapolated out
6 through 2050.
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
399 Link,Di-2nd Supp -12a
Rocky Mountain Power
1 UPDATED SYSTEM MODELING PRICE-POLICY RESULTSO2Q.Please summarize the updated PVRR(d)results
3 calculated from the SO model and PaR through 2036.
4 A.Table 2-SS summarizes the updated PVRR(d)
5 results for each price-policy scenario alongside the same
6 results summarized in my supplemental direct testimony.
7 The PVRR(d)between cases with and without the Combined
8 Projects,reflecting the updated final shortlist from the
9 2017R RFP,are shown for the SO model and for PaR,which
10 was used to calculate both the stochastic-mean PVRR(d)
11 and the risk-adjusted PVRR(d).The data used to calculate
12 the updated PVRR(d)results shown in the table are
13 provided as Exhibit No.55.
14
15
16
17
18
19
20
21
22
23
24
25
400 Link,Di-2nd Supp -13
Rocky Mountain Power
1 CORRECTED Table 2-SS Updated SO Model and PaR PVRR(d)O 2 (Benefit)/Cost of the Combined Projects ($million)
3 Second Supplemental Direct SupplementalDirect
(TInd ted Final Shrrtlist)(Orie unl Finni Shcrtlistì
4 PaR PaR
Stochastic PaR Risk-Stochastic PaR Risk-
5 SO Model Mean Adjusted SO Model Mean Adjusted
Price-Policy Scenario PVRR(d)PVRR(d)PVRR(d)PVRR(d)PVRR(d)PVRR(d)
6
Low Gas,Zero CO2 ($185)($150)($156)($145)($126)($131)
7
Low Gas,Medium CO2 ($208)($179)($188)($186)($146)($152)
8
Low Gas,High CO2 ($370)($337)($355)($297)($280)($294)
10 Medium Gas,Zero CO2 ($377)($319)($334)($306)($268)($280)
Medium Gas,Medium CO2 ($405)($357)($386)($343)($333)($349)
12 Medium Gas,High CO2 ($489)$(448)($469)($430)($409)($428)
13 High Gas,Zero CO2 ($699)($568)($596)($619)($531)($557)
14 High Gas,Medium CO2 ($716)($603)_($633)($636)($561)($588)
15 High Gas,High CO2 ($781)($694)($728)($696)($627)($658)
16
17 Over a 20-year period,the Combined Projects
18 reduce customer costs in all nine price-policy scenarios.
19 This outcome is consistent in both the SO model and PaR
20 results.Under the central price-policy scenario,when
21 applying medium natural gas,medium CO2 price-policy
22 assumptions,the PVRR (d)net benefits range between $357
23 million (up from $333 million),when derived from PaR
24 stochastic-mean results,and $405 million (up from $343
25 million),when derived from SO model results.Net
401 Link,Di-2nd Supp -14RockyMountainPower
1 benefits increase relative to those shown in myO2supplementaldirecttestimony.This is driven by the
3 increased interconnection capacity associated with the
4 Aeolus-to-Bridger/Anticline
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
402 Link,Di-2nd Supp -14a
Rocky Mountain Power
1 transmission line,which enables selection of the Ekola
2 Flats benchmark resource.Without this update,there was
3 not sufficient interconnection capacity to accommodate
4 the Ekola Flats benchmark with the TB Flats I &II and
5 Cedar Springs bids.
6 Q.Did you update the potential upside to these
7 PVRR(d)results associated with renewable energy credit
8 ("REC")revenues?
9 A.Yes.Consistent with my direct and supplemental
10 direct testimony,the PVRR(d)results presented in Table
11 2-SS do not reflect the potential value of RECs generated
12 by the incremental energy output from the updated final
13 shortlist projects.Accounting for the performance
14 estimates from the updated final shortlist projects,
15 customer benefits for all price-policy scenarios would
16 improve by approximately $34 million (up from $31 million
17 in my supplemental direct analysis)for every dollar
18 assigned to the incremental RECs that will be generated
19 from the winning bids through 2036.Quantifying the
20 potential upside associated with incremental REC revenues
21 is simply intended to communicate that the net benefits
22 from the winning bids could improve if the incremental
23 RECs can be monetized in the market.
24 Q.Did you update the potential upside to these
25 PVRR(d)results associated with reduced operations and
403 Link,Di-2nd Supp -15
Rocky Mountain Power
1 maintenance ("O&M")costs?O 2 A.Yes.Consistent with my supplemental direct
3 testimony,projects with large wind turbines are expected
4 to require less O&M costs because there are fewer
5 turbines on a given site.The default O&M assumptions
6 applied to BTA and benchmark-EPC bids in the updated
7 economic analysis are based on the company's experience
8 in operating and maintaining the existing fleet of
9 owned-wind facilities,and do not reflect expected cost
10 savings associated with operating and maintaining wind
11 facilities proposing to use
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
404 Link,Di-2nd Supp -15a
Rocky Mountain Power
1 larger wind turbines.Three of the winning bids-InvenergyO2WindDevelopment's Uinta project,the company's TB Flats
3 I &II project,and the company's Ekola Flats
4 project-will use larger equipment for a portion of the
5 wind turbines at each facility.If the O&M cost elements
6 applicable to the larger-turbine equipment are reduced by
7 42 percent,which is equivalent to an approximately 18
8 percent reduction in total O&M costs,beyond the proposed
9 O&M agreement period,customer benefits calculated
10 through 2036 for all price-policy scenarios would improve
11 by approximately $19 million (up from $13 million in my
12 supplemental direct testimony).
13 Q.Is there additional upside to the net benefits
14 shown in Table 2-SS?
15 A.Yes.The CO2 price assumptions used in the
16 updated economic analysis were inadvertently modeled in
17 2012 real dollars instead of nominal dollars.
18 Consequently,the PVRR(d)net benefits in the six
19 price-policy scenarios that use medium and high CO2 price
20 assumptions are conservative.
21 UPDATED REVENUE REQUIREMENT MODELING PRICE-POLICY RESULTS
22 Q.Please summarize the updated PVRR(d)results
23 calculated from the change in annual revenue requirement
24 through 2050.
25 A.Table 3-SS summarizes the updated PVRR(d)
405 Link,Di-2nd Supp -16
Rocky Mountain Power
1 results for each price-policy scenario calculated off ofO2thechangeinannualnominalrevenuerequirementthrough
3 2050 alongside the same results summarized in my
4 supplemental direct testimony.The annual data over the
5 period 2017 through 2050 that was used to calculate the
6 updated PVRR(d)results shown in the table are provided
7 as Exhibit No.56.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
406 Link,Di-2nd Supp -16a
Rocky Mountain Power
1
CORRECTED Table 3-SS.Updated Nominal Revenue RequirementPVRR(d)
2 (Benefit)/Cost of the Combined Projects ($million)
3 Second
Supplemental Supplemental
4 Dent Dent
(UpdatedFinal (Original Final
5 Price-Policy Scenario Shortlist)Shortlist)
6 Low Gas,Zero CO2 $184 $195
Low Gas,Medium CO2 $127 $159
Low Gas,High CO2 ($147)($79)
Medium Gas,Zero CO2 ($92)($34)
Medium Gas,Medium CO2 ($167)($151)
10 Medium Gas,High CO2 ($304)($275)
11 High Gas,Zero CO2 ($448)($411)
12 High Gas,Medium CO2 ($499)($453)
13 High Gas,High CO2 ($635)($559)
14 When system costs and benefits from the
15 Combined Projects are extended out through 2050,covering
16 the full depreciable life of the owned-wind projects
17 included in the updated 2017R RFP final shortlist,the
18 Combined Projects reduce customer costs in seven out of
19 nine price-policy scenarios.Customer net benefits range
20 from $92 million in the medium natural-gas,zero CO2
21 price-policy scenario (up from $34 million)to $635
22 million in the high natural gas,high CO2 price-policy
23 scenario (up from $559 million).Under the central
24 price-policy scenario,when applying medium natural gas,
25 medium CO2 price-policy assumptions,the PVRR(d)benefits
407 Link,Di-2nd Supp -17RockyMountainPower
1 of the Combined Projects are $167 million (up from $151
2 million).The Combined Projects provide significant
3 customer benefits in all price-policy scenarios,and the
4 net benefits are
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
408 Link,Di-2nd Supp -17a
Rocky Mountain Power
1 unfavorable only when low natural-gas prices are paired
2 with zero or medium CO2 prices.These results continue to
3 show that upside benefits far outweigh downside risks.
4 As is the case with the system-modeling
5 results,net benefits increase relative to those shown in
6 my supplemental direct testimony.As stated earlier,this
7 is driven by the increased interconnection capacity
8 associated with the Aeolus-to-Bridger/Anticline
9 transmission line,which enables selection of the Ekola
10 Flats benchmark resource.Without this update,there was
11 not sufficient interconnection capacity to accommodate
12 the Ekola Flats benchmark with the TB Flats I &II and
13 Cedar Springs bids.
14 Q.Is there additional potential upside to these
15 PVRR(d)results associated with REC revenues?
16 A.Yes.Consistent with my direct and supplemental
17 direct testimony,the PVRR(d)results presented in Table
18 3-SS do not reflect the potential value of RECs generated
19 by the incremental energy output from the Wind Projects.
20 Accounting for the performance estimates from the updated
21 final shortlist projects,customer benefits for all
22 price-policy scenarios would improve by approximately $43
23 million (up from $39 million in my supplemental direct
24 analysis)for every dollar assigned to the incremental
25 RECs that will be generated from the winning bids through
409 Link,Di-2nd Supp -18
Rocky Mountain Power
1 2050.O 2 Q.Is there additional potential upside to these
3 PVRR(d)results associated with reduced O&M costs?
4 A.Yes.As discussed above,the company
5 anticipates O&M costs for those projects that will
6 install larger-turbine equipment to be lower than what
7 has been reflected in the updated economic analysis.
8 Accounting for these cost savings,customer benefits for
9 all price-policy scenarios would improve by approximately
10 $31 million (up from $22
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
410 Link,Di-2nd Supp -18a
Rocky Mountain Power
1 million in my supplemental direct testimony)when
2 calculated from projected operating costs through 2050.
3 Q.Is there additional potential upside to these
4 PVRR(d)results shown in Table 3-SS?
5 A.Yes.As noted earlier,the updated CO2 price
6 assumptions used in the updated economic analysis were
7 inadvertently modeled in 2012 real dollars instead of
8 nominal dollars.Consequently,the PVRR(d)net benefits
9 in the six price-policy scenarios that use medium and
10 high CO2 price assumptions are conservative.
11 Q.Please describe the change in annual nominal
12 revenue requirement from the Combined Projects.
13 A.Figure 1-SS shows the updated change in nominal
14 revenue requirement due to the Combined Projects for the
15 medium natural gas,medium CO2 price-policy scenario on a
16 total-system basis.These results are shown alongside the
17 same results from the economic analysis summarized in my
18 supplemental direct testimony.The change in nominal
19 revenue requirement shown in the figure reflects updated
20 costs,including capital revenue requirement (i.e.,
21 depreciation,return,income taxes,and property taxes),
22 O&M expenses,the Wyoming wind-production tax,and PTCs.
23 The project costs are netted against updated system
24 impacts from the Combined Projects,reflecting the change
25 in NPC,emissions,non-NPC variable costs,and system
411 Link,Di-2nd Supp -19
Rocky Mountain Power
1 fixed costs that are affected by,but not directly
2 associated with,the Combined Projects.
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
412 Link,Di-2nd Supp -19a
Rocky Mountain Power
ill!'
2 CORRECTED Figure 1-SS Updated Total-System Annual Revenue Requirement
3 With the Combined Projects (Benefit)/Cost ($million)
4 SSO
5
g so
8..(sto)--
8 (560)
(880)-------------------
9 ($100)
($120)
OOO ©OO OO OOOO OO O OO CO ©O ©OOO O OO
11 -*-2nd5upplemental --RebuttalTestimony
12
13 The data shown in this figure for the updated
14 economic analysis have the same basic profile as the data
15 from the économic analysis summarized in my supplemental
16 direct testimony.Despite a reduction in PTC benefits
17 associated with changes in federal tax law,the reduced
18 costs from winning bids from the 2017R RFP continue to
19 generate substantial near-term customer benefits and
20 continue to contribute to customer benefits over the long
21 term.The Combined Projects produce net benefits in 23
22 years out of the 30 years that the proposed owned-wind
23 resources selected to the 2017R RFP final shortlist are
24 assumed to operate.
25 As noted in my supplemental direct testimony,
413 Link,Di-2nd Supp -20RockyMountainPower
1 the year-on-year reduction in net benefits from 2036 toO22037isdrivenbythecompany's conservative approach to
3 extrapolate benefits from 2037 through 2050 based on
4 modeled results from the 2028-through-2036 time frame.
5 This leads to an abrupt reduction in the benefits in
6 2037,and a subsequent year-on-year reduction to net
7 benefits,which breaks from the trend
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
414 Link,Di-2nd Supp -20a
Rocky Mountain Power
1 observed in the model results over the 2035-to-2036 timeO2frame.This extrapolation methodology is conservative
3 because it results in project benefits not matching the
4 levels observed in the model results for 2036 until 2047.
5 SOLAR SENSITIVITY
6 Q.Did the company update its solar sensitivity
7 analysis?
8 A.Yes.The solar sensitivity analysis was updated
9 to reflect the updated final shortlist from the 2017R RFP
10 and to reflect best-and-final pricing supplied by bidders
11 participating in the 2017S RFP on February 1,2018.
12 Q.Please describe the sensitivity studies that
13 analyzed the impact of the solar bids received in the
14 2017S RFP on the economics of the Combined Projects.
15 A.Consistent with the methodology summarized in
16 my supplemental direct testimony,the company's solar
17 sensitivity analysis used the SO model and PaR
18 simulations to determine the PVRR(d)based on two model
19 runs-one with solar PPA bids and the Combined Projects
20 and one with solar PPA bids but without the Combined
21 Projects.
22 Q.What were the results of the solar sensitivity
23 where solar PPA bids are assumed to be pursued in lieu of
24 the Combined Projects?
25 A.Table 4-SS summarizes PVRR(d)results for the
415 Link,Di-2nd Supp -21
Rocky Mountain Power
1 solar sensitivity where solar PPA bids are assumed to beO2pursuedwithoutanyinvestmentsintheCombinedProjects.
3 This sensitivity was developed using SO model and PaR
4 simulations through 2036 for the medium natural gas,
5 medium CO2 and the low natural gas,zero CO2 price-policy
6 scenarios.The results are shown alongside the benchmark
7 study in which the Combined Projects were evaluated
8 without solar PPA bids.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
416 Link,Di-2nd Supp -21a
Rocky Mountain Power
1
CORRECTED Table 4-SS Updated Solar Sensitivitywith Solar PPAs Included
2 in lieu of the Combined Projects (Benefit)/Cost ($million)
3 Sensitivity Benchmark Change in
4 PVRR(d)PVRR(d)PVRR(d)
Medium Gas,Medium CO,
5 SO Model ($343)($405)$61
PaR Stochastic Mean ($228)($357)$129
6 PaR Risk Adjusted ($237)($386)$149
Low Gas,Zero CO,7 SO Model ($196)($185)($11)
8 PaR Stochastic Mean ($139)($150)$11
PaR Risk Adjusted ($145)($156)$11
10 In this sensitivity,the SO model selects 1,122
11 MW of solar PPA bids in the low natural gas,zero CO2
12 price-policy scenario and 1,419 MW of solar PPA bids in
13 the medium natural gas,medium CO2 price-policy scenario.
14 All of the selected solar PPA bids are for projects
15 located in Utah.
16 In the medium natural gas,medium CO2
17 price-policy scenario,a portfolio with the Combined
18 Projects delivers greater customer benefits relative to a
19 portfolio that adds solar PPA bids without the Combined
20 Projects.Customer benefits are greater when the resource
21 portfolio includes the Combined Projects without solar
22 PPA bids by $149 million in the medium natural gas,
23 medium CO2 price-policy scenario based on the
24 risk-adjusted PaR results.In the low natural gas,zero
25 CO2 price-policy scenario,the portfolio with the
417 Link,Di-2nd Supp -22
Rocky Mountain Power
1 Combined Projects delivers slightly greater customer
2 benefits relative to a portfolio that adds solar PPA bids
3 without the Combined Projects when modeled in PaR,and
4 slightly lower customer benefits when analyzed with the
5 SO model.The decrease in net benefits in the solar PPA
6 portfolio is $11 million based on the risk-adjusted PaR
7 results.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
418 Link,Di-2nd Supp -22a
Rocky Mountain Power
1 When analyzed without the Combined Projects,
2 the solar PPA bids produce net customer benefits that are
3 lower than the benefits expected from the Combined
4 Projects in the medium natural gas,medium CO2
5 price-policy scenario.While the sensitivity with a
6 portfolio containing solar PPAs without the Combined
7 Projects produces PVRR(d)results that are similar to the
8 PVRR(d)results with only the Combined Projects in the
9 low natural-gas,zero CO2 price-policy scenario,both
10 portfolios deliver customer benefits.This sensitivity
11 does not support an alternative resource procurement
12 strategy to pursue solar PPA bids in lieu of the Combined
13 Projects.This would leave the significant benefits from
14 the Combined Projects,which include building a
15 much-needed transmission line,on the table.
16 Q.What were the results of the solar sensitivity
17 where solar PPA bids are pursued with the Combined
18 Projects?
19 A.Table 5-SS summarizes PVRR(d)results for the
20 solar sensitivity where solar PPA bids are assumed to be
21 pursued along with the proposed investments in the
22 Combined Projects.This sensitivity was developed using
23 SO model and PaR simulations through 2036 for the medium
24 natural gas,medium CO2 and the low natural gas,zero CO2
25 price-policy scenarios.The results are shown alongside
419 Link,Di-2nd Supp -23
Rocky Mountain Power
1 the benchmark study in which the Combined Projects wereO2evaluatedwithoutsolarPPAbids.
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
420 Link,Di-2nd Supp -23a
Rocky Mountain Power
2 CORRECTED Table 5-SS Updated Solar Sensitivitywith Solar PPAs Included
3
With the Combined Projects (Benefit)/Cost ($million)
4 Sensitivity Benchmark Change in
PVRR(d)PVRR(d)PVRR(d)
5 Medium Gas,]Wedium CO,
SO Model ($647)($405)($242)
6 PaR Stochastic Mean ($519)($357)($163)
7 PaR Risk Adjusted ($543)($386)($157)
Low Gas,Zero CO2
8 SO Model ($312)($185)($127)
PaR Stochastic Mean ($250)($150)($100)
9 PaR Risk Adjusted ($259)($156)($103)
10 In this sensitivity,the SO model continues to
11 choose the winning bids included in the updated 2017R RFP
12 final shortlist as part of the least-cost bid portfolio.
13 In addition to these wind resource selections,the SO
14 model selects 1,042 MW of solar PPA bids in the low
15 natural gas,zero CO2 price-policy scenario and 1,419 MW
16 of solar PPA bids in the medium natural gas,medium CO2
17 price-policy scenario.Again,all of the selected solar
18 PPA bids are for projects located in Utah.
19 When the solar PPAs are assumed to be pursued
20 in addition to the Combined Projects,total net customer
21 benefits increase.This result is consistent with the
22 company's expectation expressed during the technical
23 conference conducted on January 17,2018 that
24 cost-effective solar opportunities would not displace the
25 Combined Projects,but would only potentially add to
421 Link,Di-2nd Supp -24
Rocky Mountain Power
1 incremental resource procurement opportunities that might
2 provide net customer benefits.Importantly,this
3 sensitivity produces net benefits that are greater than
4 the net benefits from the Combined Projects without the
5 solar PPAs.This confirms that near-term renewable
6 procurement is not a matter of whether the company should
7 pursue the Combined Projects or the solar PPAs,but
8 whether the company should consider both
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
422 Link,Di-2nd Supp -24a
Rocky Mountain Power
1 opportunities.At this time,it is clear that the
2 Combined Projects provide significant net benefits,and
3 that these benefits are not eliminated if the company
4 were to also pursue solar PPA bids through the 2017S RFP.
5 WIND-REPOWERING SENSITIVITY
6 Q.Has the company updated its sensitivity
7 analysis related to the wind repowering project?
8 A.Yes.The wind repowering sensitivity was
9 updated to reflect the updated final shortlist and to
10 reflect the most recent cost-and performance estimates
11 for the wind repowering project as described in my
12 supplemental direct testimony filed in Case No.
13 PAC-E-17-06.
14 Q.What were the results of the updated
15 wind-repowering sensitivity?
16 A.Table 6-SS summarizes PVRR(d)results for this
17 wind-repowering sensitivity.This sensitivity was
18 developed using SO model and PaR simulations through 2036
19 for the medium natural-gas,medium CO2 and the low
20 natural-gas,zero CO2 price-policy scenarios.The results
21 are shown alongside the benchmark study in which the
22 Combined Projects were evaluated without wind repowering.
23 /
24 /
25 /
423 Link,Di-2nd Supp -25
Rocky Mountain Power
1
2 CORRECTED Table GSS Wind-Repowering
Sensitivity(Benefit)/Cost ($million)
3 Sensidvity Benclunark Change in
PVRR(d)PVRR(d)PVRR(d)4 Medium Gas,Medium CO2
5 so Model ($608)($405)($204)
PaR Stochastic Mean ($541)($357)($184)
6 PaR Risk Adjusted ($567)($386)($181)
Low Gas,Zero CO2
7 SO Model ($334)($185)($149)
PaR Stochastic Mean ($281)($150)($131)
PaR Risk Adjusted ($295)($156)($138)
10
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25O
424 Link,Di-2nd Supp -25a
Rocky Mountain Power
1 In the updated wind-repowering sensitivity,
2 customer benefits increase significantly when the wind
3 repowering project is implemented with the Combined
4 Projects in both the medium natural-gas,medium CO2,and
5 the low natural-gas,zero CO2 price-policy scenarios.
6 These results continue to demonstrate that customer
7 benefits not only persist,but also increase,if both the
8 wind-repowering project and the Combined Projects are
9 completed.
10 TURBINE-EQUIPMENT SENSITIVITY
11 Q.Did the company perform any other additional
12 sensitivity analysis to support selection of bids to the
13 updated 2017R RFP final shortlist?
14 A.Yes.The company produced an SO model
15 sensitivity to analyze the PVRR(d)impact of (redacted)
16 //////////////////////////////////////////////.
17 Q.Why did the company develop this sensitivity?
18 A.Technical discussions and preliminary modeling
19 of (redacted)in the interconnection-restudy process
20 raised concerns that a synchronous condenser or other
21 electrical compensation equipment might be required at
22 the Aeolus substation if the (redacted)/////////////
23 to address system performance in a low stiffness-factor
24 environment.Considering that (redacted)/////////////
25 /////////////////////////////////////////////////////////
425 Link,Di-2nd Supp -26
Rocky Mountain Power
1 ///////////////////////////////the company produced this
2 sensitivity to estimate the incremental amount of network
3 upgrade costs that would (redacted)////////////////////
4 //////////////////////.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
426 Link,Di-2nd Supp -26a
Rocky Mountain Power
1 Q.What were the results of this turbine-equipment
2 sensitivity?
3 A.Table 7-SS summarizes PVRR(d)results for the
4 turbine-equipment sensitivity.This sensitivity was
5 developed using the SO model through 2036 for the medium
6 natural-gas,medium CO2 and the low natural-gas,zero CO2
7 price-policy scenarios.The results are shown alongside
8 the benchmark study in which the Combined Projects were
9 evaluated with the updated final shortlist of bids.
10 Table 7-SS Turbine-Equipment
11 Sensitivity (Benefit)/Cost ($miHion)
12 Sensitivity Benchmark Change in
PVRR(d)PVRR(d)PVRR(d)
O 13 Medium Gas,Medium CO2 ($381)(5405)$24
Low Gas,Zero CO2 ÇiÏl43)($185)$42
14
15 Considering that the SO model uses levelized
16 capital costs,the reduction in PVRR(d)net benefits in
17 this sensitivity would require at least (redacted)in
18 incremental in-service transmission upgrade costs
19 attributable (redacted)/////////////////////////////
20 /////////////////////////////////.
21 The company does not anticipate that incremental
22 in-service transmission costs would exceed (redacted)
23 should a synchronous condenser or other electrical
24 compensation equipment be required.Moreover (redacted)
25 ////////////////////////////////////////////////////
427 Link,Di-2nd Supp -27
Rocky Mountain Power
1 ////////////////.Based on these findings (redacted)
2 ///////////////////////PacifiCorp did not (redacted)
3 ///////////////////////////////////////////////////.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
428 Link,Di-2nd Supp -27a
Rocky Mountain Power
1 INDEPENDENT EVALUATORSO2Q.Has the company compiled summaries of all bids
3 received?
4 A.Yes.The Combined Projects have proceedings
5 simultaneously occurring in Utah,Idaho,and Wyoming.
6 While the Idaho Commission does not have statutes or
7 rules that pertain to requests for proposals,other
8 states do.In order to provide as much information as
9 possible to allow a thorough review in all states,the
10 company is providing Confidential Exhibit No.57,which
11 summarizes the bids that were received and reviewed as
12 part of the 2017R RFP.The Utah IE's monthly reports,
13 which are attached as Highly Confidential Exhibit No.58,
14 also include a summary of all of the bids that were
15 included on the 2017R RFP initial shortlist.The
16 non-conforming bids that were received and rejected are
17 described in Highly Confidential Exhibit No.59.
18 Q.Is the company providing summaries of its
19 rankings and evaluations of bids?
20 A.Yes.Highly Confidential Exhibit No.60
21 provides a summary of the company's rankings and
22 evaluation of bids.In addition,my rebuttal testimony
23 filed December 18,2017,supplemental direct testimony,
24 filed January 16,2018,and my testimony above describes
25 how the company evaluated bids using the SO model and PaR
429 Link,Di-2nd Supp -28
Rocky Mountain Power
1 to identify the final-shortlist projects.
2 Q.Is the company providing the reports prepared
3 by the Utah IE?
4 A.Yes.Highly Confidential Exhibit No.58
5 provides copies of all the monthly status reports
6 prepared by the IE.The exhibit also includes the Utah
7 IE's final report on the assessment of the Company's
8 benchmark resources (i.e.,TB Flats I and II,Ekola
9 Flats,and McFadden Ridge II),which was prepared by the
10 IE on November 2,2017,and the Utah IE's report on the
11 2017R RFP final shortlist,which was prepared by the IE
12 on
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
430 Link,Di-2nd Supp -28a
Rocky Mountain Power
1 February 15,2018.O 2 Q.What were the Utah IE's conclusions related to
3 the benchmark resources?
4 A.The IE found that the company "developed
5 detailed cost information about the benchmark resources
6 and provided their proposals along with the background
7 information and spreadsheets detailing the cost by line
8 item to the IEs for review and assessment of the
9 benchmark resources."
10 The IE concluded that the "benchmark proposals
11 contain all the information required of other bidders and
12 will be evaluated consistent with the methodology used to
13 evaluate all bids submitted."According to the IE,the
14 "level and detail of information provided by [the
15 Company]is very thorough and exceeds industry standards
16 for benchmark resources at this stage in the process."
17 (emphasis added).
18 Regarding the cost estimates for the benchmark
19 resources,the IE concluded that,"[o]verall,we feel
20 that the capital costs are reasonable for the benchmark
21 resources but if there is any deviation from the average
22 we feel it would be on the low side of the cost
23 spectrum."Similarly,the IE concluded that the O&M
24 costs are reasonable.
25 Overall,the IE concluded that the company's
431 Link,Di-2nd Supp -29
Rocky Mountain Power
1 treatment of benchmark resources in the 2017R RFP
2 conformed to the requirements of Utah Admin.Rule
3 R746-420 and that the "review,assessment and scoring of
4 the benchmark resources was conducted in a fair and
5 equitable manner with no outward perception of bias."
6 Q.What were the Utah IE's conclusions related to
7 the 2017R RFP final shortlist?
8 A.As noted above,the IE agreed with the
9 Company's final shortlist and specifically concluded the
10 following:
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
432 Link,Di-2nd Supp -29a
Rocky Mountain Power
1 The response to the 2017R RFP was robust-the
2 capacity bid into the RFP was more than five
3 times the capacity requested,and bidders
4 offered a variety of commercial structures;
5 The Company used a consistent evaluation
6 process and treated all proposals equally;
7 The Company made a compelling case that it
8 reasonably accounted for the interconnection
9 queue position of project bids and eliminated
10 projects with bid positions higher than Q0712.1
11 The Company's modeling demonstrates that
12 pursuit of the Wind Projects should result in
13 significant customer benefits,particularly in
14 the near-term as PTC benefits flow through
15 rates;
16 The final revised evaluation and shortlist is
17 reasonable;
18 Q.Does Highly Confidential Exhibit No.58 include
19 the IE's final report?
20 A.No.The company has not received a copy of the
21 IE's final report.But once the report is completed,the
22 company will ensure that it is promptly filed with the
23 commission.
24 Q.Has the company included any reports filed by
25 the IE appointed by the Public Utility Commission of
433 Link,Di-2nd Supp -30
Rocky Mountain Power
1 Oregon (Oregon Commission)?
2 A.Yes.The Oregon Commission appointed Bates
3 White,LLC as its IE.At this time,the Oregon IE has
4 provided an assessment of the final draft RFP and a
5 letter confirming its agreement with changes made to the
6 final 2017R RFP,which are provided as Exhibit No.61.
7 The Oregon IE will file its closing report with the
8 Oregon Commission
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24 1 While the details of the IE's report,particularly the summaries of
bid information,is designated highly confidential,the IE's
25 conclusions are non-confidential.
434 Link,Di-2nd Supp -30a
Rocky Mountain Power
1 on February 16,2017.The company will file the Oregon
2 IE's closing report with the Idaho Commission once it is
3 available.
4 Q.Is the 2017R RFP publicly available?
5 A.Yes.The 2017R RFP,along with all appendices
6 and exhibits,has been available on the Company's website
7 (http://www.pacificorp.com/sup/rfps/2017-rfp.html)since
8 it was issued.In addition,although it is not the
9 subject of this case,the 2017S RFP and all appendices
10 are also publicly available on the Company's website
11 (http://www.pacificorp.com/sup/rfps/2017S-RFP.html).
12 Q.Does this conclude your second supplemental
13 direct testimony?
14 A.Yes.
15
16
17
18
19
20
21
22
23
24
25
435 Link,Di-2nd Supp -31
Rocky Mountain Power
1 Q.Are you the same Rick T.Link who previously
2 provided testimony in this case on behalf of Rocky
3 Mountain Power,a division of PacifiCorp?
4 A.Yes.
5 PURPOSE AND SUMMARY OF SUPPLEMENTAL REBUTTAL TESTIMONY
6 Q.What is the purpose of your supplemental
7 rebuttal testimony in this proceeding?
8 A.My testimony supports the company's application
9 for certificates of public convenience and necessity
10 ("CPCNs")and binding ratemaking treatment for the
11 Aeolus-to-Bridger/Anticline line and network upgrades
12 ("Transmission Projects")and the Ekola Flats,TB Flats I
13 and II,Cedar Springs,and Uinta projects.These are the
14 four new wind resources ("Wind Projects")included on the
15 final shortlist of the 2017R Request for Proposals
16 ("2017R RFP"),(collectively,the "Combined Projects").
17 Specifically,my testimony responds to the April 11,
18 2018,testimony filed by Anthony Yankel on behalf of the
19 Idaho Irrigation Pumper Association ("IIPA"),Nicholas L.
20 Phillips,on behalf of Monsanto,Bradley G.Mullins on
21 behalf of PacifiCorp Idaho Industrial Customers ("PIIC"),
22 and Michael Louis and Michael Eldred on behalf of the
23 Idaho Public Utilities Commission Staff ("Staff").
24 Q.Please summarize your testimony.
25 A.I respond to claims that PacifiCorp does not
436 Link,Supp-Reb -1
Rocky Mountain Power
1 have a resource need.I address criticisms of
2 PacifiCorp's 2017R RFP bid evaluation and selection
3 process and criticisms of the company's economic
4 analysis,which shows that the Combined Projects will
5 generate significant customer benefits.In response to
6 claims that the Combined Projects may not be the
7 least-cost,least-risk resource option,I also summarize
8 the economic analysis used to finalize PacifiCorp's 2017S
9 Request for Proposals ("2017S RFP")bid-selection
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
437 Link,Supp-Reb -la
Rocky Mountain Power
1 process.My supplemental rebuttal testimony demonstrates
2 that:
3 o Even after accounting for the updated load forecast
4 that is summarized in my supplemental direct
5 testimony,PacifiCorp has a 595-MW capacity deficit
6 in 2021 that grows to 3,395 MW in 2036 and that the
7 Combined Projects are least-cost,least-risk
8 resources that will partially meet this need.
9 o As supported by independent evaluators that were
10 appointed,retained,and managed by two different
11 state regulatory commissions,the 2017R RFP was
12 fair,transparent,and unbiased.
13 o These independent evaluators found that the bids
14 selected to the 2017R RFP final shortlist represent
15 the top offers that are viable under current
16 transmission planning assumptions,and one of the
17 experts concluded that the final shortlist should
18 result in significant savings for customers.
19 o The company has performed over 1,300 20-year
20 simulations of PacifiCorp's system to thoroughly
21 evaluate how the net benefits of the Combined
22 Projects are affected by a broad range of variables
23 and uncertainties.
24 o While solar resources may provide customer benefits,
25 contrary to claims from certain parties,solar
438 Link,Supp-Reb -2
Rocky Mountain Power
1 resource bids submitted into the 2017S RFP are not aO2superiorresourcealternativetotheCombined
3 Projects.
4 o Solar resources are best viewed as an incremental
5 opportunity,not as an alternative to the Combined
6 Projects.
7 o During the evaluation of bids in the 2017S RFP,
8 PacifiCorp analyzed valuation risks that are unique
9 to the procurement of solar resources and determined
10 that solar resource costs are likely to continue to
11 fall.
12 /
13
14 /
15
16 /
17
18
19
20
i
21
22
23
24
25
439 Link,Supp-Reb -2a
Rocky Mountain Power
1 o Given these solar resource-valuation risks,expectedO2costdeclines,and availability of the 30-percent
3 investment tax credit ("ITC")for solar projects
4 coming online as late as 2021,PacifiCorp does not
5 need to act now and has decided not to select any of
6 the solar power-purchase agreement ("PPA")bids to
7 the 2017S RFP final shortlist.
8 o PacifiCorp will continue to assess potential
9 economic benefits from solar-resource opportunities
10 through bi-lateral opportunities and in the 2019
11 Integrated Resource Plan ("IRP"),including a
12 thorough review of valuation risks with full
13 stakeholder engagement,to determine whether a new
14 competitive solicitation process for projects
15 capable of achieving commercial operation by the end
16 of 2021 will provide customer benefits.
17 o In contrast,the phase-out of production tax credit
18 ("PTC")benefits that are available for qualifying
19 wind projects occurs sooner than the ramp down of
20 ITC benefits that are available for solar resources,
21 which requires that PacifiCorp act now to deliver
22 the new wind and needed transmission investments
23 that will produce both near-term and long-term
24 benefits for customers.
25
440 Link,Supp-Reb -3RockyMountainPower
1 RESOURCE NEEDO2Q.Messrs.Louis,Phillips,Mullins,and Yankel
3 continue to question the need for any new resources.
4 (Louis Supp.Direct,page 3,lines 20-25;Mullins Supp.
5 Direct,page 35,lines 3-12;Phillips Supp.Direct,page
6 2,line 23 and page 28,line 5:Yankel Supp.Direct,page
7 1,lines 20-22,page 4,lines 12-20,and page 5,lines
8 1-12.)Please summarize how the 2017 IRP identified a
9 resource need that can be met by the Combined Projects.
10 A.In my rebuttal testimony,I explained in detail
11 that the company has an immediate resource need and that
12 the Combined Projects would displace higher cost,higher
13 risk front-office transactions ("FOTs")in the near term
14 and defer the need for other,higher-cost resources in
15 the 2028 time frame.Therefore the Combined Projects meet
16 a near-term and long-term resource need as identified in
17 the 2017 IRP.(Link Rebuttal,page 7,line 9 to page 17,
18 line 8.)
19 Q.Mr.Mullins claims that the company's position
20 is imprudent because it "disregards market access"when
21 determining resource sufficiency.(Mullins Supp.Direct,
22 page 35,lines 14-19.)Is this true?
23 A.No.Mr.Mullins implies that the company just
24 ignores FOTs in its IRP modeling,which is the exact same
25 modeling used in this case.In fact,as I described in my
441 Link,Supp-Reb -4RockyMountainPower
1 rebuttal testimony,FOTs must compete against all other
2 resource options,including the Combined Projects.The
3 fact that the SO model selected the Combined Projects
4 over FOTs demonstrates that the Combined Projects are a
5 superior resource choice to meet the capacity shortfall
6 identified in the 2017 IRP,and moreover to meet all
7 system requirements.The implication of Mr.Mullins's
8 position is that the company should rely
9 /
10
11 /
12
I
13 /
14
15
16
17
18
19
20
21
22
23
24
25
442 Link,Supp-Reb -4a
Rocky Mountain Power
1 on FOTs to meet its resource needs regardless of cost and
2 risk,which is the truly imprudent course of action.
3 Q.Mr.Mullins and Mr.Yankel claim that the
4 capacity need identified in the 2017 IRP no longer exists
5 when the company's resource need assessment is updated to
6 account for the most recent,lower load forecast.
7 (Mullins Supp.Direct,page 36,line 3 to page 37,line
8 14,and Yankel Supp.Direct,page 4,line 12 to page 5,
9 line 12.)Is this true?
10 A.No.In 2021,the first full year that the Wind
11 Projects are in service,the 2017 IRP shows a capacity
12 deficit of 1,023 MW.The updated load forecast summarized
13 in my supplemental direct testimony shows a 428-MW
14 reduction to the coincident peak load forecast in 2021
15 relative to the load forecast used in the 2017 IRP (Link
16 Supp.Direct,page 18,line 10 to page 19,line 8).
17 Consequently,accounting for the updated load forecast,
18 PacifiCorp's capacity deficit in 2021 is now 595 MW
19 (1,023 MW capacity deficit less 428 MW reduction in
20 coincident peak load).Accounting for the updated load
21 forecast,PacifiCorp's capacity need grows to 3,395 MW by
22 2036.The capacity contribution of the Wind Projects is
23 207 MW (1,311 MW nameplate capacity times 15.8 percent
24 capacity contribution),which is well below the 595 MW of
25 capacity need in 2021 and the 3,395 MW of capacity need
443 Link,Supp-Reb -5RockyMountainPower
1 in 2036 even after accounting for the updated load
2 forecast.
3 /
4
5 /
6
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
444 Link,Supp-Reb -5a
Rocky Mountain Power
1 Q.Mr.Louis justifies his proposed conditions
2 based upon a distinction between a resource need and
3 capacity need,pointing out that the company's 2017 IRP
4 does not show a capacity need until 2028.(Louis Supp.
5 Direct,page 6 line 16 to page 7 line 4.)How do you
6 respond?
7 A.I strongly disagree with the fundamental
8 premise of Mr.Louis's view of resource need.As
9 discussed above,even after accounting for an updated
10 load forecast,PacifiCorp has a 595-MW capacity deficit
11 in 2021 that grows to 3,395 MW by 2036.This means that
12 if the company did not procure any new resources,it
13 would not have sufficient capacity to reliably meet
14 customer demand throughout the entire forecast horizon.
15 The IRP models are used to identify the least-cost,
16 least-risk mix of resources,among all resource
17 alternatives (i.e.,FOTs,demand-side management,energy
18 storage,and generating assets),that can be used to fill
19 this capacity deficit.In every scenario that the company
20 has analyzed,the IRP models choose the proposed Wind
21 Projects,among all other resource alternatives.This
22 means that the proposed Wind Projects are lower cost than
23 all other resource alternatives.
24 Mr.Louis's attempt to distinguish between
25 resource need and the need for capacity to meet load is
445 Link,Supp-Reb -6RockyMountainPower
1 misguided and not supported.The fact is that there is no
2 difference-a resource need is defined as the need for
3 capacity to meet load.This capacity can come in many
4 different forms (i.e.,FOTs,demand-side management,
5 energy storage,and generating assets),and the company's
6 economic analysis clearly demonstrates that the Wind
7 Projects are the least-cost,least-risk resource
8 alternative.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
446 Link,Supp-Reb -6a
Rocky Mountain Power
1 Q.Why is it important to recognize the parties'
2 flawed and contradictory positions on resource need?
3 A.Messrs.Louis,Mullins,and Phillips have
4 recommended several unprecedented conditions that the
5 Commission should apply if it grants CPCNs for the
6 Combined Projects,including disallowance of rate-base
7 treatment for any turbine not in service in time to
8 receive 100-percent PTCs,a capital-cost cap that results
9 in an automatic 21-percent disallowance,a lifetime cap
10 on O&M and capital expenditures,imputation of the full
11 estimated PTC benefits over the next 10 years,and total
12 disallowance if the Combined Projects are not completed
13 (Phillips Corrected Supp.Response,page 59,line 7 to
14 page 60,line 21.)They justify these conditions because
15 they claim that the "Combined Projects are an opportunity
16 investment for RMP"and therefore "it is appropriate to
17 apply the traditional regulatory compact in reverse"to
18 effectively guarantee customer benefits and eliminate
19 customer risk.(Phillips Direct,page 7,line 21 to page
20 8,line 5;see also Phillips Direct,page 34,line 21 to
21 page 35,line 2 (Combined Projects are "discretionary,
22 and not designed to fulfill any resource requirement or
23 other needs[.]");Phillips Direct,page 3,lines 17-19
24 ("Wind Projects are not being pursued by RMP as a matter
25 of need;rather,they are a discretionary project
447 Link,Supp-Reb -7
Rocky Mountain Power
1 predominantly intended to harvest tax credits and
2 increase RMP's rate base which might provide savings to
3 ratepayers.")).However,because the Combined Projects
4 clearly meet a resource need in the traditional sense
5 there is no basis for these conditions.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
448 Link,Supp-Reb -7a
Rocky Mountain Power
1 Q.Have these parties demonstrated that the
2 Combined Projects pose greater risk to customers than
3 increased reliance on FOTs in the near-term and the
4 acquisition of a resource in 2028?
5 A.No.While they recommend that customers be
6 relieved of virtually all risk related to the Combined
7 Projects,they have not demonstrated that customers will
8 be exposed to higher or unreasonable risk because of the
9 Combined Projects relative to the next best resource
10 options.Just as there is no reason customers should be
11 relieved of all risk related to FOTs,there is no reason
12 customers should be relieved of all risk associated with
13 the Combined Projects.Because the Combined Projects meet
14 an identified resource need,there is no basis to apply
15 conditions that represent a dramatic and unprecedented
16 departure from well-established and long-standing
17 regulatory principles.
18 .Q.Mr.Phillips notes the Oregon independent
19 evaluator's recommendation for ratemaking treatment for
20 the Combined Projects to support his proposed conditions.
21 (Phillips Supp.Direct,page 57,lines 1-35.)How do you
22 respond?
23 A.Mr.Phillips's proposed conditions go far
24 beyond the recommendation of the Oregon independent
25 evaluator.For example,the Oregon independent evaluator
449 Link,Supp-Reb -8
Rocky Mountain Power
1 recommends a hard cap on the capital and O&M costs forO2theCombinedProjects.Mr.Phillips recommends a hard cap
3 and a 21-percent disallowance.Moreover,the Oregon
4 independent evaluator's recommendation was intended to
5 provide a comparable risk profile for utility-owned and
6 PPA resources.Mr.Phillips's conditions are designed to
7 remove customer risk regardless of the commercial
8 structure,as evidenced by the fact his conditions were
9 proposed before he knew whether the 2017R RFP would
10 result in
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
450 Link,Supp-Reb -8a
Rocky Mountain Power
1 PPAs or utility-owned resources.Ultimately,the company
2 believes that the Commission's existing ratemaking tools
3 provide robust customer protections that do not require
4 the imposition of unprecedented conditions on the
5 Combined Projects.
6 Q.Mr.Yankel claims that "PacifiCorp's need for
7 more internal generation has moved back farther than the
8 10 years originally mentioned in the filing."(Supp.
9 Direct,Page 1,lines 21-22.)How do you respond?
10 A.As described at length in my rebuttal
11 testimony,the fact that the IRP includes FOTs means that
12 there is a resource need that is not met by existing
13 resources.If PacifiCorp can meet that need with
14 resources that are lower cost and lower risk than FOTs,
15 it is reasonable to do so.The 2017 IRP demonstrates that
16 there is a near-term resource need that can be met with
17 FOTs or with new wind investments enabled by the Aeolus-
18 to-Bridger/Anticline transmission line.The company's
19 economic analysis in this proceeding,developed using the
20 same IRP models,continue to validate results in the 2017
21 IRP.Just like the 2017 IRP,the economic analysis in
22 this proceeding demonstrates that a resource portfolio
23 that includes the proposed new wind and transmission
24 investments is the least-cost,least-risk portfolio.This
25 conclusion has been confirmed and strengthened over the
451 Link,Supp-Reb -9
Rocky Mountain Power
1 course of this case.O 2 PacifiCorp's 2017 IRP analysis compared new
3 wind and transmission investments to all other available
4 resource options,including FOTs,thermal resources,
5 other renewable resources,and additional demand-side
6 resources.The robust analysis in the IRP,which was
7 confirmed in this case,demonstrates that wind resources
8 are least-cost,least-risk even after accounting for
9 their intermittency and resulting capacity-contribution
10 value.
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
452 Link,Supp-Reb -9a
Rocky Mountain Power
1 Q.Mr.Phillips claims that shareholders not
2 customers are the ones who will benefit from the Combined
3 Projects.(Phillips Supp.Direct,page 26 line 1 to page
4 28 line 2.)How do you respond?
5 A.PacifiCorp's resource decisions consider the
6 customer costs associated with a particular resource
7 decision and do not,and should not,consider whether one
8 provider or another benefits from that decision.To be
9 very clear,PacifiCorp simply selected the lowest-cost,
10 lowest-risk resources regardless of shareholder impact.
11 2017R RFP MODELING AND RESULTS
12 Q.Monsanto,PIIC and Staff claim that the 2017R
13 RFP was unfair and biased.(See,e.g.,Phillips Supp.
14 Direct,page 13,line 21 to page 14,line 5;Mullins
15 Supp.Direct,page 17,lines 15-20;Eldred Supp.Direct,
16 page 3 lines 8-18.)What is your general response to this
17 contention?
18 A.I disagree.More importantly,these witnesses'
19 assertions are directly contrary to the conclusions of
20 the independent evaluators who monitored the 2017R RFP.
21 Both independent evaluators provided their own
22 independent analysis and carefully scrutinized the
23 process and results.And both independent evaluators
24 concluded that the 2017R RFP was transparent,fair,and
25 unbiased.
453 Link,Supp-Reb -10
Rocky Mountain Power
1 Q.Please provide more detail on the role of theO2independentevaluators.
3 A.The 2017R RFP was overseen by two independent
4 evaluators-one appointed by the Public Utility Commission
5 of Oregon ("Oregon Commission")and retained by
6 PacifiCorp,and one appointed and retained by the Public
7 Service Commission of Utah ("Utah Commission").In
8 accordance with the statutes,rules,and policies in
9 Oregon and Utah,the independent evaluator is an
10 independent expert appointed and managed
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
454 Link,Supp-Reb -10a
Rocky Mountain Power
1 by the commission (not PacifiCorp)to ensure that the RFP
2 process was conducted in a fair and unbiased manner and
3 the final shortlist projects are reasonable and
4 consistent with the modeling results used to evaluate
5 bids.
6 In the 2017R RFP,both independent evaluators
7 were involved from the beginning-providing feedback and
8 recommendations regarding the design and content of the
9 2017R RFP and actively participating in every stage of
10 the RFP.For its part,PacifiCorp ensured that the
11 independent evaluators had complete and unrestricted
12 access to all information related to the 2017R RFP and
13 kept both independent evaluators informed of developments
14 as they occurred.
15 Q.Did the independent evaluators provide an
16 assessment of PacifiCorp's benchmark resources bid into
17 the 2017R RFP (i.e.,TB Flats I and II,Ekola Flats,and
18 McFadden Ridge II)?
19 A.Yes.Because the 2017R RFP included benchmark
20 resources,both independent evaluators provided detailed
21 assessments of the benchmark bids to ensure that they
22 were reasonable and would not bias the solicitation in
23 favor of utility-owned resources.The benchmark review
24 process occurred before any other bids were received to
25 provide additional assurance that the benchmarks were not
455 Link,Supp-Reb -11
Rocky Mountain Power
1 provided an unfair advantage.Oregon's final independent
2 evaluator report,issued February 16,2018,is provided
3 as Highly Confidential and Confidential Exhibit No.67
4 ("Oregon IE Report"),and Utah's independent evaluator
5 report is Highly Confidential and Confidential Exhibit
6 No.68 ("Utah IE Report").
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
456 Link,Supp-Reb -lla
Rocky Mountain Power
1 Q.Did the independent evaluators review confirm
2 the reasonableness of the benchmark bids?
3 A.Yes.As described in my second supplemental
4 direct testimony,the Utah independent evaluator
5 concluded that (1)PacifiCorp provided detailed
6 information related to the benchmarks that exceeded
7 industry standards,(2)cost estimates were reasonable,
8 and (3)the review,assessment,and scoring of the
9 benchmark resources was conducted in a fair and equitable
10 manner with no outward perception of bias.(Link Second
11 Supp.,page 29,line 20 to page 30 line 12.)
12 The Oregon independent evaluator also conducted
I13athoroughassessmentofthebenchmarks,noting that when
14 "assessing a utility's own bids in response to the RFP,
15 our greatest concern is that the utility will incorporate
16 cost estimates that have been aggressively estimated and
17 do not characterize the costs of the project accurately."
18 (Oregon IE Report at 10.)To make its assessment,the
19 Oregon independent evaluator "looked at a detailed
20 breakdown of each of the benchmarks costs to determine if
21 any items have been improperly omitted from the cost
22 calculation,and at overall capital cost levels by
23 comparing them to publicly-available data on recent wind
24 generation capital costs."(Oregon IE Report at 10.)This
25 "comparison provided a measure of the overall
457 Link,Supp-Reb -12RockyMountainPower
1 reasonableness of the Benchmark capital costs and
2 capacity factors."(Oregon IE Report at 10.)The Oregon
3 independent evaluator ultimately found that the
4 benchmarks were acceptable based on three items:
5 o First,the benchmarks were not deliberately
6 underpriced through omission of any capital cost
7 components .
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
458 Link,Supp-Reb -12a
Rocky Mountain Power
1 o Second,the benchmark capital and operating costs
2 appeared reasonable when compared with public data
3 on U.S.wind projects.
4 o Third,the capacity factors of the benchmarks were
5 reasonable when compared with public data and were
6 supported by credible third-party analysis.
7 (Oregon IE Report at 10-11.)
8 Q.Did the independent evaluators provide any
9 overall conclusions related to the 2017R RFP?
10 A.Yes.The Oregon independent evaluator
11 recommended that the Oregon Commission approve
12 PacifiCorp's final shortlist based on the following
13 conclusions:
14 o The selected bids represent the top offers that are
15 viable under current transmission planning
16 assumptions and provide the greatest benefits to
17 ratepayers.
18 o The selected bids represent the best viable options
19 from a competitive perspective,based on the 59 bid
20 options presented.
21 o The independent evaluator's analysis confirmed that
22 the selected bids were reasonably priced and,while
23 not the lowest-cost offers,were the lowest-cost
24 offers that were viable under current transmission
25 planning assumptions.The independent evaluator's
459 Link,Supp-Reb -13
Rocky Mountain Power
1 analysis included its own cost models for each bidO2optionandareviewofPacifiCorp's models.
3 o The independent evaluator took special care to
4 confirm the selection of PacifiCorp's benchmark
5 resources.The independent evaluator confirmed the
6 accuracy of the benchmark costs and scoring.The
7 independent evaluator noted that the benchmark bids
8 were disciplined by the fact that a third-party
9 bidder
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
460 Link,Supp-Reb -13a
Rocky Mountain Power
1 submitted a competing offer for a build-transferO2agreement("BTA")for benchmark projects.
3 o The independent evaluator confirmed that the 2017R
4 RFP aligns with the 2017 IRP.
5 (Oregon IE Report at 2-3.)
6 The Utah independent evaluator also supported
7 the final shortlist projects based on the following
8 conclusions:
9 o The 2017R RFP was fair,reasonable,and generally in
10 the public interest.(Utah IE Report.)
11 o The bid evaluation and selection processes were
12 designed to lead to the acquisition of wind-
13 generated electricity at the lowest reasonable cost
14 based on the detailed state-of-the-art portfolio
15 evaluation methodology used,the steps taken to
16 achieve comparability between utility cost-of-
17 service resources and third-party firm priced bids,
18 the flexibility afforded bidders via a range of
19 eligible resource alternatives,and the attempt to
20 allow for equal terms for PPA and BTA resources.
21 (Utah IE Report at 71.)
22 o PacifiCorp's modeling demonstrates that the Combined
23 Projects "should result in significant savings for
24 customers."(Utah IE Report at 83.)Further,because
25 PTCs will flow through to customers in the first ten
461 Link,Supp-Reb -14
Rocky Mountain Power
1 years,the "near-term benefits to customers should
2 be significant."(Utah IE Report at 83.)
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
462 Link,Supp-Reb -14a
Rocky Mountain Power
1 Q.Please respond to Mr.Phillips's and Mr.
2 Eldred's claims that PacifiCorp's changes to its economic
3 modeling for purposes of developing the final shortlist
4 for the 2017R RFP unfairly biased the results.(Phillips
5 Rebuttal,page 6,lines 3-11;Eldred Supp.Direct,page
6 6,lines 11-15.)
7 A.As explained in my supplemental direct
8 testimony,when comparing bids in the 2017R RFP portfolio
9 development phase,for self-build and BTA bids,PTC
10 benefits were applied on a nominal basis rather than a
11 levelized basis to better reflect how the PTC benefits
12 flow through customer rates.(Link Supp.Direct,page 25,
13 line 11 to page 26,line 11.)This refinement better
14 aligns project costs and benefits and impacts only the
15 System Optimizer ("SO")model and Planning and Risk model
16 ("PaR")results through 2036.This modeling refinement
17 had no impact on the nominal revenue requirement
18 calculations that were also reported in my supplemental
19 direct and second supplemental direct testimony.This
20 change did not bias the results of the 2017R RFP as Mr.
21 Phillips and Mr.Eldred claim,as described in more
22 detail below.
23 Q.Did you continue to use levelized capital costs
24 during the portfolio development phase of the 2017R RFP
25 bid evaluation and selection process?
463 Link,Supp-Reb -15
Rocky Mountain Power
1 A.Yes.
2 Q.Is the treatment of PTCs and capital costs
3 consistent with how PacifiCorp has analyzed specific
4 resource decisions using its IRP models in the past?
5 A.Yes.When the company has historically
6 conducted economic analysis of specific resource
7 decisions,it treats costs that are not spread over the
8 life of the asset on a nominal basis.Typically,this
9 means that capital costs are levelized,while other
10 costs,such as operations and maintenance ("O&M")costs,
11 are nominal.The company used
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
464 Link,Supp-Reb -15a
Rocky Mountain Power
1 this approach without controversy when it requested CPCNs
2 to install emission control equipment at its Jim Bridger
3 Unit 3 and Unit 4 coal units and when it conducted
4 coal-plant analysis in its IRPs.The refined modeling
5 used here simply conforms the treatment of PTCs to the
6 treatment of other costs and benefits that are not spread
7 out over the life of the asset.
8 Q.Does PacifiCorp intend to model PTCs in this
9 manner in its IRPs?
10 A.Yes.Because modeling PTCs on a nominal basis
11 better reflects how they are treated in rates,PacifiCorp
12 intends to use this approach in future IRPs.
13 Q.Did the independent evaluators overseeing the
14 2017R RFP object to PacifiCorp's refined modeling?
15 A.No.Both independent evaluators overseeing the
16 2017R RFP were aware of PacifiCorp's decision to model
17 PTC benefits on a nominal rather than levelized basis,
18 and neither concluded that the refinement biased the
19 bid-evaluation results.In fact,the sensitivity analysis
20 requested by the independent evaluators that I described
21 in my supplemental direct testimony,(Link Supp.Direct,
22 page 11,line 1 to page 12,line 2),was designed to
23 specifically test whether the refined modeling of PTC
24 benefits unreasonably biased the resource selection.The
25 Oregon independent evaluator's report supports the
465 Link,Supp-Reb -16
Rocky Mountain Power
1 conclusions I reported regarding this sensitivity.
2 According to the Oregon independent evaluator,levelizing
3 the PTC benefits caused the SO model to select PPAs
4 instead of self-build and BTA bids.(Oregon IE Report at
5 30.)But "looking at the actual flow of cost recoveries,
6 treating both PTCs and costs as incurred"out through
7 2050,demonstrated that each portfolio produced virtually
8 identical net benefits.(Oregon IE Report at 32.)The
9 Oregon independent evaluator also noted that the PPA
10 portfolio was
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
466 Link,Supp-Reb -16a
Rocky Mountain Power
1 more expensive in the early years.(Oregon IE Report at
2 32.)Thus,PacifiCorp's refined PTC modeling did not
3 unreasonably bias the selection of resources.The Oregon
4 independent evaluator also specifically noted that the
5 PTC-modeling refinement "had no impact on winning
6 projects selected in this RFP"because several of the
7 PPAs that were selected in the sensitivity requested by
8 the independent evaluators were ultimately non-viable
9 projects.(Oregon IE Report at 5.)
10 Q.Did the Utah independent evaluator discuss this
11 treatment of PTCs in the portfolio development phase of
12 the 2017R RFP?
13 A.Yes.The Utah independent evaluator noted a
14 concern that the PTC modeling could produce a bias in
15 favor of utility-owned resources "if only a portion of
16 the capital costs associated with the benchmarks and BTAs
17 are recovered during the 20-year evaluation period,since
18 these projects have a 30-year life and capital cost
19 recovery period."(Utah IE Report at 62.)In response,
20 the Utah independent evaluator described the additional
21 analysis provided by the company,along with several
22 meetings with the independent evaluators to discuss this
23 issue.The Utah independent evaluator observed in his
24 report that PacifiCorp "refuted the basis for evaluating
25 PTCs on a levelized cost basis since [PacifiCorp]would
467 Link,Supp-Reb -17
Rocky Mountain Power
1 flow through all the customer costs in the near-term."
2 (Utah IE Report at 62.)Further,according to the Utah
3 independent evaluator,PacifiCorp "also provided a
4 30-year analysis of the costs and benefits of the initial
5 portfolio [i.e.,the portfolio with utility-owned
6 resources]and the updated portfolio [i.e.,the portfolio
7 with PPAs]...to demonstrate that the original portfolio
8 would still provide greater benefits over a 30-year
9 timeframe."(Utah IE Report at 62.)
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
468 Link,Supp-Reb -17a
Rocky Mountain Power
1 When PacifiCorp presented its final shortlist
2 to the independent evaluators,the Utah independent
3 evaluator provided additional discussion of this issue:
4 PacifiCorp also addressed two of the IEs concerns
raised in discussions on shortlist evaluation and
5 selection.The first issue dealt with theapplicationofthePTCsintheevaluation
6 methodology.As noted,PacifiCorp's analysis assumes
that the PTC inputs to the SO model would be based
7 on nominal dollar values since the actual benefits
would be flowed through to customers.The Oregon IE
8 requested a sensitivity where the PTC benefits
produced by BTA and benchmark options would be
9 levelized over the full 30-year life of the project.
A second issue raised by the IEs was whether the
10 term of the analysis through 2036 (approximately 16years)and the real levelized cost treatment for
11 capital revenue requirements adequately reflects all
the capital costs associated with utility ownership
12 options over a thirty-year project life.In
response,PacifiCorp completed an analysis of the
O 13 expected benefits and costs through 2050 comparing
the results of PacifiCorp's selected portfolio and
14 the IE sensitivity case.In its presentation,PacifiCorp concluded that the PVRR(d)benefits
15 through 2036 from the final shortlist portfolio
total $343 million and the benefits from the IE
16 Sensitivity with the PPA included in the bidportfoliototal$277 million.Through 2050,the
17 benefits from the final shortlist bid portfolio of
$223 million are closely aligned with the IE
18 Sensitivity bid portfolio that provides an estimated
$224 million in benefits through 2050.The revised
19 shortlist portfolio provides greater near-term
benefits.
20 (Utah IE Report at 65.)
21 Q.Did the Utah independent evaluator provide any
22 conclusions related to whether the self-build or BTA bids
23 received a preference as a result of PacifiCorp's
24 modeling?
25 A.Yes.The Utah independent evaluator concluded
469 Link,Supp-Reb -18
Rocky Mountain Power
1 that the results of the sensitivity (discussed above)
2 "indicated that there did not appear to be an inherent
3 advantage
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
470 Link,Supp-Reb -18a
Rocky Mountain Power
1 associated with a utility-ownership bid due to the
2 shorter evaluation period for purposes of evaluating and
3 selecting a portfolio of resources."(Utah IE Report at
4 75.)The independent evaluator explained that the "net
5 benefits approach used may eliminate the costs for a
6 longer-term resource but also eliminates the revenue side
7 of the equation,which would likely be escalating over
8 time."(Utah IE Report at 75.)Thus,the company's
9 modeling "allows for a consistent and fair evaluation of
10 bids of different technologies and terms and is a
11 reasonable tool for initial evaluation of bids."(Utah IE
12 Report at 75.)
13 Q.Mr.Phillips and Mr.Eldred claim that the use
14 of nominal pricing for the PTCs and levelized pricing for
15 the capital costs create an improper mismatch that biased
16 the resources selected in the 2017R RFP.(Phillips Supp.
17 Direct,page 6,lines 12-23;Eldred Supp.Direct,page 7
18 line 10-15.)Do you agree?
19 A.No.Moreover,neither of the independent
20 evaluators that monitored the 2017R RFP agree either,as
21 discussed above.Mr.Phillips and Mr.Eldred claim that
22 the use of nominal PTC pricing together with levelized
23 capital costs improperly reduced the net present value
24 ("NPV")of utility-owned resources making it more likely
25 that the SO model would select self-build or BTA bids.
471 Link,Supp-Reb -19
Rocky Mountain Power
1 (Phillips Supp.Direct,page 6,lines 20-21;Eldred Supp.
2 Direct,page 3,lines 8-18.).
3 The IRP models select least-cost portfolios
4 based on present-value system costs.And it would not be
5 appropriate to include nominal revenue requirement from
6 capital investments for assets having a depreciable life
7 that extends beyond the 20-year IRP study period in any
8 present-value calculation.It would only be appropriate
9 to include capital revenue requirement on a nominal basis
10 in present-value calculations when
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
472 Link,Supp-Reb -19a
Rocky Mountain Power
1 those calculations cover the full life of the proposed
2 new wind facilities.In contrast,it is appropriate to
3 consider nominal PTC benefits in the IRP models because
4 all of these benefits will be realized within the 20-year
5 time frame of those studies.This is consistent with how
6 PTCs will flow through to customer rates,and
7 consequently,PacifiCorp's IRP models appropriately
8 weight the front-end loaded PTC benefits without
9 disproportionately weighting capital costs in its
10 present-value calculations.
11 It is also disingenuous for Mr.Phillips to
12 imply that PacifiCorp's modeling change was improperly
13 motivated when he argues that the nominal revenue
14 requirement results,which have always applied PTCs on a
15 nominal basis,"most closely depict how project costs and
16 benefits will pressure rates."(Phillips Supp.Direct,
17 page 7,lines 5-7.)
18 Q.Did Mr.Phillips refute the sensitivity
19 analysis requested by the independent evaluators that was
20 presented in your supplemental direct testimony and
21 discussed at length in the independent evaluators'
22 reports?
23 A.No.
24 Q.Mr.Phillips also claims that the company
25 improperly used "real"levelization instead of uniform
473 Link,Supp-Reb -20
Rocky Mountain Power
1 levelization.(Phillips Corrected Supp.Direct,page 11,
2 lines 1-6.)Is this true?
3 A.No.I explained in my direct testimony that it
4 is important to levelize capital revenue requirement in
5 the SO model and PaR to avoid potential distortions in
6 the economic analysis of capital-intensive assets that
7 have different lives and in-service dates.(Link Direct,
8 page 26,lines 13 to page 27,line 22.)As noted by Mr.
9 Phillips,the company uses an inflation-adjusted real-
10 levelized method rather than using a uniform-
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
474 Link,Supp-Reb -20a
Rocky Mountain Power
1 levelization method.The inflation-adjusted real-
2 levelized method more closely aligns with the fact that
3 benefits for capital investments generally increase over
4 time.Consequently,and similar to the problems
5 associated with using a nominal revenue requirement
6 approach in the SO model and PaR,the application of a
7 uniform-levelization method would also create potential
8 distortions in resource selections for capital-intensive
9 assets that have different lives and in-service dates.
10 Q.Mr.Phillips suggests that the Wind Projects
11 are higher risk than PPAs because customers are insulated
12 from risks when the company executes PPAs,whereas
13 customers bear risks for utility-owned resources (e.g.,
14 the risk of construction cost over-runs).(Phillips Supp.
15 Direct page 14,lines 17-24,page 15,lines 1-18.)Mr.
16 Mullins makes a similar point.(Mullins Supp.Direct,
17 page 14,lines 7-22.)How do you respond?
18 A.I disagree.Mr.Phillips ignores the fact that
19 customers also receive upside benefits for utility-owned
20 resources that they do not receive under a PPA.For
21 example,I described in my previous testimony the
22 potential upside benefits associated with renewable
23 energy credits ("RECs"),reduced O&M costs,and increased
24 energy production.(Link Second Supp.Direct,page 15,
25 line 4 to page 16,line 13;Exhibit No.38;see also
475 Link,Supp-Reb -21
Rocky Mountain Power
1 Teply Rebuttal,page 16,lines 2-15.)In each of these
2 cases,customers will receive the increased benefits
3 because of the nature of cost-of-service ratemaking.
4 Under a PPA structure,on the other hand,project owners
5 receive all the upside benefits.PPAs can provide some
6 amount of certainty,but that certainty can both benefit
7 and harm customers.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
476 Link,Supp-Reb -21a
Rocky Mountain Power
1 Moreover,a utility self-build or BTA project
2 provides substantial long-term benefits that customers
3 never receive under a PPA.Once a PPA term expires,
4 customers walk away with nothing.If the utility owns the
5 resource,however,customers will continue to receive the
6 benefits of that resource for as long as it operates,and
7 even after the resource is no longer operational,
8 customers retain the value associated with the land and
9 facilities that have lives that extend beyond the life of
10 the generating resource.To use Mr.Phillips's example of
11 a home mortgage,under a utility-owned bid,customers pay
12 the mortgage and,after 30 years,they own the home.
13 Under a PPA,customers pay the mortgage and,after 30
14 years,customers have nothing.
15 Q.Mr.Phillips also complains that he had
16 insufficient time to review the Combined Projects.
17 (Phillips Supp.Direct,page 5,lines 11-22,page 6,
18 lines 1-2.)Do you agree?
19 A.No.Parties have had nine months to review the
20 proposed resource decision in this case.Over that time,
21 the Aeolus-to-Bridger/Anticline line has not changed in
22 any material way.While it is true that the results of
23 the 2017R RFP were disclosed fairly recently,
24 PacifiCorp's modeling has remained virtually unchanged,
25 and three of the four resources included in the company's
477 Link,Supp-Reb -22
Rocky Mountain Power
1 Q0712.The Oregon independent evaluator concluded that it
2 "understand[s]and appreciate[s]PacifiCorp's position
3 and do[es]not disagree with their transmission
4 department's findings (beyond noting the obvious fact
5 that many projects will likely drop out of the queue and
6 that actual interconnection costs will differ from
7 projected)."(Oregon IE Report at 35.)According to the
8 independent evaluator,"[t]o go forward with projects
9 that cannot meet the proposed online date
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
480 Link,Supp-Reb -23a
Rocky Mountain Power
1 without major accelerated transmission investment would
2 not seem to be the wisest course of action."(Oregon IE
3 Report at 35.)
4 Q.Is the fact the independent evaluators disagree
5 with Mr.Mullins's claim particularly notable?
6 A.Yes.While Mr.Mullins appears to rely on the
7 independent evaluators,neither support his conclusion.
8 Q.Mr.Mullins claims that the company never
9 disclosed the possibility that a bidder's interconnection
10 queue position could impact the viability of its project.
11 (Mullins Supp.Direct,page 11,lines 11-25.)Is this
12 true?
13 A.No.The fact that there was limited
14 interconnection capability was known at the beginning of
15 the 2017R RFP process,which is why PacifiCorp's initial
16 minimum bid eligibility screen included a requirement for
17 an interconnection system impact study.Commenters and
18 bidders requested that this requirement be removed from
19 the minimum bid eligibility screen to allow broader
20 participation.At the recommendation of the independent
21 evaluators,this restriction was changed to generators
22 who had begun the interconnection study processi.This
23 change increased the number of projects that could bid
24 into the 2017R RFP,which resulted in robust
25 participation,including numerous bids that were not
481 Link,Supp-Reb -24
Rocky Mountain Power
1 dependent on the construction of the Aeolus-to-Bridger/
2 Anticline line.Although transmission constraints
3 ultimately rendered some bids non-viable,neither of the
4 independent evaluators indicated that the 2017R RFP
5 process was biased or unreasonable because of this fact.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24 1 See Application of Rocky Mountain Power for Approval of
25
Solic5ita3 Hearrincæsran crW d Resour5c,l OD ek N
,2017).
482 Link,Supp-Reb -24a
Rocky Mountain Power
1 Q.Mr.Mullins also claims that the company's
2 "treatment of transmission costs"was inconsistent with
3 its communications with bidders in the period leading up
4 to the 2017R RFP.(Mullins Supp.Direct,page 12,lines
5 1-13.)Is this true?
6 A.No.Mr.Mullins confuses transmission costs
7 with interconnection costs.Mr.Mullins is correct that
8 the company informed bidders that costs associated with
9 the Aeolus-to-Bridger/Anticline transmission line,which
10 relieves congestion and enables interconnection would not
11 be assigned to individual projects.PacifiCorp did not
12 inform bidders that interconnection costs required to
13 receive interconnection service,which are specific to
14 any individual wind facility,would not be accounted for
15 in the company's bid selection and evaluation process.In
16 fact,one of the minimum bid-eligibility requirements
17 explicitly identified in the 2017R RFP clearly states
18 that bids could be disqualified if bidders failed to
19 provide interconnection costs.In specifying this minimum
20 bid-eligibility requirements,the 2017R RFP document
21 further states that cost estimates are required even if a
22 study from the transmission provider was not completed or
23 available at the time bids were due.Clearly,PacifiCorp
24 would not have established this minimum bid-eligibility
25 requirement,which if not met could disqualify a bid,if
483 Link,Supp-Reb -25
Rocky Mountain Power
1 it did not intend to use this information to evaluateO2bidssubmittedintothe2017RRFP.
3 Q.Mr.Mullins claims that the company should have
4 "either equalize[d]or mitigate[d]the bidding advantage
5 otherwise available to a bidder with a higher queue
6 position."(Mullins Supp.Direct,page 13,lines 9-14.)
7 Can PacifiCorp do what Mr.Mullins recommends?
8 A.No.As described above,such action would be
9 inconsistent with the company's OATT.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
484 Link,Supp-Reb -25a
Rocky Mountain Power
1 Mr.Mullins's apparent misunderstanding of this fact is
2 not a reflection on the accuracy of the 2017R RFP process
3 nor an indication that the process was unfair.
4 Q.Mr.Mullins claims that because "PacifiCorp
5 applied incremental transmission costs to the bids whose
6 queue position exceeded the incremental transmission
7 capacity,the higher queue position resources had no way
8 of being selected by the model."(Mullins Supp.Direct,
9 page 13,lines 15-18.)Is this true?
10 A.No.In fact,my supplemental direct testimony
11 describes the bid evaluation and selection process that
12 was completed before considering the results of the
13 interconnection restudy process.The original final
14 shortlist of bids summarized in that testimony included
15 the same projects selected to the updated final shortlist
16 summarized on my second supplemental direct testimony
17 except that the original final shortlist included the
18 McFadden Ridge II benchmark bid.In direct contradiction
19 to the claims made by Mr.Mullins,the original bid
20 evaluation and selection process performed by PacifiCorp
21 and monitored by two independent evaluators demonstrates
22 that the interconnection restudy process did not prevent,
23 in any way,the selection of projects because of their
24 interconnection queue number.
25 Q.Based on this understanding,Mr.Mullins then
485 Link,Supp-Reb -26
Rocky Mountain Power
1 argues that there is no way to know if the best resources
2 were actually selected to the final shortlist.(Mullins
3 Supp.Direct,page 13,lines 15-23.)Is this true?
4 A.No.As discussed above,Mr.Mullins's assertion
5 is contrary to basic facts and,therefore,fundamentally
6 flawed.Before considering results of the interconnection
7 restudy process,the only interconnection-related
8 constraint was the assumption that total interconnection
9 capability with the addition of the Aeolus-to-Bridger/
10 Anticline
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
486 Link,Supp-Reb -26aRockyMountainPower
1 transmission line would be 1,270 MW.The interconnection
2 restudies performed after the original final shortlist
3 was determined resulted in the following conclusions:
4 (1)That the TB Flats I and II and Cedar Springsprojectscouldinterconnectwiththeadditionof the
5 Aeolus-to-Bridger/Anticline transmission line and no
other elements of the company's long-term plan;
6
(2)That McFadden Ridge II could not interconnect
7 without additional elements of the company's
long-term transmission plan,namely Gateway West and
8 Gateway South;and
9 (3)That additional interconnection capability would
be created with the addition of the Aeolus-to-
10 Bridger/Anticline transmission line,which allowed
McFadden Ridge II to be replaced with Ekola Flats.
11
12 Rather than limiting the outcome of the 2017R
13 RFP,the interconnection restudy process provided new
14 information that allowed the inclusion of a more economic
15 project because of increased interconnection capability.
16 The only thing that was preventing the models from
17 choosing Ekola Flats over McFadden Ridge II in
18 development of the original final shortlist was the
19 original 1,270-MW limit on interconnection capability.
20 Mr.Mullins also ignores the fact that the
21 interconnection considerations resulted in PacifiCorp
22 proposing to replace only one shortlist bid,with all
23 other shortlist bids remaining unchanged.More
24 specifically,the interconnection restudy process
25 provided new,more updated information that caused
487 Link,Supp-Reb -27
Rocky Mountain Power
1 PacifiCorp to exclude the McFadden Ridge II benchmark
2 bid.While the new and more updated information from the
3 interconnection restudy process demonstrates that
4 projects with an interconnection queue number greater
5 than QO712 would not be viable at this time,this
6 information had no impact on selection of the best
7 resources other than allowing the more economic Ekola
8 Flats benchmark bid to replace the McFadden Ridge II
9 benchmark bid.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
488 Link,Supp-Reb -27a
Rocky Mountain Power
1 This single shortlist change resulting from
2 interconnection restudies can hardly be described as
3 interfering with the value of the company's entire
4 competitive solicitation process.Allowing participation
5 without regard to interconnection queue position or study
6 status resulted in a robust competitive solicitation,
7 including numerous bids that were not enabled by
8 construction of the Aeolus-to-Bridger/Anticline
9 transmission line.Interconnection considerations,based
10 on the most current and up-to-date information,causing
11 the replacement of a single project did not unravel those
12 benefits.What Mr.Mullins really appears to be arguing
13 is that the original (pre-interconnection considerations)
14 shortlist should have included lower-queued projects for
15 other,non-interconnection-related reasons,not that
16 interconnection queue considerations caused those
17 projects to be eliminated from the shortlist in the first
18 place.These arguments should be disregarded because they
19 are inconsistent with the results of the economic
20 evaluation of the bids.
21 Q.Mr.Mullins claims that PPA bids were better
22 alternatives and that these alternatives were eliminated
23 based only on their interconnection queue position.
24 (Mullins Supp.Direct,page 13,line 18 to page 14,line
25 6.)Is this true?
489 Link,Supp-Reb -28
Rocky Mountain Power
1 A.No.As described above,the preliminary
2 shortlist of bids that was selected before the
3 interconnection restudy process was finalized included
4 virtually the same resources that are included in the
5 updated final shortlist.Moreover,as discussed in my
6 supplemental direct testimony,at the request of the
7 independent evaluators,PacifiCorp conducted a
8 sensitivity to specifically test whether the highest
9 performing PPAs bid into the RFP could displace the bids
10 selected to the preliminary shortlist.This sensitivity
11 study,
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
490 Link,Supp-Reb -28a
Rocky Mountain Power
1 developed before the interconnection restudy process was
2 completed,show that the PPAs were not superior resource
3 selections.
4 ECONOMIC ANALYSIS
5 Q.Mr.Phillips argues that the Commission should
6 give greater weight to the nominal revenue requirement
7 analysis,which was performed through 2050.(Phillips
8 Supp.Direct,page 7,lines 1-13.)Mr.Mullins agrees.
9 (Mullins Supp.Direct,page 18,lines 11-20.)Do you
10 agree?
11 A.No.Both types of analysis-the system modeling
12 results through 2036 and the nominal revenue requirement
13 results through 2050-are useful in assessing the
14 economics of the Combined Projects.The system modeling
15 results provide a view of economic analysis that is
16 consistent with the planning period and approach used to
17 identify a least-cost,least-risk preferred portfolio in
18 the IRP.This type of analysis was used to identify new
19 wind and transmission projects as an element of
20 PacifiCorp's least-cost,least-risk plan in the 2017 IRP
21 and has been used to evaluate past resource acquisitions
22 and plant investments.For instance,the same IRP models
23 used to evaluate the Combined Projects in this
24 proceeding,configured to simulate PacifiCorp's system
25 over a 20-year time frame with the application of
491 Link,Supp-Reb -29
Rocky Mountain Power
1 levelized capital costs,were used to support the
2 company's acquisition of the Chehalis combined-cycle
3 plant,support selection of the Lake Side 2
4 combined-cycle plant through an RFP process,and to
5 support the company's Wyoming CPCN application for the
6 installation of selective catalytic reduction equipment
7 at Jim Bridger Unit 3 and Unit 4.
8 The nominal revenue requirement analysis
9 provides a sense of how the Combined Projects might
10 impact customer rates,relative to alternative resource
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
492 Link,Supp-Reb -29a
Rocky Mountain Power
1 procurement scenarios,over time.While an extension of
2 system benefits associated with the Combined Projects
3 through 2050 enables a present-value revenue-requirement
4 differential ("PVRR(d)")to be calculated,as with any
5 long-term study,longer-term results are increasingly
6 more difficult to project.Moreover,I noted in my second
7 supplemental direct testimony that the long-term
8 extrapolation of system benefits used in the nominal
9 revenue requirement analysis is conservative because the
10 extrapolation approach yields projected benefits that do
11 not reach the levels observed in the model in 2036 until
12 2047.
13 Q.Mr.Mullins claims that there is no reason to
14 analyze levelized costs at all in this case because the
15 "[u]se of levelized costs might be appropriate when
16 considering the costs of multiple different resources in
17 a capital expansion model and where the study period does
18 not align with the useful life of the resource."But,
19 according to Mr.Mullins,the company is not doing that
20 in this case.(Mullins Supp.Direct,page 18,lines
21 14-20.)Is this true?
22 A.No.Mr.Mullins appears to fundamentally
23 misunderstand PacifiCorp's modeling used to both select
24 the bids to the final shortlist and to evaluate the
25 customer benefits of the Combined Projects.Mr.Mullins
493 Link,Supp-Reb -30
Rocky Mountain Power
1 implies that the company has somehow hardwired the Wind
2 Projects into its models and then measured the benefits
3 using the SO model and PaR without considering the costs
4 of multiple resource alternatives.To the contrary,in
5 every price-policy scenario,the company used the SO
6 model (i.e.,Mr.Mullins's referenced "capital expansion
7 model")to determine which,if any,of the bids submitted
8 into the 2017R RFP were selected as an element of the
9 least-cost mix of resources over a 20-year study period.
10 Wind bids were forced to compete with all other resource
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
494 Link,Supp-Reb -30a
Rocky Mountain Power
1 options (including solar resources in the solar
2 sensitivity discussed below)and were selected only if
3 they were least-cost,which is precisely how the company
4 conducts its IRP modeling.In every scenario studied,the
5 SO model selected the Wind Projects.
6 Q.Mr.Phillips claims that the economics of the
7 Combined Projects are no better than when originally
8 proposed.(Phillips Supp.Direct,page 45,lines 1-5.)Do
9 you agree?
10 A.No.Mr.Phillips concedes that PacifiCorp's
11 updated nominal revenue requirement analysis shows that
12 the benefits under the medium natural gas,medium CO2
13 scenario increased from $137 million to $167 million-an
14 increase of over 20 percent.(Phillips Supp.Direct,page
15 46,line 3-7.)Mr.Phillips's claim that the company's
16 testimony was "erroneous and misleading"on this point is
17 unsupported.
18 Q.Mr.Phillips claims that the updated nominal
19 revenue requirement analysis shows that the NPV savings
20 over the first 20 years is lower than in the company's
21 original analysis.(Phillips Supp.Direct,page 46,line
22 8 to page 47,line 16.)How do you respond?
23 A.It is not surprising that the updated nominal
24 revenue requirement analysis,reflecting winning bids
25 from the 2017R RFP and changes in federal tax law,
495 Link,Supp-Reb -31RockyMountainPower
1 produces a different net-benefit profile than what was
2 shown in my original analysis,which reflected proxy wind
3 resources and higher federal tax rates for corporations.
4 Importantly,and as stated in my second supplemental
5 direct testimony,with reduced costs from the winning
6 bids from the 2017R RFP,the Combined Projects generate
7 substantial near-term benefits despite a reduction in PTC
8 benefits associated with changes in federal tax law,and
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
496 Link,Supp-Reb -31a
Rocky Mountain Power
1 generate net benefits in 23 years out of the 30 years
2 that the proposed owned-wind resources are assumed to
3 operate.(Link Second Supp.,page 20,lines 2-9.)
4 Q.Mr.Phillips also claims that the updated
5 nominal revenue requirement analysis shows that the
6 majority of the customer benefits occur later and
7 therefore the Combined Projects are now riskier as
8 compared to the original filing.(Phillips,Supp.Direct,
9 page 48,lines 1-10.)Is this a fair metric for measuring
10 risk?
11 A.No.As noted above,Mr.Phillips is simply
12 stating that updated nominal revenue-requirement analysis
13 produces a different net-benefit profile than what was
14 shown in my original analysis,which primarily reflects
15 changes in Wind Project costs and associated network
16 upgrades,federal income tax rates applicable to
17 corporations,and updated system assumptions (i.e.,more
18 current price-policy scenario assumptions and an updated
19 load forecast).This does not mean that project risks
20 have increased.In fact,project risks have been
21 materially reduced since the company's original filing.
22 For instance,when the company made its initial filing,
23 it was uncertain whether federal tax-reform legislation
24 would be introduced and how that legislation might impact
25 PTC benefits,which are critical to the economic benefits
497 Link,Supp-Reb -32RockyMountainPower
1 of the Combined Projects.Similarly,at that time,the
2 company had not yet issued the 2017R RFP and had not
3 received firm pricing for wind resource bids solicited
4 through a competitive bidding process.At this time,
5 these uncertainties have been eliminated and replaced
6 with known tax law changes and firm,competitive wind
7 resource pricing,and the updated economic analysis of
8 the Combined Projects continues to demonstrate that these
9 investments will generate substantial customer benefits.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
498 Link,supp-Reb -32a
Rocky Mountain Power
1 Q.Mr.Phillips and Mr.Eldred claim that the only
2 way the company can claim a $167 million customer net
3 benefit using its nominal revenue-requirement analysis is
4 to include a terminal value benefit in 2050 that was not
5 included in the original analysis (Phillips Supp.Direct,
6 page 49,line 1-7:Eldred Supp.Direct,page 9 lines
7 1-8.)How do you respond?
8 A.It is reasonable to include a terminal value
9 benefit for projects where the company retains control of
10 the site at the end of the asset life and,contrary to
11 Mr.Phillips's claim,the company's analysis does not
12 rely heavily on 2050 results to demonstrate a positive
13 net benefit.Even if the terminal value were completely
14 eliminated,which would not be appropriate,the Combined
15 Projects would still produce $124 million in net customer
16 benefits before accounting for the conservative
17 extrapolation methodology used by the company,
18 conservative CO2 emissions cost savings,potential upside
19 in O&M cost savings,and upside from renewable energy
20 credit ("REC")potential revenue.
21 Q.Why did the company include a terminal value
22 benefit for utility-owned resources?
23 A.The terminal value benefit recognizes the fact
24 that at end of a utility-owned resource's life,there is
25 residual value that accrues to customers.For a PPA,the
499 Link,Supp-Reb -33
Rocky Mountain Power
1 terminal value accrues to the project owner,not
2 customers.That terminal value includes the facilities
3 supporting the resources,like transmission facilities,
4 that have longer useful lives and,in the case of
5 generation tied to natural resources such as wind
6 resources,there is inherent value in the site
7 itself-particularly resources located in high-capacity-
8 factor geographic areas like eastern Wyoming.These
9 high-value,renewable-resource
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
500 Link,supp-Reb -33a
Rocky Mountain Power
1 locations are often scarce or unique in their suitability
2 for generation permitting and construction,as well as
3 proximity to transmission.
4 Q.Did the independent evaluators comment on the
5 inclusion of the terminal value benefit in the 2017R RFP
6 modeling?
7 A.Yes.The Utah independent evaluator observed
8 that the terminal value is typically.equal to the net
9 salvage value of the resource,but for wind resources
10 there are additional "assets associated with the wind
11 site,such as land,site characteristics and generation
12 interconnection and transmission facilities"that may
13 provide additional value.(Utah IE Report at 33.)The
14 independent evaluator explained that the terminal value
15 benefits reflected the depreciated value of assets that
16 have not fully depreciated at the end of the assumed
17 30-year life for the wind facilities,such as
18 transmission assets,and the appreciated value of other
19 elements of the project that remain at the end of the
20 30-year life,such as development rights.
21 The Oregon independent evaluator also noted
22 that the terminal value was included to account for the
23 fact that the company would own the site at the end of
24 the project's useful life.(Oregon IE Report at 15.)
25 Q.Did the independent evaluators comment on the
501 Link,Supp-Reb -34
Rocky Mountain Power
1 size of the terminal value benefit?
2 A.Yes.The Utah independent evaluator noted that
3 the terminal value was "relatively low."(Utah IE Report
4 at 42.)Likewise,the Oregon independent evaluator found
5 that the "terminal value adders were fairly small."
6 (Oregon IE Report at 17.)
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
502 Link,Supp-Reb -34a
Rocky Mountain Power
1 Q.Mr.Phillips questions the terminal value
2 calculations included in the company's analysis,claiming
3 this benefit is speculative.(Phillips Supp.Direct,page
4 52,line 8-11.)How do you respond?
5 A.I disagree.Notably,as described above,both
6 of the independent evaluators confirmed and validated the
7 company's bid-selection and evaluation process,and
8 proposed no adjustment.
9 Q.Does Mr.Mullins challenge the company's
10 terminal value used in the economic modeling?
11 A.Yes.While Mr.Mullins does not challenge the
12 magnitude of terminal values associated with the new wind
13 projects,and does "not necessarily disagree"that
14 utility-owned resources provide a terminal value that
15 PPAs do not,he argues that,with regard to the
16 transmission project,the company needed to also consider
17 the ongoing capital maintenance and investment required
18 to achieve the terminal value assumed in the economic
19 analysis.(Mullins Supp.Direct,page 19,lines 9-14.)
20 PacifiCorp's analysis recognizes that the
21 useful life of the transmission project extends more than
22 30 years beyond the useful life of the new wind projects.
23 Mr.Mullins is correct that costs of the transmission
24 project are not included beyond 2036 in the system
25 modeling,nor are they included beyond 2050 in the
503 Link,Supp-Reb -35
Rocky Mountain Power
1 nominal revenue requirement analyses .However,the
2 company also did not include any incremental benefits of
3 the proposed transmission project beyond 2036 in the
4 levelized view,or beyond 2050 in the nominal view.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
504 LR kk,pp-aR -a
1 Q.Mr.Phillips argues that the Combined Projects
2 are higher risk now,compared to the original filing,
3 because of the changes in the federal corporate tax rate,
4 lower load forecasts,and low natural-gas prices.
5 (Phillips Supp.Direct,page 51,lines 3-14.)How do you
6 respond?
7 A.I disagree.It is true that each of the factors
8 identified by Mr.Phillips decreased customer benefits.
9 But the decrease associated with these factors was more
10 than offset by other factors,such as lower installed
11 capacity costs associated with the Wind Projects.In
12 total,when all of the changes are considered,the
13 company's analysis shows that risks have decreased and
14 customer benefits have increased since the initial
15 filing.
16 Q.Mr.Phillips claims that the company has not
17 assessed the risk associated with wind variability.
18 (Phillips Corrected Supp.Response,page 53,line 1-7.)
19 Is this true?
20 A.No.PacifiCorp performed robust risk analysis
21 of wind variability,including the retention of a
22 third-party expert to verify the wind-production
23 estimates for every bid selected to the initial shortlist
24 in the 2017R RFP.Mr.Chad A.Teply also provided
25 testimony explaining that the company's existing wind
505 Link,Supp-Reb -36
Rocky Mountain Power
1 projects in the Medicine Bow area of Wyoming have
2 out-performed pre-construction estimates.(Teply
3 Rebuttal,page 16,line 9 to page 17,line 6.)
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
506 Link,Supp-Reb -36a
Rocky Mountain Power
1 Q.Mr.Phillips claims that there is a risk that
2 future qualifying facility ("QF")development may cause
3 curtailment of the Wind Projects,thereby reducing their
4 production.(Phillips Corrected Supp.Response,page 54,
5 line 7-21.)Is this a reasonable concern?
6 A.No.Mr.Phillips describes curtailment risk
7 associated with a 320-MW QF project in eastern Wyoming
8 that has an executed interconnection agreement.This
9 interconnection agreement requires additional
10 transmission upgrades,which includes all of Energy
11 Gateway West and Energy Gateway South,scheduled to occur
12 in 2024.Mr.Phillips then correctly explains that the
13 company did not reserve interconnection capacity for this
14 QF project when performing its economic analysis of the
15 Combined Projects.
16 PacifiCorp did not reserve any of the
17 incremental interconnection capability associated with
18 the Aeolus-to-Bridger/Anticline transmission line for
19 this particular 320-MW QF project because the project can
20 only interconnect if the transmission upgrades identified
21 in this QF project's executed interconnection agreement
22 are built,including all of Energy Gateway West and
23 Energy Gateway South.The upgrades are required for this
24 320-MW QF project to proceed would increase
25 interconnection capacity in the region and would increase
507 Link,Supp-Reb -37
Rocky Mountain Power
1 the transfer capability out of eastern Wyoming.
2 Consequently,if this QF project moves forward,it would
3 mean that all of Energy Gateway West and Energy Gateway
4 South have been built,which would mitigate,not
5 increase,any potential curtailment of the proposed Wind
6 Projects.
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
508 Link,Supp-Reb -37a
Rocky Mountain Power
1 Q.Mr.Phillips is concerned that the company has
2 not thoroughly evaluated the Combined Projects,(Phillips
3 Supp.Direct,page 5,lines 21-22),and faults the
4 company for not conducting any capital cost over-run or
5 load forecast sensitivities in its updated analysis.
6 (Phillips Supp.Direct,page 56,lines 3-8.)How do you
7 respond?
8 A.The company's economic analysis in this docket
9 has been thorough and extensive.The updated economic
10 analysis summarized in my second supplemental direct
11 testimony alone includes 26 SO model simulations and 26
12 PaR simulations.Each PaR simulation considers 50
13 different iterations of system performance with
14 variations in stochastic variables,which includes
15 variations in load.Accounting for the stochastic system
16 simulations performed using PaR,the economic analysis
17 summarized in my second supplemental direct testimony
18 represents over 1,300 simulations of PacifiCorp's system
19 over a 20-year forecast time frame.Through these
20 studies,the company has assessed how the net benefits of
21 the Combined Projects are affected by the proposed wind
22 repowering project,solar resource opportunities,
23 selection of alternative wind-turbine equipment,
24 alternative natural-gas price assumptions,alternative
25 CO2 price assumptions,and application of alternative
509 Link,Supp-Reb -38
Rocky Mountain Power
1 assumptions for O&M cost and REC revenues.O 2 It is also important to recognize that the
3 winning bids selected to the 2017R RFP final shortlist
4 are based on firm-pricing proposals through a competitive
5 solicitation process with oversight from two independent
6 evaluators.The company also provided evidence that its
7 prior two large-scale transmission projects were 19
8 percent and six percent under budget.(Vail Rebuttal,
9 page 15,Table 1.)
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
510 Link,Supp-Reb -38a
Rocky Mountain Power
1 Q.Are all of the risks identified by Mr.Phillips
2 asymmetrical,i.e.,can the risks only run against
3 customer interests?
4 A.No.Variability of the factors described by Mr.
5 Phillips can favor customers too.Project performance can
6 be better than expected,as Mr.Teply indicates has
7 occurred.Capital costs can be lower than expected,as
8 Mr.Vail indicates has occurred.And ongoing O&M costs
9 can be less than expected,as I previously discussed.
10 Q.Mr.Eldred calculates the percentage increase
11 in capital costs that would eliminate net benefits for
12 each price-policy scenario.(Edred Supp.Direct,page 16
13 to page 18,line 12).Are Mr.Edred's calculations
14 correct?
15 A.No.Mr.Eldred's calculations have two errors.
16 First,he includes run-rate O&M costs for the Aeolus-to-
17 Bridger/Anticline transmission line when calculating the
18 percentage increase in capital costs that would result in
19 a break-even PVRR(d).Second,he does not account for the
20 transmission revenue credits from the Aeolus-to-Bridger/
21 Anticline transmission line,which would increase if
22 capital costs increase.These two errors understate the
23 increase in capital costs that would result in a
24 break-even PVRR(d)by approximately $9 million in each
25 price-policy scenario.Consequently,in the medium
511 Link,Supp-Reb -39
Rocky Mountain Power
1 natural gas,medium CO2 price-policy scenario capital
2 costs would need to increase by $205 million
3 (approximately 9.1 percent)to eliminate net benefits,
4 not the $196 million (approximately 8.7 percent)figure
5 calculated by Mr.Eldred.
6 Q.Is there also a risk that natural-gas prices
7 will be higher than expected?
8 A.Yes.In my direct testimony,I noted that the
9 low natural-gas price forecast assumed stagnant liquefied
10 natural gas ("LNG")exports.(Link Direct,page 32,line
11 13 to page 33,line 2.)According to the U.S.Energy
12 Information Administration's Annual Energy
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
512 Link,Supp-Reb -39a
Rocky Mountain Power
1 Outlook 2018 ("AEO 2018"),published on February 6,2018,
2 the United States is now a net exporter of natural gas
3 and its reference case shows increased LNG exports in the
4 coming years as additional terminals come into service.
5 The increased exports will likely put pressure on future
6 natural gas prices,meaning that over the next 32 years
7 (i.e.,until 2050),it is unlikely that natural gas
8 prices will remain as low as the low case used here.
9 Q.Mr.Yankel claims that the low natural-gas
10 price scenarios are the most likely to occur.(Yankel
11 Supp.Direct,page 6,line 18 to page 9,line 14.)Do you
12 agree?
13 A.No.PacifiCorp's medium natural-gas price
14 scenarios are the most likely to occur.These forecasts
15 are based on observed market forward prices and base-case
16 projections from third-party experts.Moreover,for the
17 reasons discussed above,pressure on future natural gas
18 prices may actually be higher than what is assumed in the
19 low natural-gas price scenario.
20 Q.Is there a price risk associated with long-term
21 PPA contracts?
22 A.Yes.Recently in the context of avoided-cost
23 pricing,the Commission reduced QF contract terms to two
24 years.The Commission ruled:"Based upon our record,we
25 find that 20-year contracts exacerbate overestimations to
513 Link,Supp-Reb -40
Rocky Mountain Power
1 a point that avoided cost rates over the long-term period
2 are unreasonable and inconsistent with the public
3 interest.We find shorter contracts reasonable and
4 consistent with federal and state law for multiple
5 reasons.First,shorter contracts have the potential to
6 benefit both the QF and the ratepayer.By adjusting
7 avoided cost rates more frequently,avoided costs become
8 a truer reflection of the actual costs avoided by the
9 utility and allow QFs and ratepayers to benefit from
10 normal fluctuations in the market."In the Matter of
11 Idaho Power Co.'s
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
514 Link,Supp-Reb -40a
Rocky Mountain Power
1 Petition to Modify Terms and Conditions of PURPA Purchase
2 Agreements,et al.,Case Nos.IPC-E-15-01,AVU-E-15-01,
3 PAC-E-15-03,Order No.33357 at 23 (Aug.20,2015).
4 The same is true here-there is no bias in the
5 medium natural-gas price forecast and therefore,actual
6 future natural-gas prices are as likely to be higher as
7 they are lower.However,all of the parties'testimony
8 has been very asymmetrical only focusing on the risk
9 associated with the company's proposal and ignoring the
10 fact that seven of the nine scenarios demonstrate that
11 customers will benefit from the Combined Projects.
12 Q.Do Mr.Phillips and Mr.Yankel continue to rely
13 on the low natural-gas price scenario?
14 A.Yes.Mr.Phillips reiterated that the low
15 natural-gas price forecast is the "status quo"and
16 appears to continue to rely heavily on the low
17 natural-gas price scenarios for his analysis.(Phillips
18 Supp.Direct,page 20,lines 17-18.)Mr.Yankel stated
19 that "the two scenarios where customers are worse off,
20 have the most likelihood of occurring."(Yankel Supp.
21 Direct page 2,lines 3-4.)This is despite the lack of
22 bias in the company's price forecasts,as noted above,
23 and assumes that current "price-floor"conditions will
24 persist for the next 32 years.
25 Q.Mr.Mullins claims that PacifiCorp's economic
515 Link,Supp-Reb -41
Rocky Mountain Power
1 analysis has not taken into consideration declining
2 market prices.(Mullins Supp.Direct,page 22,lines
3 2-8.)Is this true?
4 A.No.Mr.Mullins correctly notes that
5 PacifiCorp's December 2017 official forward price curve
6 ("OFPC")reflects 72 months of market forwards followed
7 by 12 months of a forwards-fundamental blend that
8 transitions to a pure fundamentals-based forecast in
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
516 Link,Supp-Reb -41a
Rocky Mountain Power
1 month 85.Consequently,the first seven years of the
2 December 2017 OFPC reflects or is influenced by observed
3 market forwards as of December 29,2017.This was the
4 most current OFPC available at the time the company was
5 finalizing its 2017R RFP bid evaluation and selection
6 process and is representative of current market
7 conditions.
8 Q.Mr.Mullins goes on to explain that the company
9 relies on a third-party forecast from November 21,2017,
10 and is concerned that the December OFPC does not consider
11 the effects of tax reform.(Mullins Supp.Direct,page
12 23,lines 8-17.)How do you respond?
13 A.As noted above,the OFPC reflects or is
14 influenced by observed market prices through the first
15 seven years (through 2024).The December 2017 OFPC that
16 the company used in its medium price-policy scenarios
17 reflects market forwards as of December 29,2017,which
18 is after President Trump signed the tax reform bill.This
19 means that through the first seven years of the December
20 2017 OFPC,observed prices account for tax reform.
21 Moreover,I have reviewed observed forward prices,which
22 are updated each trading day,throughout December 2017,
23 and there is no indication that would suggest there was
24 any material change in forward prices that coincide with
25 the timing of when tax reform legislation was passed by
517 Link,Supp-Reb -42
Rocky Mountain Power
1 Congress and subsequently signed by President Trump.
2 Consequently,I would not expect a material change in
3 forecasted prices beyond the first seven years of the
4 December 2017 OFPC when prices are based on a third-party
5 forecast.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
518 Link,Supp-Reb -42a
Rocky Mountain Power
1 Q.Mr.Mullins claims that forward market prices
2 for calendar year 2022 in the December 2017 OFPC declined
3 by approximately 35 percent relative to prices in the
4 June 2017 OFPC,which were used in PacifiCorp's original
5 economic analysis (Mullins Supp.Direct,page 24,lines
6 1-3.)Is this accurate?
7 A.No.The average Henry Hub natural gas price for
8 calendar-year 2022 from the June 2017 OFPC is
9 $2.92/MMBtu.The average Henry Hub natural gas price for
10 calendar-year 2022 from the December 2017 OFPC,which
11 reflects observed market prices as of December 29,2017
12 (not January 2,2018 as claimed by Mr.Mullins),is
13 $2.89/MMBtu.By my calculations,this reflects a
14 one-percent reduction in prices.This is a far cry from
15 the 35-percent reduction calculated by Mr.Mullins.
16 Q.Mr.Mullins asserts that year-on-year changes
17 in prices from the December OFPC over the 2023-2026 time
18 frame is possibly due to use of a stale forecast.
19 (Mullins Supp.Direct,page 24,lines 8-10.)How do you
20 respond?
21 A.The reason for an increase in prices over this
22 time frame is not caused by the use of a stale forecast.
23 As described above,PacifiCorp used the most current OFPC
24 available at the time the company was finalizing its
25 2017R RFP bid evaluation and selection process,and it is
519 Link,Supp-Reb -43
Rocky Mountain Power
1 representative of current market conditions.The increase
2 in prices over the 2023-2026 time frame is consistent
3 with an expectation of increased LNG exports.As I noted
4 earlier in my testimony,according to the AEO 2018,
5 published on February 6,2018,the United States is now a
6 net exporter of natural gas and its reference case shows
7 increased LNG exports in the coming years as additional
8 terminals come into service.The increased exports is
9 expected to put pressure on future natural gas prices.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
520 Link,Supp-Reb -43a
Rocky Mountain Power
1 Q.Mr.Mullins estimates that had PacifiCorp used
2 more current price forecasts,present-value net benefits
3 would be reduced by approximately $359 million.(Mullins
4 Supp.Direct,page 26,lines 2-5.)Is this analysis
5 reasonable?
6 A.No.Mr.Mullins did not supply work papers with
7 his testimony,so I was not able to validate the accuracy
8 of his calculations.Nonetheless,Mr.Mullins's
9 description of his calculations highlights methodological
10 deficiencies.It is not clear from Mr.Mullins's
11 testimony whether he calculated his $359 million
12 adjustment through 2036 or through 2050.Based on his
13 statement that this adjustment would eliminate net
14 benefits in the low natural gas,zero CO2 price-policy
15 scenario,I assume his calculation is based on benefits
16 calculated through 2036.
17 From what I can tell,Mr.Mullins calculated an
18 implied market heat rate off of the December 2017 OFPC by
19 dividing Palo Verde electricity prices by Henry Hub
20 natural gas prices.He produced an alternative
21 electricity price forecast by multiplying this implied
22 market heat rate derived from the December 2017 OFPC by a
23 lower natural gas price forecast.He then states that he
24 multiplied the difference in Palo Verde prices (the
25 difference between prices in the December 2017 OFPC and
521 Link,Supp-Reb -44
Rocky Mountain Power
1 his estimated lower price forecast)by the volume of wind
2 energy associated with the Combined Projects to arrive at
3 his estimate of reduced benefits.
4 Assuming I understand Mr.Mullins's methodology
5 correctly,his oversimplified approach grossly overstates
6 the impact of a reduced natural gas price forecast on the
7 net benefits from the Combined Projects.This methodology
8 assumes that the energy benefits from the Combined
9 Projects are valued at the Palo Verde market curve.This
10 is simply not the case.In the company's analysis,the
11 energy benefits from the Combined
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
522 Link,Supp-Reb -44a
Rocky Mountain Power
1 Projects are heavily driven by avoided system fuel costs,
2 particularly coal costs,through the 2027 time frame.
3 Over this period,market prices have less of an impact on
4 system energy benefits than over later time frames (i.e.,
5 beyond 2027).This is a result of system constraints that
6 limit access to markets,particularly prior to those
7 years where coal unit retirements are assumed.
8 For instance,in the company's economic
9 analysis that uses medium natural gas,medium CO2
10 price-policy assumptions,system energy benefits over the
11 2021-2027 time frame (before the Dave Johnston coal plant
12 is assumed to retire)average $23.40/MWh.In the low
13 natural gas,zero CO2 price-policy scenario,system
14 energy benefits average $20.13/MWh (approximately 14
15 percent lower than in the medium natural gas,medium CO2
16 price-policy scenario).Henry Hub natural gas prices over
17 this time frame average $3.54/MMBtu in the medium natural
18 gas,medium CO2 price-policy scenario and $2.69/MMBtu in
19 the low natural gas,zero CO2 price-policy scenario
20 (approximately 24 percent lower than in the medium
21 natural gas,medium CO2 price-policy scenario).These
22 results demonstrate that a change in natural gas price
23 assumptions does not proportionately impact system energy
24 benefits from the Combined Projects.
25 Clearly,it is inappropriate to assume that a
523 Link,Supp-Reb -45
Rocky Mountain Power
1 dollar-for-dollar change in price curve assumptions
2 equates to a dollar-for-dollar change in system energy
3 benefits.This approach,which was used by Mr.Mullins,
4 will grossly overstate the impact of a change in natural
5 gas price assumptions on net benefits from the Combined
6 Projects,and consequently,Mr.Mullins's estimate and
7 associated conclusions are not valid.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
524 Link,Supp-Reb -45a
Rocky Mountain Power
1 Q.Did Mr.Mullins present all of the natural gas
2 price forecasts he received from the company through
3 discovery in Confidential Figure 3 of his supplemental
4 rebuttal testimony?
5 A.No.PacifiCorp also provided an update to the
6 November 2017 natural gas price forecast that was used in
7 the company's December 2017 OFPC.This updated forecast
8 was issued on February 18,2018 and is actually slightly
9 higher than the November 2017 forecast used in the
10 company's economic analysis.However,Mr.Mullins omitted
11 this forecast in Confidential Figure 3 of his
12 supplemental rebuttal testimony.
13 Q.Mr.Mullins restates his opinion that market
14 prices have consistently been lower than utilities'
15 long-term forecasts.(Mullins Supp.Direct,page 26,
16 lines 15-17.)How do you respond?
17 A.Assuming Mr.Mullins's reference to the term
18 "market prices"is synonymous with "actual prices,"I
19 agree that market forwards exceeded actual prices over
20 the 2010-2015 time frame,when structural expansion in
21 natural gas supply outpaced market expectations.However,
22 beyond 2015,the ratio of forward market prices to
23 actuals has come down significantly and now hovers near
24 one.Simply stated,market expectations are catching up
25 with supply capabilities.This is reasonable given that
525 Link,Supp-Reb -46
Rocky Mountain Power
1 technological progress and efficiencies in natural gas
2 production continue to increase,but at a slower rate.As
3 such,historical variances between forward market prices
4 and spot prices are not good indicators of future price
5 developments.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
526 Link,Supp-Reb -46a
Rocky Mountain Power
1 SOLAR RESOURCE SENSITIVITY
2 Q.Please summarize the solar resource sensitivity
3 provided in your previous testimony.
4 A.My second supplemental direct testimony
5 provided robust modeling results through 2036 using the
6 SO model and PaR based on preliminary bid analysis from
7 the 2017S RFP.(Link Second Supp.Direct,page 21,line 4
8 to page 25,line 3.)Those modeling results supported two
9 important conclusions.
10 First,solar PPAs provided fewer benefits than
11 the Combined Projects under the medium natural gas,
12 medium CO2 price-policy scenario,and slightly fewer
13 benefits under the low natural gas,zero CO2 price-policy
14 scenario using PaR,and slightly more benefits under the
15 low natural gas,zero CO2 price-policy scenario using the
16 SO model.In other words,under the medium natural gas,
17 medium CO2 price-policy scenario,the Combined Projects
18 are superior,and under the low natural gas,zero CO2
19 price-policy scenario the Combined Projects are roughly
20 equal to the solar PPAs.
21 Second,when analyzed together,the Combined
22 Projects and solar PPAs produced greater customer
23 benefits under both the medium natural gas,medium CO2
24 price-policy scenario and low natural gas,zero CO2
25 price-policy scenario relative to scenarios where either
527 Link,Supp-Reb -47
Rocky Mountain Power
1 the Combined Projects or solar PPAs are procured on their
2 own.
3 Significantly,none of wind or solar bids were
4 hard coded into the model,and when solar bids were
5 selected in the models,they did not displace the wind
6 bids.These conclusions indicated that it is not a
7 question of whether the company should pursue the
8 Combined Project or the solar PPAs,but rather a question
9 of whether the company should pursue the Combined
10 Projects and the solar PPAs.
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
528 Link,Supp-Reb -47a
Rocky Mountain Power
1 Q.Did the company provide the solar sensitivityO2totheindependentevaluatorswhomonitoredthe2017R
3 RFP?
4 A.Yes.The Oregon independent evaluator noted in
5 his report:"In all cases the combination of solar and
6 shortlisted [wind]resources provided more net benefits."
7 (Oregon IE Report at 36.)Although the Utah independent
8 evaluator did not specifically comment on the solar
9 sensitivity,he did not challenge it in his final report.
10 (see Utah IE Report at 61.)
11 Q.Messrs.Eldred,Mullins,and Phillips argue
12 that solar PPAs represent a superior resource option for
13 customers and therefore the Combined Projects are
14 contrary to the public interest.(Eldred Supp.Direct,
15 page 11,line 6 to page 12 line 5;Mullins Supp.Direct,
16 page 16,line 8-16;Phillips Supp.Direct,page 30,lines
17 2-6.)Do you agree?
18 A.No.PacifiCorp has now completed its bid
19 evaluation and selection process for the 2017S RFP,and
20 the complete analysis and results confirm the company's
21 earlier assessment that solar-PPA bids do not displace
22 the economic benefits of the Combined Project.While the
23 base economic analyses of solar bids show that there are
24 potential customer benefits associated with a 1,320 MW
25 portfolio of solar PPAs from the 2017S RFP,subsequent
529 Link,Supp-Reb -48
Rocky Mountain Power
1 sensitivity analyses show a risk,unique to solar
2 resource opportunities,that the projected benefits for
3 the solar PPAs in the base economic analysis are
4 overstated,as I will discuss below.
5 In addition,driven by uncertainties regarding
6 tariff and tax reforms,current solar resource pricing
7 likely reflects a risk premium,and solar project costs
8 are expected to decline.Because the 30-percent ITC is
9 available for solar resources that
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
530 Link,Supp-Reb -48a
Rocky Mountain Power
1 come online by 2021,PacifiCorp expects that solar
2 pricing received in late 2019 for projects that could
3 come online in 2021 will be lower than pricing received
4 in the 2017S RFP and would avoid the current risk premium
5 associated with the tariff and tax reform uncertainties.
6 Thus,PacifiCorp does not need to act now and has decided
7 not to select any of the 2017S RFP bids to the final
8 shortlist.
9 PacifiCorp will continue to assess potential
10 economic benefits from solar resource opportunities in
11 the 2019 IRP and through bi-lateral discussions with
12 developers,including a thorough evaluation of hourly
13 price-profile and capacity-contribution risks (discussed
14 below)with full stakeholder engagement and a more
15 orderly assessment of the potential customer benefits of
16 solar generation.Should subsequent analysis in the 2019
17 IRP demonstrate that solar resource opportunities provide
18 economic benefits for customers,or if there is an
19 opportunity to mitigate evaluation risks,there will be
20 sufficient time to initiate a new competitive
21 solicitation process or to pursue bi-lateral contracts
22 for projects capable of achieving commercial operation by
23 the end of 2021 that can qualify for the 30-percent ITC.
24 This potential solicitation could consider storage bids
25 as a means to mitigate valuation risks and allow
531 Link,Supp-Reb -49
Rocky Mountain Power
1 sufficient time for participants to be further along in
2 the transmission interconnection process.
3 Q.Did PacifiCorp inform the independent evaluator
4 overseeing the 2017S RFP of its final shortlist results?
5 A.Yes.PacifiCorp summarized its 2017S RFP final
6 shortlist bid evaluation and selection analysis with
7 London Economics International,LLC,the independent
8 evaluator retained by the company to monitor the 2017S
9 RFP,on March 12,2018.This summary
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
532 Link,Supp-Reb -49a
Rocky Mountain Power
1 is included in the final report of the independent
2 evaluator for the 2017S RFP,which is provided as
3 Confidential Exhibit No.69 ("Solar IE Report").
4 Q.Did the independent evaluator for the 2017S RFP
5 agree with the company's conclusions?
6 A.Yes.The independent evaluator concluded that
7 the company's decision to not accept any solar bids was
8 not unreasonable and that PacifiCorp's concerns over
9 conditions in the solar market that reflected
10 uncertainties over tax reform and tariffs were
11 reasonable.In addition,the independent evaluator
12 concluded that the 2017S RFP was conducted in a manner
13 that was consistent with general procurement best
14 practices,unbiased,that the selection of the
15 shortlisted resources was fair,and that the company's
16 modeling reflected industry best practices.Solar IE
17 Report at 4-5.
18 Q.What additional sensitivity analyses did
19 PacifiCorp perform in the 2017S RFP to better assess the
20 potential customer benefits and valuation risks
21 associated with the solar resource bids?
22 A.PacifiCorp performed two additional
23 sensitivities.First,the company refined how it converts
24 its forward market prices into hourly prices to more
25 accurately reflect hourly market-price variation in those
533 Link,Supp-Reb -50RockyMountainPower
1 hours when solar resources are producing energy.Second,
2 the company performed a capacity-contribution sensitivity
3 to assess how changes in the assumed ability of solar
4 resource to meet peak load during periods when there is
5 an increased probability of loss-of-load events affect
6 the overall customer benefits.
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
534 Link,Supp-Reb -50a
Rocky Mountain Power
1 Q.Please describe the hourly price-profile
2 sensitivity developed to analyze bids in the 2017S RFP.
3 A.PacifiCorp uses hourly price scalars,which are
4 applied to monthly on-peak and off-peak prices in the
5 forward price curve,to derive hourly market price
6 profiles that vary by month and day type (i.e.,weekdays,
7 Saturdays,and Sundays/holidays).PacifiCorp currently
8 uses five years of hourly Powerdex price data to develop
9 price scalars.The company's review of the Powerdex data
10 shows that the five-year price history is not supported
11 by a significant volume of reported transactions (many
12 hours have no market pricing inputs)and that the
13 resulting hourly price shapes do not align with prices
14 observed in operations that are being increasingly
15 influenced by growth in solar resources across the
16 region.Thus,for the hourly price-profile sensitivity,
17 PacifiCorp developed an alternative set of price scalars
18 that are derived from one year of day-ahead hourly prices
19 available from the California Independent System Operator
20 ("CAISO").
21 The figure below illustrates the differences
22 between the Powerdex-derived scalars and the
23 CAISO-derived scalars.
24
25
535 Link,Supp-Reb -51
Rocky Mountain Power
Figure 1-SR:HourlyPrice-Scenario Sensitivity
Current Method (Powerdex)Sensitivity (CAISO Day Ahead)
2021Price ProSe -+-2036 Price ProMe ---Postioio 2 CF 2021Price Pronie -+-2036 Price ProSe --PordoNo2 CF
9
10 The figure at top left shows representative
11 average hourly price profiles as derived from historical
12 Powerdex data and used in the bid evaluation process of
13 the 2017S RFP.The figure at top right shows
14 representative average hourly price profiles derived from
15 historical CAISO data and used in this sensitivity.In
16 both figures,the hourly price profile is based on the
17 average hourly prices from representative months
18 (January,April,July,and October)and shown alongside
19 .the average hourly energy profile of bids included in a
20 solar-PPA bid portfolio.The price profile used in the
21 sensitivity shows that when accounting for the growth of
22 solar resources across the region,prices are lower
23 during those hours when the resources in the solar-PPA
24 bid portfolio are expected to generate electricity.
25 Q.Does the company intend to use the
536 Link,Supp-Reb -52
Rocky Mountain Power
1 CAISO-derived scalars in future resource analyses?O 2 A.Yes.The company intends to use the refined
3 scalars in the 2017 IRP Update,future IRPs,and future
4 regulatory filings.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
537 Link,Supp-Reb -52a
Rocky Mountain Power
1 Q.How do the refined hourly price scalars impact
2 the benefits of the solar-PPA resources?
3 A.The use of the CAISO-derived hourly price
4 scalars decreased the benefits of the solar PPAs.This
5 outcome was observed regardless of whether these price
6 scalars were applied to studies evaluating solar-PPA bids
7 with or without the Combined Projects.When analyzed in
8 isolation from the Combined Projects,20-year PaR studies
9 (through 2036)show that application of the CAISO-derived
10 hourly price scalars decreased solar-PPA benefits from
11 $174 million to $108 million (a reduction of $66 million)
12 based on stochastic-mean PaR results and from $183
13 million to $114 million (a reduction of $69 million)
14 based on risk-adjusted PaR results in the medium natural
15 gas,medium CO2 price-policy scenario.
16 When analyzed under the low natural gas,zero
17 CO2 price-policy scenario,the CAISO-derived hourly price
18 scalars decreased the benefit of the solar PPAs from
19 showing a $45 million net benefit to showing a $10
20 million net cost (a $55 million reduction in benefits)
21 based on stochastic-mean PaR results and from showing a
22 $48 million net benefit to showing a $10 million net cost
23 (a $58 million reduction in benefits)based on
24 risk-adjusted PaR results.
25 The price-policy scenario assumptions used to
538 Link,Supp-Reb -53RockyMountainPower
1 analyze solar-PPA bids in the 2017S RFP are identical to
2 those used to analyze the Combined Projects in my second
3 supplemental direct testimony,with the exception that
4 the medium CO2 price assumptions were correctly applied
5 as a nominal cost instead of real costs in 2012 dollars.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
539 Link,Supp-Reb -53a
Rocky Mountain Power
1 Q.Are there any other issues to consider related
2 to the price-profile used to evaluate the solar-PPA bids?
3 A.Yes.The expected increase in solar generation,
4 coupled with correlation among expected solar resource
5 generation profiles across the west,has had a
6 significant impact on hourly prices and will continued to
7 do so as solar development increases.S&P Global Market
8 Intelligence tracks power-plant capacity,and reports
9 that solar capacity in the Western Electricity
10 Coordinating Council ("WECC")region,which represents
11 capacity that is online or announced to go online having
12 obtained regulatory approvals,will grow from 16.8
13 gigawatts ("GW")in 2017 to 29.8 GW by 2023 (growth of
14 approximately 77 percent over six years).Similarly,the
15 AEO 2018 Reference Case trends closely with the S&P
16 Global Market Intelligence data,and shows continued
17 growth of solar capacity in the WECC,which reaches 46.8
18 GW by 2050.By the end of a 25-year solar PPA (2045),the
19 AEO 2018 Reference Case predicts that solar capacity in
20 the WECC region will grow to 41.3 GW,which is 2.5 times
21 the amount of solar capacity reported for 2017.
22 The rapid increase in solar capacity across the
23 region over the past five years has significantly
24 impacted hourly market prices,and continued growth in
25 new solar capacity could further affect the market value
540 Link,Supp-Reb -54
Rocky Mountain Power
1 of solar energy beyond what has been analyzed in the
2 price-profile sensitivity described above.Moreover,
3 proxy solar profiles from the National Renewable Energy
4 Laboratory ("NREL")show a high degree of correlation
5 among potential solar sites across the WECC region,
6 indicating that the potential impacts on hourly price
7 profiles are likely regardless of where new solar is
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
541 Link,Supp-Reb -54a
Rocky Mountain Power
1 added.The figure below illustrates the expected growth
2 in solar generation and the correlated generation
3 profiles throughout the region.
4 Figure 2-SR:Growth in Solar Generation and Correlation of Generation Profiles
5
Solar Capacity the WECC Region Representative Solar Profiles (NREL Data)
15 20%
ammin SAP Gobal Madedutemgence --MOMS -Maona $con late)-South OmaiOR11
12 Q.Did the independent evaluator for the 2017S RFP
13 comment on the hourly price sensitivity?
14 A.Yes.The independent evaluator concluded that
15 the "alternative price profile was a reasonable way to
16 examine potential downside risks to customers of
17 committing to solar resources."Solar IE Report at 25.
18 Q.Mr.Yankel claims that the company's analysis
19 should account for the impact increased wind generation
20 will have on market prices similar to the adjustment
21 applied to solar.(Yankel Supp.Direct,page 11 lines
22 3-19.)Do you agree?
23 A.No.The company's price curves,which includes
24 monthly on-peak and off-peak power prices,account for
25 the growth of renewable resources throughout the WECC
542 Link,Supp-Reb -55
Rocky Mountain Power
1 over time.For instance,across the WECC region,the
2 fundamentals-based component of PacifiCorp's December
3 2017 OFPC includes 9.4 GW of new solar resources and 5.4
4 GW of new wind resources by 2025.New solar capacity
5 increases to 18 .O GW and new
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
543 Link,Supp-Reb -55a
Rocky Mountain Power
1 wind capacity grows to 12.3 GW by 2035.This OFPC does in
2 fact account for the impact of increased solar and wind
3 resources over time.
4 The price-profile sensitivity does not assess
5 how new solar resources affect overall monthly prices.As
6 discussed above,the impact of new solar and wind
7 resources is already captured in the company's OFPC.
8 Rather,the price-profile sensitivity is intended to
9 evaluate how changes to the hourly price profile within a
10 given 24-hour period is impacted if more accurate market
11 data from the CAISO is used to more closely align these
12 hourly price profiles with those observed in operations.
13 To be clear,the price profiles developed for this
14 sensitivity are based on market data and are not based on
15 assumed levels of solar penetration.It is not surprising
16 that the hourly shape of these market data show the
17 effects increased solar generation,which only produce
18 energy during day-light hours.In contrast,wind
19 resources produce energy across all hours of the day.
20 Therefore the energy output from wind resources is less
21 likely to materially impact the hourly shape of market
22 prices.
23 Q.Please describe the capacity-contribution
24 sensitivity used in the 2017S RFP bid evaluation and
25 selection process.
544 Link,Supp-Reb -56
Rocky Mountain Power
1 A.The capacity-contribution sensitivity is
2 designed to assess the risks associated with overstating
3 the capacity contribution of solar resources when
4 evaluating the potential customer benefits of solar-PPA
5 bids.The capacity contribution of solar resources,
6 represented as a percentage of resource capacity,is a
7 measure of the ability for these resources to reliably
8 meet demand.The company's base economic analysis used to
9 evaluate bids submitted into the 2017S RFP and used to
10 support the solar sensitivity studies in my supplemental
11 direct and second supplemental direct testimony applied
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
545 Link,Supp-Reb -56a
Rocky Mountain Power
1 the capacity-contribution values for solar resources
2 developed for the 2017 IRP (59.7 percent for the solar
3 PPAs located in Utah),and therefore,the base economic
4 analysis assumes that the 1,320 MW of solar-PPA capacity
5 included in the 2017S RFP bid portfolio can displace the
6 need for approximately 788 MW of system capacity (59.7
7 percent multiplied by the 1,320 MW of solar-PPA
8 capacity).
9 As more highly correlated solar generation is added
10 to the system,the energy output from these resources is
11 more likely to shift the timing of potential loss-of-load
12 events to evening hours when solar irradiance is low and
13 generation levels are greatly reduced or zero.
14 Consequently,solar capacity-contribution values are
15 highly sensitive to increasing solar penetration levels.
16 The figure below illustrates study results concluding
17 that additional solar generation reduces the capacity
18 contribution of solar resources.
19 /
20 /
21 /
22 /
23 /
24 /
25 /
546 Link,Supp-Reb -57
Rocky Mountain Power
1
2
Figure 3-SR:Capacity Contribution Compared to Penetration
80 -NV Power:Perez et al (2008)3 -CA Case Study:Mills and Wiser (2012)70 -CA Case Study:Jones (2012)4
-60 -APS -Tracking:R.W.Beck (2009)
5 -APS -Fixed;R.W.Beck (2009)50 -WestConnect:GE Energy(2010)
6 40 -Toronto:Pellandand Abboud(2008)
E:Perez et al (2008)
7 30
8 20
10
010 0 5 10 15 20 25 30
11 PV Penetration (%annual energy)
12 Source:Mills,Andrew,and Ryan Wiser.2012."An Evaluation of Solar Valuation Methods Used in Utility Planning and
13 Procurernent Processes."LBNL-5933E,Berkeley,CA:Ernest Orlando Lawrence Berkeley National Laboratory.
14 /
15
16 /
17
18
19
20
21
22
23
24
25
547 Link,Supp-Reb -57a
Rocky Mountain Power
1 For PacifiCorp,the addition of 1,320 MW of solar
2 capacity would more than double the amount of solar
3 resources on its system.The capacity-contribution
4 sensitivity evaluates the economic impact of halving the
5 capacity-contribution value from 59.7 percent to 29.9
6 percent when applying medium natural gas,medium CO2 and
7 low natural gas,zero CO2 price-policy assumptions.
8 Considering that the company will begin using the hourly
9 price profiles derived from day-ahead CAISO data in the
10 2017 IRP Update,future IRPs,and future regulatory
11 filings,the capacity-contribution sensitivity also
12 includes the CAISO-derived hourly price profile.
13 Q.What were the results of this capacity-
14 contribution sensitivity used to evaluate bids in the
15 2017S RFP?
16 A.With the capacity-contribution assumption
17 reduced from 59.7 percent down to 29.9 percent,the
18 amount of system capacity that the 1,320 MW of solar
19 resource capacity can displace is reduced from 788 MW to
20 394 MW.This reduces the resource-deferral value of the
21 solar-PPA resources,which in turn reduces the net
22 benefits of the solar-PPA bids.
23 The combined effect of the hourly price-profile
24 and capacity-contribution assumptions,when solar-PPA
25 bids are analyzed in isolation of the Combined Projects
548 Link,Supp-Reb -58
Rocky Mountain Power
1 over a 20-year time frame in PaR,is to decrease the
2 solar-PPA benefits from $174 million to $69 million (a
3 reduction of $105 million in benefits)based on
4 stochastic-mean PaR results,and from $183 million to $73
5 million (a reduction of $110 million in benefits)based
6 on risk-adjusted PaR results in the medium natural gas,
7 medium CO2 price-policy scenario.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
549 Link,Supp-Reb -58a
Rocky Mountain Power
1 When analyzed under the low natural gas,zero
2 CO2 price-policy scenario,the combined effect of the
3 hourly price-profile and capacity-contribution
4 assumptions is to decrease the benefit of the solar PPAs
5 from showing a $45 million net benefit to showing a $56
6 million net cost (a $101 million reduction in benefits)
7 based on stochastic-mean PaR results,and from showing a
8 $48 million net benefit to showing a $58 million net cost
9 (a $106 million reduction in benefits)based on
10 risk-adjusted PaR results.
11 Again,the price-policy scenario assumptions
12 used to analyze solar-PPA bids in the 2017S RFP are
13 identical to those used to analyze the Combined Projects
14 in my second supplemental direct testimony,with the
15 exception that the medium CO2 price assumptions were
16 correctly applied as a nominal cost instead of real costs
17 in 2012 dollars.
18 Q.When assessing the impact of the hourly
19 price-profile sensitivity for the 2017S RFP,did the
20 company consider how the CAISO-derived hourly price
21 scalars might affect the economic analysis of the
22 Combined Projects?
23 A.Yes.The table below summarizes how the
24 CAISO-derived hourly price-scalar assumptions impact the
25 Combined Projects and,separately,how these assumptions
550 Link,Supp-Reb -59
Rocky Mountain Power
1 impact the 1,320 MW bid portfolio that includes solar
2 PPAs without the Combined Projects when applying medium
3 natural gas,medium CO2 price-policy assumptions.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
551 Link,Supp-Reb -59a
Rocky Mountain Power
1 Table 1-SR:Solar-OnlyCompared to Combined Projects
2 Hourly-Price SensitivitySystem Modeling Results
(Medium Gas,Medium CO2)
3
4 Stochastic-Risk-Adjusted
Mean PaR PaR PVRR(d)
5 PVRR(d)(Benefit)/Cost
6 (Benefit)/Cost $million
Combined Projects
7 Benchmark Analysis (Second Supplemental
Direct3 $(357)$(386)
8 Hourlv Price-Profile Sensitivitv &Nominal CO->$(328]$(343)
Decrease in Net Benefits $29 $4392017SSolar-PPA Bid Portfolio
10 Benchmark Analvsis (Current Hourlv Scalars)$(237)$(248)
Hourlv Price-Profile Sensitivitv $(160)$(168)
11 Decrease in Net Benefits $77 $80
12 This analysis shows that the new hourly
13 prices-profile decreases the customer benefits of the
14 Combined Projects on a stand-alone basis and decreases
15 the customer benefits of the solar PPAs on a stand-alone
16 basis.But,importantly,the reduction in net benefits
17 associated with the hourly-price profile sensitivity is
18 between 1.9 and 2.7 times greater for the solar PPAs than
19 it is for the Combined Projects when applying medium gas,
20 medium CO2 price-policy assumptions.The disproportionate
21 impact is consistent with the fact that solar generation
22 profiles are more highly correlated with the impact solar
23 resources are having on hourly price profiles relative to
24 wind.While both types of technologies are faced with the
25 same reduction in the market value of energy during the
552 Link,Supp-Reb -60
Rocky Mountain Power
1 middle of the day,the wind generation produces energy
2 during the early morning and late evening hours,when the
3 market value of energy is higher.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
553 Link,Supp-Reb -60a
Rocky Mountain Power
1 Q.Did you conduct this same analysis for the low
2 gas,zero CO2 price-policy scenario?
3 A.Yes.The table below saamarizes how the
4 CAISO-derived hourly price-scalar assumptions impact the
5 Combined Projects and the 1,320 MW solar-PPA bid
6 portfolio when applying low gas,zero CO2 price-policy
7 assumptions.
8 Table 2-SR:Solar-OnlyCompared to Combined Projects
Hourly-Price SensitivitySystem ModelingResults
9 (Low Gas,Zero CO2)
I10
Stochastic-Risk-Adjusted
11 Mean PaR PaR PVRR(d)
12 PVRR(d)(Benefit)/Cost
(Benefit)/Cost $million
13 Combined Projects
14 Benchmark Analvsis (Second Sueolemental Direct)($150)($156)
Hourlv Price-Profile Sensitivitv ($125)($130)
15 Decrease in Net Benefits $25 $26
2017S Solar-PPA Bid Portfolio
16 Benchmark Analvsis (Current Hourlv Scalars)($125)($131)
HourlyPrice-Profile Sensitivity ($69)($72)17 Decrease in Net Benefits $56 $59
18 Similar to the medium gas,medium CO2
19 price-policy scenario,the results show that the net
20 benefits associated with both the Combined Projects and
21 the solar PPAs decreased,but,again,the reduction in
22 net benefits associated with the hourly-price profile
23 sensitivity is approximately 2.2 to 2.3 times greater for
24 the solar PPAs than it is for the Combined Projects when
25 applying low gas,zero CO2 price-policy assumptions.
554 Link,Supp-Reb -61
Rocky Mountain Power
1 Q.What conclusions can you draw from theseO2results?
3 A.The solar PPAs are more sensitive to the
4 refined hourly price-profile and therefore present a
5 greater risk that the customer benefits of the solar PPAs
6 are overstated relative
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
555 Link,Supp-Reb -61a
Rocky Mountain Power
1 to the Combined Projects.O 2 Q.Did the company apply the capacity-contribution
3 sensitivity to the Combined Projects?
4 A.No.Unlike solar resources,wind resources are
5 expected to generate in all hours of the day,and thus
6 the energy output from wind resources are not likely to
7 shift the timing of potential loss-of-load events to
8 hours when the wind is not generating.Consequently,the
9 capacity-contribution value for wind resources (15.8
10 percent for east wind as reported in the 2017 IRP)is
11 less likely to be materially impacted with increasing
12 penetration of either new wind or solar resources.
13 Q.How do the economics of the Combined Projects
14 with CAISO-derived hourly price scalars compare to the
15 economics of the solar-PPA bid portfolio that reflects
16 the combined effects of the alternative hourly-price and
17 capacity-contribution assumptions?
18 A.The table below summarizes how these
19 assumptions impact the Combined Projects and the 1,320 MW
20 solar-PPA bid portfolio when applying medium natural gas,
21 medium CO2 price-policy assumptions.
22
23
24
25
556 Link,Supp-Reb -62
Rocky Mountain Power
\1O Table 3-SR:Solar-OnlyCompared to Combined Projects
2 Capacity-ContributionSensitivitySystem Modeling Results
(Medium Gas,Medium CO2)
3
4 Stochastic-Risk-Adjusted
Mean PaR PaR PVRR(d)
5 PVRR(d)(Benefit)/Cost
6 (Benefit)/Cost $million
Combined Projects
Benchmark Analvsis (Second Supplernental Direct)($357)($386]
o HourlyPrice-Profile Sensitivitv &Nominal CO2 ($328)($343)
Decrease in Net Benefits $29 $43
9 2017S Solar-PPA ßid Portfolio
Benchmark Analysis (Current Hourly Scalars/Cap
10 Cont l ($237)($248)
HourlvPrice-Profile/C4p Cont.Sensitivitv ($93)($97)
11 Decrease in Net Benefits $144 $151
12
13 As set forth above,the combined effect of theO14hourlyprice-profile and capacity-contribution
15 assumptions is to reduce the net benefits of the
16 solar-PPA bids by between $144 million and $151 million
17 in the medium gas,medium CO2 price-policy scenario,
18 which is approximately 3.5 to 5.0 times greater than the
19 impact of the hourly price-profile on the Combined
20 Projects.
21 Q.What do these sensitivities show when applying
22 low gas,zero CO2 price-policy assumptions?
23 A.The table below summarizes how hourly
24 price-scalar and capacity-contribution sensitivity
è 25 assumptions affect the Combined Projects and the 1,320 MW
557 Link,Supp-Reb -63
Rocky Mountain Power
1 solar-PPA bid portfolio when applying low natural gas,
2 zero CO2 price-policy assumptions.
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
558 Link,Supp-Reb -63a
Rocky Mountain Power
1 Table 4-SR:Solar-OnlyCompared to Combined Projects
2 Capacity-ContributionSensitivitySystem Modeling Results
(Low Gas,Zero CO2)
3
4 Stochastic-Risk-Adjusted
Mean PaR PaR PVRR(d)
5 PVRR(d)(Benefit)/Cost
6 (Benefit)/Cost $million
Combined Projects'Benchmark Analvsis (Second Supplemental pirect)($150)($156)
o Hourlv Price-Profile Sensitivity ($125)($130)
Decrease in Net Benefits $25 .$26
9 2017S Solar-PPA Bid Portfolio
Benchmark Analysis (Current Hourly Scalars/Cap
1 0 Cont 3
($125)($131)
HourlyPrice-Profile/Cap Cont.Sensitivitv ($8)($8)
11 Decrease in Net Renefits $117 $123
12 The combined effect of the hourly price-profile
13 and capacity-contribution assumptions is to reduce the
14 net benefits of the solar-PPA bids by between $117
15 million and $123 million in the low natural gas,zero CO2
16 price-policy scenario,which is approximately 4.7 times
17 greater than the impact of the hourly price-profile on
18 the Combined Projects.
19 Q.What conclusions can you draw from these
20 sensitivities?
21 A.The sensitivities set forth above demonstrate
22 that there is risk that the customer benefits from the
23 solar PPAs are overstated because the assumed
24 capacity-contribution value and associated
25 resource-deferral benefits are likely to be lower than
559 Link,Supp-Reb -64RockyMountainPower
1 what is assumed in the base analysis.Importantly,this
2 same risk does not apply to the Combined Projects.In
3 fact,the Combined Projects will bring additional
4 transmission capacity and a diverse resource that is
5 uncorrelated to solar production (i.e.,wind production
6 occurs in all
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
560 Link,Supp-Reb -64a
Rocky Mountain Power
1 hours,not just daylight hours).Moreover,solar-resource
2 opportunities do not displace the benefits of the
3 Combined Projects,and similarly,the Combined Projects
4 do not displace the potential benefits of solar-resource
5 opportunities.Solar resources are best viewed as an
6 incremental opportunity to the Combined Projects,not as
7 an alternative.
8 Q.Did the company perform an annual revenue
9 requirement analysis to assess how these risks affect the
10 Combined Projects and the 1,320 MW solar-PPA bid
11 portfolio?
12 A.Yes.Figure 4-SR provides these annual revenue
13 requirement results when applying medium natural gas,
14 medium CO2 price-policy assumptions.The figure also
15 shows the cumulative PVRR,where the PVRR for each year
16 represents the present value of annual revenue
17 requirement from that year and all prior years.
18 Figure 4-SR:Annual Revenue RequirementResults
19
increase/(Decrease)in Nom.Rev.Req.
23
561 Link,Supp-Reb -65
Rocky Mountain Power
1 As Figure 4-SR illustrates,the PVRR(d)
2 benefits of the Combined Projects,reflecting an hourly
3 price profile derived from the CAISO day-ahead data,when
4 calculated from nominal revenue requirement results is
5 $127 million.The PVRR(d)benefits of the solar PPAs,
6 reflecting an hourly price profile derived from the CAISO
7 day-ahead data and reflecting a 29.9 percent
8 capacity-contribution value,is
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
562 Link,Supp-Reb -65a
Rocky Mountain Power
1 $149 million.The Combined Projects have a higher net
2 cost relative to the solar PPAs for two years;however,
3 with PTCs,the net costs drop below the solar-PPA bids
4 beginning year three and the Combined Projects begin
5 producing net benefits by 2025.The solar PPAs do not
6 begin producing net benefits until 2029.Beyond the first
7 few years,the cumulative PVRR of the Combined Projects
8 is favorable relative to the solar-PPA bids through 2035.
9 Over the long term,more speculative benefits that
10 reflect no further deterioration to hourly price profiles
11 or capacity-contribution value drive the cumulative PVRR
12 benefits of the solar-PPA bids below wind.In 2050,the
13 terminal value assumed for owned assets (applicable to
14 1,011 MW of the new wind)improves the cumulative PVRR
15 for the Combined Projects.
16 Q.In addition to the risk associated with hourly
17 prices and capacity contribution,are there any other
18 risks associated with obtaining solar PPAs now as a
19 result of the 2017S RFP?
20 A.Yes.As shown in Figure 5-SR,solar resource
21 costs have been steadily declining and the trend is
22 expected to continue.
23
24
25
563 Link,Supp-Reb -66
Rocky Mountain Power
Figure 5-SR:Solar Resource Costs
2017Uso
per WattDC pg gy pg3FixedTat(100 MW)one-Axis Tracker (100 MW)
2040 20tt 20t2 2013 2084 2015 2016 20tT 2090 20tt 2012 20t3 2014 2015 2018 20tT
oSon Costa -Others (PII.Land Accluisi&on.Sales Tex.Overhead,anci Net Prorst)
9 ascacessa -samen t.abor
D Herdware BOS -Structuratand Electricol Counponenteainverter
10
11
12 source:Fu,Ran,David Feldman,Robert Margolis Mike Woodhouse,and Kristen Ardani."U.S.Solar Photovoltaic
System Cost Benchmark:Q1 2017."Nabonal Renewable Energy Laboratory.September 2017.13
14 As illustrated above,solar resource costs have
15 fallen over time with a 77 percent reduction in
16 utility-scale solar photovoltaic system costs for
17 fixed-tilt systems over the 2010-2017 time frame and an
18 80-percent reduction for single-axis tracker systems.
19 Stemming from increases in module costs due to a global
20 shortage of Tier 1 module supply,tax-reform uncertainty,
21 and tariff uncertainty,solar costs increased for the
22 first time in the third quarter of 2017 since the Solar
23 Energy Industry Association and GTM Research began
24 publishing market cost reports in 2010;however,cost
25 reductions are expected to continue over the long term.
564 Link,Supp-Reb -67RockyMountainPower
1 By the second half of 2019,tariff and tax risks,O 2 including implications on tax-equity markets,are
3 expected to have been mitigated and module costs are
4 expected to fall to as low as
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
565 Link,Supp-Reb -67a
Rocky Mountain Power
1 30 cents-per-watt on a direct-current basis by 20192,
2 Additional reductions to the cost of inverters,tracking
3 structures,and other balance-of-system components are
4 expected to further reduce total-system costs in 2019 and
5 2020.
6 Q.How do these changes in solar resource costs
7 impact the company's assessment of the 2017S RFP
8 resources?
9 A.When considering the relatively long lead time
10 between contract execution of 2017S RFP solar resource
11 bids with commercial operation dates in late 2020,and
12 the fact that the 30-percent ITC is available for solar
13 projects coming online as late as 2021,current pricing
14 for solar resources likely reflects a risk premium,by
15 both bidders and their tax-equity investors,related to
16 tariff and tax-reform uncertainties.Solar pricing
17 received in late 2019 for projects that could come online
18 in 2021 and qualify for the 30-percent ITC should reflect
19 expected cost reductions and avoid the current risk
20 premium associated with tariff and tax-reform
21 uncertainties.
22 Q.Mr.Phillips claims that the company was
23 misleading because it did not present the nominal revenue
24 requirement results through 2050 for the solar
25 sensitivity presented in the second supplemental direct
566 Link,Supp-Reb -68
Rocky Mountain Power
1 testimony.(Phillips Supp.Direct,page 19,lines 4-22.)
2 How do you respond?
3 A.I disagree that the company's testimony and
4 analysis was misleading.As I described in my second
5 supplemental testimony,the company's system-modeling
6 analysis demonstrated that the combined benefits of the
7 solar resources and the Combined
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24 2 Why Solar Is on a Pada to Dominance,"Greentech Media,Yuri
Horwitz,February 15,2018 (available at https://www.qreentechmedia.
25 com/articles/read/solar-is-going-to-win-bigly).
567 Link,Supp-Reb -68a
Rocky Mountain Power
1 Projects were higher than the individual benefits of each
2 resource option alone.Mr.Phillips does not dispute that
3 conclusion.
4 As I discussed earlier,the system-modeling
5 results provide a view of the economic analysis that is
6 consistent with the planning period and approach used to
7 identify a least-cost,least-risk preferred portfolio in
8 the IRP.While the nominal revenue-requirement analysis
9 provides a sense of how the Combined Projects and solar
10 resources might impact customer rates over time,
11 longer-term results in this analysis are increasingly
12 difficult to project.The company focused on the
13 system-modeling results when performing its solar
14 resource sensitivities because these studies are more
15 suitable for comparing different resource portfolios,
16 consistent with how resource portfolios are evaluated in
17 the IRP.
18 Q.Messrs.Mullins,Phillips and Eldred claim that
19 the nominal revenue-requirement results show that solar
20 PPAs are a superior resource option when compared to the
21 Combined Projects.(Mullins Supp.Direct,page 16,lines
22 8-16;Phillips Supp.Direct,page 20,lines 3-13;Eldred
23 Supp.Direct,page 11,lines 6-15.)How do you respond?
24 A.First,as noted above,Mr.Phillips does not
25 dispute that the customer benefits of the Combined
568 Link,Supp-Reb -69
Rocky Mountain Power
1 Projects and the solar resources together are higher than
2 each resource option alone when analyzed over a 20-year
3 time frame,consistent with evaluation of resource
4 portfolios in the IRP.That is the key finding reported
5 in my solar sensitivity analysis.
6 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
569 Link,Supp-Reb -69a
Rocky Mountain Power
1 Second,as described above,there is a risk
2 that benefits of the solar PPAs reported in my second
3 supplemental testimony are overstated,as demonstrated by
4 the additional sensitivities discussed above,and that
5 these risks could increase over time.
6 Q.These witnesses also claim that the solar
7 option is also less risky than the Combined Projects
8 because the solar resources are PPAs.(Phillips Supp.
9 Direct,page 21,lines 1-13 and page 24,line 9 to page
10 25,line 2;Eldred Supp.Direct,page 10,lines 16-22.)
11 Is this true?
12 A.No.These parties'focus on only the commercial
13 structure is overly simplistic.As described above,solar
14 resources generally present additional risks that do not
15 apply to wind resources.Specifically,solar resources
16 tend to generate most during the day,when demand and
17 prices are relatively low.Because the generation profile
18 of solar resources is consistent across the west,the
19 increasing penetration of solar resources throughout the
20 region will likely further depress prices during the
21 period when solar generates.Thus,there is a risk with
22 solar that the value of the generation provided will be
23 less than current forecasts and could be less than
24 projected in the hourly price-profile sensitivities.
25 Moreover,the capacity contribution of solar
570 Link,Supp-Reb -70
Rocky Mountain Power
1 resources is likely decreasing as solar penetration
2 increases.As discussed above,this is a risk that is
3 unique to solar resources and means that the customer
4 benefits for solar resources are likely overstated.
5 Q.Are there any other risks associated with
6 pursuing solar resources now?
7 A.Yes.These parties also claim that the solar
8 PPAs are less risky because they do not require the
9 Aeolus-to-Bridger/Anticline transmission line.But,as
10 described by Mr.Vail,that transmission line will
11 provide substantial customer benefits independent of
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
571 Link,Supp-Reb -70a
Rocky Mountain Power
1 the fact that it will enable interconnection of the Wind
2 Projects.And,as described by Mr.Vail,the company
3 currently anticipates construction of the line by 2024
4 even without the Combined Projects.Thus,far from
5 reducing customer risk,if the company selected the solar
6 PPAs instead of the Combined Projects,it would create a
7 very real risk that customers would ultimately bear the
8 cost of the Aeolus-to-Bridger/Anticline line without the
9 subsidy provided by the PTC-eligible Wind Projects.And
10 if the costs to construct the Aeolus-to-Bridger/Anticline
11 line are considered in the solar-PPA analysis,with the
12 addition of PTC-eligible wind resources,the benefits of
13 those solar-PPA resources would decrease dramatically and
14 would be substantially less than the benefits of the
15 Combined Projects.
16 Q.Mr.Phillips also argues that the solar PPAs
17 are superior because they provide no equity returns to
18 PacifiCorp.(Phillips Supp.Direct,page 26,line 1 to
19 page 27,line 8.)Should the amount of equity returns
20 have any bearing on the resource decision at issue here?
21 A.No.PacifiCorp'_s resource planning considers
22 the costs associated with a particular resource decision
23 and does not,and should not,consider whether a
24 component of a resource's cost is an equity return to
25 PacifiCorp's shareholders or an equity return to a
572 Link,Supp-Reb -71
Rocky Mountain Power
1 shareholder of an independent power producer.There is no
2 logical reason that PacifiCorp would select a more
3 expensive or higher-risk resource simply because it did
4 not include an equity return to the company.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
573 Link,Supp-Reb -71a
Rocky Mountain Power
1 Q.Mr.Phillips claims that the company would not
2 have issued the 2017S RFP if the Utah Commission had not
3 suggested doing so and that this demonstrates serious
4 flaws in the 2017 IRP.(Phillips Supp.Direct,page 18,
5 lines 1-9.)How do you respond?
6 A.As discussed above,the 2017S RFP provided a
7 great deal of useful market information that will inform
8 future IRPs.The recommendation from the Utah Commission
9 to consider solar-resource opportunities does not in any
10 way suggest that the 2017 IRP was flawed.Moreover,the
11 2017S RFP will not ultimately result in the acquisition
12 of solar resources because benefits of waiting are
13 greater than the risks of moving forward at this time.
14 ENERGY IMBALANCE MARKET MODELING
15 Q.Mr.Mullins again argues that the Company has
16 not accounted for energy imbalance market ("EIM")
17 uninstructed imbalance charges.(Mullins Supp.Direct,
18 page 32,lines 18-20.)Can you please explain
19 uninstructed imbalance charges?
20 A.Yes.First,I will provide more context for the
21 explanation and how EIM settlements are calculated for
22 PacifiCorp's resources.In the EIM,the company provides
23 a base schedule for all of its participating and
24 non-participating resources,including variable energy
25 resources such as wind facilities.The base schedules are
574 Link,Supp-Reb -72
Rocky Mountain Power
1 hourly and are used by the CAISO for purposes of a
2 balancing test to ensure that the company has scheduled
3 its resources within one percent of its expected demand
4 in the upcoming hour.The next step in the scheduling
5 process is the fifteen-minute schedule,which is
6 generated approximately 30 minutes before the operating
7 interval for each resource in
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
575 Link,Supp-Reb -72a
Rocky Mountain Power
1 PacifiCorp's system.This fifteen-minute schedule is
2 considered an advisory schedule because it is not used
3 for dispatch purposes.Lastly,there is a five-minute
4 schedule,which is a dispatch instruction to each of
5 PacifiCorp's resources,including expected wind output
6 for the five-minute interval.Each of these three
7 schedules--hourly,fifteen-minute and five-minute--is
8 used to calculate the instructed imbalance market
9 settlements for a resource.
10 For the uninstructed imbalance settlement,the
11 CAISO utilizes the variance in the actual submitted meter
12 data for a resource,the five-minute dispatch instruction
13 and the five-minute locational marginal price at the
14 resource node.The difference between the five-minute
15 dispatch instruction and the actual meter data is
16 multiplied by the locational marginal price and divided
17 by 12 (division by 12 is required because the time frame
18 is a five-minute interval,and there are 12 five-minute
19 intervals in an hour).This calculation results in a
20 charge to a resource if it produced less energy relative
21 to the schedule.Conversely,this calculation results in
22 a payment to a resource if it produced more energy
23 relative to its schedule.
24 Q.In the company's rebuttal testimony filed in
25 December 2017,Mr.Vail testified that the company
576 Link,Supp-Reb -73
Rocky Mountain Power
1 expects that the uninstructed imbalance charges should be
2 neutral over the life of the resource.(Vail Rebuttal,
3 page 23,line 15 to page 24,line 14.)Mr.Mullins argues
4 that Mr.Vail was wrong (Mullins Supp.Direct,page 33,
5 lines 3-10.)How do you respond?
6 A.As explained by Mr.Vail,the uninstructed
7 imbalance charges are a reflection of forecast error
8 (actual meter data minus a five-minute forecast).
9 Assuming that the forecast,which is produced less than
10 30 minutes before the interval,has an equal
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
577 Link,Supp-Reb -73a
Rocky Mountain Power
1 chance of being higher or lower over the life of a
2 resource,the net charges should be close to zero.
3 Mr.Mullins provides evidence related to two
4 resources over a short period of time to argue that there
5 is an inherent bias in the forecasting.But the alleged
6 bias is simply the result of Mr.Mullins's reliance on a
7 limited data set and is not reflective of long-term
8 expectations,which are that the net outcome will be
9 closer to zero.
10 Q.Are there any other flaws in Mr.Mullins's
11 analysis?
12 A.Yes.The existence of uninstructed imbalance
13 charges assigned to certain resources does not mean that
14 there is an actual cost (or revenue)that is passed
15 through to customers.Uninstructed imbalance reflects the
16 movement of resources and load that are outside of the
17 CAISO's dispatch and,therefore,PacifiCorp is required
18 to manage that variation using its regulating resources
19 as the balancing area authority.PacifiCorp must manage
20 its area-control error as close to zero as possible to
21 maintain its balancing and frequency requirements in
22 accordance with the National Electric Reliability
23 Council's standards.Thus,if a wind resource was five MW
24 above its CAISO dispatch (five-minute forecast),then
25 another resource,likely a regulating resource,on the
578 Link,Supp-Reb -74
Rocky Mountain Power
1 PacifiCorp system would need to decrease by five
2 megawatts to maintain system balance.
3 Q.When the regulating resource moves in the
4 opposite direction of the wind resource,is that
5 considered uninstructed imbalance?
6 A.Yes.The movement would be uninstructed
7 imbalance because it was not part of the CAISO's dispatch
8 solution.When PacifiCorp regulates with its resources
9 for changes in wind,solar,and load outside of the
10 CAISO's dispatch,that is considered regulation
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
579 Link,Supp-Reb -74a
Rocky Mountain Power
1 and is maintained by keeping several of PacifiCorp
2 thermal units in "regulating mode"to make sure that
3 PacifiCorp's system-balancing requirements are met.
4 Q.Does that mean there is a reciprocal cost or
5 revenue for PacifiCorp's regulating resources?
6 A.Yes.While Mr.Mullins includes a table that
7 shows a cost for the wind facilities'uninstructed
8 imbalance,what he does not show is the corresponding
9 revenue that was received by one of PacifiCorp's
10 regulating resources.
11 Q.Is there a cost for regulating for variable
12 energy resources?
13 A.Yes.There is a cost for regulating for
14 variable-energy resources,which is why PacifiCorp
15 includes an integration cost in its economic analysis,
16 consistent with the treatment of including an integration
17 cost in the IRP.
18 Q.If the Commission used Mr.Mullins's assessment
19 of the uninstructed imbalance costs for the new wind
20 facilities,would that be double counting the costs of
21 integration?
22 A.Yes.As noted above,integration costs are
23 already included in the company's economic analysis.
24 Q.One of Mr.Mullins's conditions is that in all
25 future ratemaking proceedings,the company's dispatch
580 Link,Supp-Reb -75
Rocky Mountain Power
1 model used to set net power costs should include 300 MW
2 of transmission "link"between Jim Bridger and Walla
3 Walla,consistent with the EIM benefit assumption used in
4 economic analysis of the Combined Projects.(Mullins
5 Supp.Direct,page 4,lines 28-32.)What is your
6 response?
7 A.This is not the correct forum to establish
8 modeling assumptions for all future ratemaking
9 proceedings that rely on the company's dispatch models to
10 set net power
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
581 Link,Supp-Reb -75a
Rocky Mountain Power
1 costs.PacifiCorp's transmission-topology assumptions
2 used to capture EIM benefits in this proceeding are
3 valid,as described in my direct testimony,and are based
4 on the best available information at this time.It may be
5 appropriate to incorporate this type of assumption in
6 future ratemaking proceedings that rely on the company's
7 dispatch models to set net power costs,but that analysis
8 and determination should be made at that point in time
9 and should not be pre-determined in this proceeding.
10 CONCLUSION
11 Q.Please summarize the conclusions of your
12 supplemental rebuttal testimony.
13 A.As confirmed by two different independent
14 evaluators,the 2017R RFP was fair,transparent,and
15 unbiased.The independent evaluators found that the bids
16 selected to the 2017R RFP final shortlist represent the
17 top offers that are viable under current transmission
18 planning assumptions,and the Utah independent evaluator
19 found that the final shortlist of bids should result in
20 significant savings for customers.While solar-resource
21 bids submitted into the 2017R RFP may provide customer
22 benefits,contrary to claims from certain parties,
23 solar-resource bids are not a superior resource
24 alternative to the Combined Projects.When considering
25 solar resource valuation risks,expected cost declines,
582 Link,Supp-Reb -76
Rocky Mountain Power
1 and availability of the 30-percent ITC for solar projects
2 coming online as late as 2021,PacifiCorp does not need
3 to act now and has decided not to select any of the
4 solar-PPA bids to the 2017S RFP final shortlist.
5 PacifiCorp will continue to reassess potential economic
6 benefits from solar-resource opportunities through
7 bi-lateral opportunities and in the 2019 IRP,considering
8 a thorough assessment of valuation risks with full
9 stakeholder engagement,to determine whether a new
10 competitive solicitation process for projects capable of
11 achieving commercial operation by the end of 2021 will
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23
24
25
583 Link,Supp-Reb -76a
Rocky Mountain Power
\
1 provide customer benefits.
2 In contrast,the phase out of PTC benefits that
3 are available for qualifying wind projects occurs sooner
4 than the ramp down of ITC benefits that are available for
5 solar resources,which requires that PacifiCorp must act
6 now to deliver the new wind and needed transmission
7 investments that will produce both near-term and
8 long-term benefits for customers.This conclusion is
9 supported by thorough and extensive economic analyses
10 that is based on over 1,300 20-year simulations of
11 PacifiCorp's system,which have been used to evaluate how
12 the net benefits of the Combined Projects are affected by
13 a variety of variables and uncertainties.
14 Q.Does this conclude your supplemental rebuttal
15 testimony?
16 A.Yes.
17
18
19
20
21
22
23
24
25
584 Link,Supp-Reb -77
Rocky Mountain Power
1 Q.Are you the same Rick T.Link who previously
2 provided testimony in this case on behalf of Rocky
3 Mountain Power,a division of PacifiCorp?
4 A.Yes.
5 PURPOSE AND SUMMARY OF TESTIMONY
6 Q.What is the purpose of your settlement
7 testimony?
8 A.I provide and describe the economic analysis
9 that quantifies customer benefits with removal of the
10 Uinta project from the portfolio of new wind resources
11 that were identified in my second supplemental direct
12 testimony.With removal of Uinta,the company is seeking
13 to construct and procure three new wind projects-TB Flats
14 I and II,Ekola Flats,and Cedar Springs-totaling 1,150
15 megawatts ("MW")and seeking to construct the
16 Aeolus-to-Bridger/Anticline transmission line and the
17 network upgrades associated with the three wind projects
18 (collectively,the "Stipulated Projects").
19 Q.Please summarize your settlement testimony.
20 A.As described in the settlement testimony of
21 company witness Joelle R.Steward,the company has agreed
22 to no longer seek a certificate of public convenience and
23 necessity for the 161-MW Uinta project in this case.My
24 testimony summarizes the economic analysis of the
25 Stipulated Projects with the removal of Uinta and its
585 Link,Sett -1
Rocky Mountain Power
1 associated interconnection network upgrades.This
2 analysis demonstrates that even without Uinta,the
3 Stipulated Projects are expected to continue to provide
4 substantial customer benefits in all nine price-policy
5 scenarios when studied through 2036 and in seven of nine
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
586 Link,Sett -la
Rocky Mountain Power
1 scenarios when studied through 2050.This economic
2 analysis continues to demonstrate that the Stipulated
3 Projects remain a critical element of PacifiCorp's
4 least-cost,least-risk plan to deliver reasonably priced
5 and reliable service for its customers.Therefore,the
6 Idaho Public Utilities Commission should approve the
7 stipulation because it is in the public interest.
8 STIPULATED WIND PROJECTS
9 Q.Please summarize the cost-and-performance
10 attributes of the stipulated wind projects.
11 A.With removal of the Uinta project,the total
12 in-service capital cost for the remaining wind projects
13 is approximately $(redacted)billion.Relative to the
14 company's initial filing,the per-unit capital cost of
15 the stipulated wind projects is down (redacted)percent
16 from $1,590/kilowatts ("kW")to $(redacted)/kW.The
17 power-purchase agreement pricing for 50 percent of the
18 output of the Cedar Springs project is unchanged from
19 what was described in my second supplemental direct
20 testimony (Link Second Supp.Dir.,page 4,lines 3-10.)
21 And in aggregate,the stipulated wind projects are
22 expected to operate at a capacity-weighted average annual
23 capacity factor of (redacted)percent.
24 Q.What is the nominal value of federal production
25 tax credits ("PTCs")relative to the in-service capital
587 Link,Sett -2
Rocky Mountain Power
1 cost of the stipulated wind projects?
2 A.Over the first 10 years of operation,the
3 stipulated wind projects that will be owned by PacifiCorp
4 will generate over $(redacted)billion in PTC benefits,
5 which is nearly 103 percent
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
588 Link,Sett -2aRockyMountainPower
1 of the in-service capital for these wind facilities.O 2 ECONOMIC ANALYSIS OF STIPULATED PROJECTS
3 Q.Has the company updated the economic analysis
4 based on the removal of the Uinta project?
5 A.Yes.First,I performed a spreadsheet analysis
6 to estimate the high-level economic impact of removing
7 the Uinta project.I performed this spreadsheet analysis
8 for all nine price-policy scenarios previously described
9 in my testimony.Consistent with the company's prior
10 economic analysis,I provide these results based on the
11 integrated resource plan ("IRP")methodology through 2036
12 and using nominal revenue requirement projections through
13 2050.
14 Q.Please describe how you performed the
15 high-level spreadsheet analysis.
16 A.Using data from the economic analysis presented
17 in my second supplemental direct testimony,Exhibit No.
18 55 for results through 2036 and Exhibit No.56 for
19 results through 2050,I calculated the system benefits,
20 including the Uinta Project,on a
21 dollar-per-megawatt-hour basis for each price-policy
22 scenario.I then multiplied these results by the expected
23 generation from the Uinta project to estimate the annual
24 system benefits associated with the Uinta project in
25 total dollars.These system-benefit estimates were then
589 Link,Sett -3
Rocky Mountain Power
1 netted against the same project-specific costs for the
2 Uinta facility that were used in the economic analysis
3 summarized in my second supplemental direct testimony.
4 This calculation results in an estimate of the marginal
5 net benefit or cost of
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
590 Link,Sett -3a
Rocky Mountain Power
1 removing the Uinta project for each price-policy
2 scenario.
3 Q.Did you also update the economic analysis using
4 the company's models?
5 A.Yes.I also re-ran the company's IRP models to
6 remove Uinta under the medium natural gas,medium carbon
7 dioxide ("CO2")and low natural gas,zero CO2 price-policy
8 scenarios.
9 Q.Did you update any of the other inputs used in
10 the analysis?
11 A.No.Other than removing Uinta,all the other
12 inputs used in the economic analysis are the same as the
13 inputs used in the company's second supplemental direct
14 testimony filed on February 16,2018.
15 Q.What is the high-level estimate of the economic
16 impact of removing Uinta based on results through 2036?
17 A.Table 1-ST reports the high-level estimate of
18 the economic impact of removing Uinta based on the
19 results through 2036.These present-value revenue-
20 requirement differential ("PVRR(d)")results are shown
21 alongside the results summarized in my second
22 supplemental direct testimony.The difference between the
23 original results that include Uinta and the high-level
24 estimates without Uinta are an indicator of the marginal
25 net benefit or cost of the Uinta project.
591 Link,Sett -4
Rocky Mountain Power
21
Table 1-ST.Estimated Impactof RemovingUinta3PaRStochasticMeanPVRR(d)(Benefit)/Cost($million)through2036
Second
4 Price-PolicyScenario Di ith Esti a out (Ben t of
5 Uinta)
Low Gas,Zero CO2 ($150)($146)($4)
Low Gas,Medium CO2 ($179)($172)($7)
7 Low Gas,High CO2 ($337)($312)($25)
8 MediumGas,Zero CO2 ($319)($296)($23)
9 MediumGas,Medium CO2 ($357)($330)($27)
10 MediumGas,High CO2 ($448)($410)($38)
11 High Gas,Zero CO2 ($568)($517)($51)
12 High Gas,Medium CO2 ($603)($548)($55)
High Gas,High CO2 ($694)($629)($66)
13
14
15
16 Q.What conclusions can you draw from the results
17 provided in Table 1-ST?
18 A.The high-level estimate based on results
19 through 2036 shows that net benefits of the Stipulated
20 Projects are reduced by between $4 million and $66
21 million.In the medium natural gas,medium CO2
22 price-policy scenario,net benefits are reduced by $27
23 million.Considering that results from the IRP models
24 were used to select winning bids in the 2017R Request for
25 Proposals ("RFP"),these findings confirm that it was
592 Link,Sett -5RockyMountainPower
1 reasonable to include Uinta in the 2017R RFP final
2 shortlist,and that there could still be an opportunity
3 to pursue this project to deliver customer benefits
4 outside of this proceeding.Importantly,these results
5 also show that the Stipulated Projects will continue to
6 deliver substantial net customer benefits with removal of
7 the Uinta project.With Uinta removed,the net benefits
8 from the Stipulated Projects range between
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
593 Link,Sett -5a
Rocky Mountain Power
1 $146 million and $629 million.In the medium natural gas,
2 medium CO2 price-policy scenario,the net benefits are
3 estimated to be $330 million.
4 Q.What is the high-level estimate of the economic
5 impact of removing Uinta based on nominal revenue
6 requirement results through 2050?
7 A.Table 2-ST reports the high-level estimate of
8 the economic impact of removing Uinta based on the
9 nominal revenue requirement results through 2050.These
10 PVRR(d)results are shown alongside the results
11 summarized in my second supplemental direct testimony.
12 Like Table 1-ST above,the difference between the
13 original results that include Uinta and the high-level
14 estimates without Uinta are an indicator of the marginal
15 net benefit or cost of the Uinta project.
16 Table 2-ST.Estimated Impactof RemovingUinta
Nominal PVRR(I)(Benefit)/Cost($million)through1050
Soond17¯'~Supþlètnèniar.....--High-Level ..-MarginaL,
Price-PolicyScenario Direct Filing (With Estimate (Without (Benefit)/Costof
18 -Uinta)Uinta)Uinta
19 Low Gas,Zero CO2 $184 $146 $38
20 Low Gas,MediumCO2 $127 $97 $31
Low Gas,High CO2 ($147)($145)($2)
21
MediumGas,Zero CO2 ($92)($97)$5
22 Medium Gas,MediumCO2 ($167)($162)($4)
2 3 MediumGas,High CO2 ($304)($283)($20)
2 4 High Gas,Zero CO2 ($448)($411)($37)
2 5 High Gas,MediumCO2 ($499)($456)($43)
High Gas,High CO2 ($635)($576)($59)
594 Link,Sett -6RockyMountainPower
1 Q.What conclusions can you draw from Table 2-ST?
2 A.The high-level estimate based on nominal
3 revenue requirement results through 2050 shows that
4 removal of Uinta reduces the net cost of the Stipulated
5 Projects in three of the nine price-policy scenarios and
6 that the net benefits of the Stipulated Projects are
7 reduced in six of the nine price-policy scenarios.In the
8 medium natural gas,medium CO2 price-policy scenario,net
9 benefits are reduced by $4 million.Importantly,when the
10 impact of net benefits are based on nominal revenue
11 requirement results through 2050,these results show that
12 the Stipulated Projects will continue to deliver
13 substantial net customer benefits with removal of the
14 Uinta project.With Uinta removed,the net benefits from
15 the Stipulated Projects in the scenarios where they occur
16 range between $97 million and $576 million.In the medium
17 natural gas,medium CO2 price-policy scenario,the net
18 benefits are estimated to be $162 million.
19 Q.What is the economic impact of removing Uinta
20 based on updated results from the IRP model runs?
21 A.Table 3-ST reports the high-level estimate of
22 the economic impact of removing Uinta alongside the
23 updated modeled results using the 2036 and 2050
24 calculation methodologies.These results are presented
25 for both the low natural gas,zero CO2 and the medium
595 Link,Sett -7
Rocky Mountain Power
1 natural gas,medium CO2 price-policy scenarios.The table
2 also shows the difference between the high-level estimate
3 and the modeled results.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
596 Link,Sett -7a
Rocky Mountain Power
1
2 Table 3-ST.Estimated Impactof RemovingUinta
Nominal PVRR(d)(Benefit)/Cost($million)through2050
3 PaR Stochastic Mean PVRR(d)(Benefit)/Cost($million)through2036
4 High-Level Estimate ModeledResult Variance fromPrice-PolicyScenario (Without Uinta)(Without Uinta)Modeled Result
5 Low Gas,Zero CO2 ($146)($143)($3)
6 Medium Gas,MediumCO2 ($330)($338)$8
7 Nominal PVRR(d)(Benefit)/Cost($million)through2050
High-Level Estimate ModeledResult Variance fromPrice-PolicyScenario (Without Uinta)(Without Uinta)ModeledResult
Low Gas,Zero CO2 $146 $154 ($8)
9 MediumGas,MediumCO2 ($162)($174)$12
10
11
12 Q.What conclusions can you draw from Table 3-ST?
13 A.First,the modeled results are similar to the
14 high-level estimates described above,and consequently,
15 the high-level estimates provide a reasonable
16 representation of the impact of removing Uinta.
17 Second,under the medium natural gas,medium
18 CO2 price-policy scenario,the Stipulated Projects still
19 provide net customer benefits when Uinta is removed.When
20 calculated from IRP model results through 2036,customer
21 net benefits are $338 million (down by $19 million from
22 $357 million that was reported in my second supplemental
23 direct testimony).When calculated from the nominal
24 revenue requirement results through 2050,customer net
25 benefits are $174 million (up by $7 million from the $167
597 Link,Sett -8
Rocky Mountain Power
1 million that was reported in my second supplemental
2 direct testimony).
3 Third,under the low natural gas,zero CO2
4 price-policy scenario,the Stipulated Projects still
5 provide net customer benefits with Uinta removed when the
6 PVRR (d)is
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
598 Link,Sett -8a
Rocky Mountain Power
1 calculated from IRP model results through 2036.Based on
2 this methodology,customer net benefits are $143 million
3 (down by $7 million from the $150 million benefit that
4 was reported in my second supplemental direct testimony).
5 When calculated from the nominal revenue requirement
6 results through 2050,net costs are $154 million (down by
7 $30 million from the $184 million that was reported in my
8 second supplemental direct testimony).
9 Q.Have you calculated the change in capital costs
10 that would have to occur to eliminate net benefits in the
11 medium natural gas,medium CO2 price-policy scenario?
12 A.Yes.In my supplemental rebuttal testimony,I
13 responded to Mr.Eldred's testimony on the percentage
14 increase in capital costs that would eliminate net
15 benefits and testified that in-service capital costs
16 would have to increase by 9.1 percent (or $205 million)
17 to eliminate net benefits in the medium natural gas
18 price,medium CO2 price-policy scenario.(Link Supp.
19 Reb.,page 39,lines 16-19.)Removal of the Uinta project
20 reduces capital costs for the Stipulated Projects to
21 $(redacted)million.In-service capital costs would have
22 to increase by approximately 11.1 percent (or $(redacted)
23 million)to eliminate net benefits in the medium natural
24 gas,medium CO2 price-policy scenario.My updated results
25 reflect the same corrections to Mr.Eldred's calculations
that were noted in my supplemental rebuttal testimony.
599 Link,Sett -9
Rocky Mountain Power
1 Q.Do the Stipulated Projects without Uinta still
2 provide overall customer net benefits?
3 A.Yes.As set forth above,when using the IRP
4 modeling,the Stipulated Projects still provide robust
5 customer net benefits under all nine price-policy
6 scenarios.Although the benefits have decreased slightly,
7 they remain substantial.In addition,under the nominal
8 revenue requirement view,the net benefits remained
9 fairly consistent,increasing in some price-policy
10 scenarios and decreasing in others.As I described in my
11 prior testimony,although neither view is dispositive,
12 each of these views provides important insight into how
13 the Stipulated Projects are expected to impact the
14 company's revenue requirement.Taken together,each of
15 these views indicate that the removal of Uinta does not
16 adversely impact the customer benefits and the
17 acquisition of the Stipulated Projects remains in the
18 public interest.
19 Q.Does this conclude your settlement testimony?
20 A.Yes.
21
22
23
24
25
600 Link,Sett -10
Rocky Mountain Power
1 (The following proceedings were had in
2 open hearing.)
3
4 DIRECT EXAMINATION
5
6 BY MS.McDOWELL:(Continued)
7 Q Mr.Link,before I make you available for
8 Commission questions and cross-examination,can you just
9 briefly explain your settlement testimony in this
10 docket?
11 A Sure;so as noted,I did support and
12 provide supplemental --well,I guess settlement
13 testimony earlier this week and my testimony focuses on
14 the updated economic analysis to account for the fact
15 that the stipulation between the Company and Staff
16 eliminates one of the projects from the scope of our
17 filing,and so briefly,just to summarize that,with that
18 updated analysis,the stipulated projects still show that
19 there are substantial customer benefits associated with
20 the proposed new wind and associated network upgrades and
21 the new transmission line.
22 We've run our analysis over 10 time frames
23 on a 20-year basis and through 2050 capturing the full
24 life of the wind facilities and on the 20-year basis,
25 that updated economic analysis using base case
CSB REPORTING 601 LINK (Di)
208.890.5198 Rocky Mountain Power
1 assumptions shows a $338 million customer net benefit,
2 and when extrapolated and extended out to 2050,it shows
3 a $174 million customer net benefit.
4 MS.McDOWELL:Thank you,Mr.Link.This
5 witness is available for cross-examination and
6 Commissioner questions.
7 COMMISSIONER ANDERSON:Mr.Budge.
8 MR.BUDGE:No questions
9 COMMISSIONER ANDERSON:Mr.Williams.
10 MR.WILLIAMS:Yes,Mr.Chairman.
11
12 CROSS-EXAMINATION
13
14 BY MR.WILLIAMS:
15 Q Mr.Link,good morning.I just wanted to
16 follow up on that last question.Let me get into it a
17 little bit differently.On page 22 of your supplemental
18 rebuttal testimony at the top of the line,you talk about
19 the benefits of a Company-owned project versus a power
20 purchase agreement,and then you say,"customers will
21 continue to receive the benefits of that resource for as
22 long as it operates."Assuming that the wind or solar
23 PPAs were 20-year contracts and given the fact that in
24 less than 10 years you're already repowering your wind
25 fleet,isn't it just as likely that the Company-owned
CSB REPORTING 602 LINK (X)
208.890.5198 Rocky Mountain Power
1 windmills will be obsolete at the end of 20 years?
2 A I do not agree with that statement.
3 Q But you do agree that after 10 years
4 you've chose to repower existing turbines with better and
5 more enhanced production turbines;correct?
6 A Yes,we have in a separate proceeding,I
7 believe,that's been before this Commission,we did move
8 forward with our wind repowering project,which does
9 replace older vintage equipment with newer equipment,but
10 I would highlight that in that circumstance,that was
11 only done given the substantial economic benefits
12 associated with that decision.
13 Inasmuch as any new project would be
14 developed at some point down the road,any change would
15 be done in a very similar fashion in that it would have
16 to be supported by being a prudent and appropriate
17 decision given the benefits that it might accrue to our
18 customers.
19 Q It also seems when you discuss the
20 benefits of Company-owned versus the benefits of power
21 purchase agreements,one of the things that I don't see
22 in your testimony,but I think it's somewhat the elephant
23 in the room,is that PPA costs are pass-through costs to
24 the utility while utility-owned projects are rate based
25 and earn every year,so my question is a hypothetical
CSB REPORTING 603 LINK (X)
208.890.5198 Rocky Mountain Power
1 one,on a $2 billion rate base investment at a 10 percent
2 ROE and a 50-50 capital structure,wouldn't utility
3 shareholders in the very first year earn 100 million of
4 benefits in the first year of a hypothetical project at 2
5 billion?
6 A I haven't run the precise math.I'm
7 assuming they would speak for themselves.I would simply
8 highlight that we didn't make any resource decisions
9 through our competitive RFP process driven by any
10 shareholder return.Our analysis overseen by two
11 different independent evaluators was purely based on what
12 was the best combination of projects assessed through
13 this competitive process that would provide the most
14 benefit for our customers.That was how we determined
15 which projects to move forward with.
16 Q But back to my question,on my
17 hypothetical,why don't we just assume that that $2
18 billion investment turns 100 million to ratepayers.
19 After the end of the second year,wouldn't the net
20 benefits to the shareholder exceed the net benefits over
21 the 20-year life of the project to the customers in your
22 medium,medium scenario?
23 A I haven't run the numbers under this
24 hypothetical.I'd have to see how that all plays out and
25 analyze that,but I don't know that that's true or not.
CSB REPORTING 604 LINK (X)
208.890.5198 Rocky Mountain Power
1 Q And I'm glad you brought up the
2 independent evaluation,because I'd like to turn to that
3 evaluation,especially in light of your criticisms of Mr.
4 Mullins relying on portions of that independent
5 investigation from Oregon.It's your confidential
6 Exhibit 67 and I have excerpts for the Commissioners if
7 they would prefer the pages I'm going to be referring to.
8 Would that be convenient?
9 COMMISSIONER ANDERSON:Certainly.
10 MR.WILLIAMS:Okay.
11 (Mr.Mullins distributing documents.)
12 Q BY Mr.WILLIAMS:Mr.Link,do you have
13 your Exhibit 67 in front of you?
14 A I do.
15 Q All right,and could you identify this
16 exhibit?
17 A At least what I have in front of me
18 labeled as highly confidential,Exhibit 67,and it is the
19 independent evaluator's final report on PacifiCorp's
20 2017R request for proposals,and it's prepared by Bates
21 White,which is the independent evaluator approved by the
22 Oregon Commission.
23 Q Now,if you would turn to page 4 of that
24 report,these are the recommendations of the independent
25 evaluator in Oregon,and when you look at paragraph C,
CSB REPORTING 605 LINK (X)
208.890.5198 Rocky Mountain Power
1 the second sentence,it reads,"First,in order to
2 protect ratepayers and ensure that they receive the
3 benefits promised during this RFP,we would recommend
4 that all selected resources to be owned by the Company be
5 held to their capital and operations and maintenance cost
6 projections as provided with the bid.These amounts
7 should be considered a hard cap,meaning that there will
8 be no opportunity for the Company to collect additional
9 costs even if they believe such expenditures were
10 prudent."Did I capture that correctly?
11 A Yes.
12 Q And did you reference this section in your
13 testimony of the IE,independent evaluator's,report?
14 A I know I made reference to the IE's
15 report.I can't recall,unless you point me there,
16 explicitly which sentence and the page it's on.
17 Q Yet,the Company objects to this provision
18 or does not agree with this provision in the IE report;
19 correct?
20 A Correct.
21 Q If I could get you to turn the page again
22 to page 5 and that first full paragraph says,this is the
23 third recommendation of the IE,that the Company should
24 similarly be held to their cost projections for the,and
25 I'm going to say,transmission line segment.
CSB REPORTING 606 LINK (X)
208.890.5198 Rocky Mountain Power
I
1 PacifiCorp's resource acquisition strategy here,which
2 includes three projects that rely on the D2 segment's
3 construction for economic viability,is based on a
4 certain cost promise for this segment and the Company
5 should be held to its promises,so do you agree with that
6 provision of the IE report?
7 A We do not agree with this provision and I
8 would highlight that as Mr.Steward just described
9 through the stipulation,we are taking on cost overrun
10 risks through the terms of that agreement with Staff in
11 this docket,and I would also highlight with regard to
12 these recommendations from the Oregon independent
13 evaluator,I recently participated in a special public
14 meeting held by the Oregon Commission,I believe it was
15 last week,in which --well,I'll at least say that the
16 chair of that Commission had identified that this was not
17 within the scope of the independent evaluator's report
18 and recognized --
19 MR.WILLIAMS:Mr.Chairman,I'm going to
20 object to this testimony.This is way beyond the scope
21 of what my questions are and he's providing off-the-cuff
22 spontaneous examples of conversations that is hearsay
23 that he had last week.
24 MS.McDOWELL:Can I respond,if I might?
25 COMMISSIONER ANDERSON:Yes.
CSB REPORTING 607 LINK (X)
208.890.5198 Rocky Mountain Power
1 MS.McDOWELL:So the question was did he
2 agree with this language and he's explaining why he does
3 not.I think it's absolutely within the scope of the
4 question.
5 COMMISSIONER ANDERSON:I'd just advise to
6 keep it as narrow as you can and answer directly as you
7 can without going too far afield.
8 THE WITNESS:I will;so I do not agree
9 with the statements and my primary point was while the
10 Oregon Commission is reviewing its own process associated
11 with these projects,in that meeting,the chair stated
12 that this is not something the Commission would take on
13 at this time.
14 Q BY MR.WILLIAMS:Would you agree that
15 both you and Mr.Mullins have relied on different
16 sections from the same report to support your testimony?
17 A Yes.
18 Q Would you agree that these sections of the
19 IE report that I have read support Staff and all of the
20 intervenors'recommendations that hard caps at cost
21 estimates be imposed and no more than that?
22 A I wouldn't say it supports other
23 recommendations.I would say it simply demonstrates what
24 the Oregon IE's recommendations might be if the
25 Commission were to consider these types of protections in
CSB REPORTING 608 LINK (X)
208.890.5198 Rocky Mountain Power
1 their proceeding.
2 Q Mr.Link,if you could turn to page 26 of
3 your supplemental direct testimony --I'm sorry,
4 supplemental rebuttal,and in essentially the first
5 question and answer on that page,you dispute Mr.
6 Mullins'claim that more economic wind projects were not
7 selected because of their higher queue positions,and
8 that,and I'm reading from line 13,the original bid
9 evaluation and selection process performed by PacifiCorp
10 and monitored by the two independent evaluators,and I
11 stress monitored,demonstrates that the interconnection
12 restudy process did not prevent,in any way,the
13 selection of the projects because of their
14 interconnection queue,so I want to go back to the
15 independent evaluator's report and I'm going to turn to
16 page 32 now,which was also included in my handout,and
17 I'm going to read you that first section.
18 The very first sentence says,and this is
19 the independent evaluator from Oregon speaking,that at
20 this point we believed that the PPA-heavy portfolio
21 should be the top choice.However,when we voiced this
22 opinion to the Company,they claimed that they had
23 concerns regarding interconnection costs for some of the
24 offers.Doesn't this paragraph actually show that the
25 Oregon IE did not support the Company's initial shortlist
CSB REPORTING 609 LINK (X)
208.890.5198 Rocky Mountain Power
1 of Company-owned projects and instead preferred a PPA
2 portfolio?
3 A I don't interpret the terms of this report
4 in that fashion,and I was directly in conversation with
5 not only the Oregon IE,but the Utah IE as we were
6 progressing through this analysis,and I believe what
7 they're highlighting is that there were some alternative
8 resources that perhaps could have been considered in
9 those conversations with the Oregon independent
10 evaluator.They were suggesting at that time,at least
11 to me,that the intent was to make sure they're open for
12 consideration as we continued the review process,and my
13 statements which you started with,I believe,by pointing
14 me in the reference to my supplemental rebuttal testimony
15 around not prohibiting selection is to highlight that,so
16 in my supplemental direct testimony,we had performed an
17 analysis that had identified four projects,I believe,
18 selected at that point in time.
19 This was before the transmission
20 interconnection restudy process had been completed,and
21 then in my second supplemental direct testimony,we had
22 identified that taking into account the findings from
23 that interconnection restudy process,there was a change
24 in our resources,but it was really only to swap out one
25 project,at that time it was our McFadden Ridge II
CSB REPORTING 610 LINK (X)
208.890.5198 Rocky Mountain Power
1 benchmark project for Ekola Flats,and essentially what
2 that restudy process did was allow for a more economic
3 wind project to be included into our ultimate proposal of
4 final resources,but the highlight there is at that point
5 in time,we had not --without the interconnection study,
6 we ended up with essentially the same portfolio,actually
7 a better portfolio,by swapping out one benchmark for
8 another benchmark.
9 Q So back to my question,and I'll read the
10 sentence again,the very first sentence,"At this point,
11 we believed that the PPA-heavy portfolio should be the
12 top choice";so what is the IE referring to when they say
13 "at this point"?
14 A I can't speak precisely for what the --
15 Q What do you think that they meant?
16 A Again,based on my conversations with the
17 IE's,we were proceeding and walking them through routine
18 meetings --
19 Q No,would you answer my question?At this
20 point,what do you think they meant by this statement?
21 A I'm trying to --with respect,I was
22 trying to answer that question,so at this point in time
23 when we were having these meetings,they had some belief
24 that perhaps there could be other alternatives.The IE's
25 also highlighted this analysis that we prepared for them
CSB REPORTING 611 LINK (X)
208.890.5198 Rocky Mountain Power
1 at their request that the projects were essentially very
2 similar in terms of present value revenue requirements,
3 so I think based on my conversations that I had with the
4 IE's,they had a perception that this could be one of the
5 best or an alternative selection,I would say,to what
6 our analysis had produced in that it could be a top
7 choice,but ultimately,this was not the Oregon IE's
8 final recommendation.
9 MR.WILLIAMS:Mr.Chairman,no further
10 questions.
11 COMMISSIONER ANDERSON:Mr.Olsen.
12 MR.OLSEN:Thank you,Mr.Chair.
13
14 CROSS-EXAMINATION
15
16 BY MR.OLSEN:
17 Q Mr.Link,do you have Mr.Yankel's
18 testimony available to you up there?
19 A I do not have Mr.Yankel's testimony.
20 MS.McDOWELL:I can provide it to the
21 witness.
22 (Ms.McDowell approached the witness.)
23 Q BY MR.OLSEN:Mr.Link,I'd like you to
24 turn to his direct testimony,page 12,if you could.
25 A I'm there,thank you.
CSB REPORTING 612 LINK (X)
208.890.5198 Rocky Mountain Power
1 Q Okay,do you recognize the graph in the
2 middle of that page as being from PacifiCorp's 2013
3 IRP?
4 A Yes.
5 Q Does that graph demonstrate the forecast
6 in gas prices used by the Company in the years,if you
7 look at the parentheticals there,for 2010,2012,
8 September 2012,and August of 2011;is that correct?
9 A Yes,I see those dates.
10 Q Okay.Now,if you look here in this
11 graph,the furthest date,there's a forecasted price in
12 2032;is that correct?
13 A Yes.
14 Q And that the 2010 price and the 2011 price
15 is approximately 10.50 per MBTU?
16 A I'm sorry,could you say that again?
17 Q The approximate price if you look at the
18 graph that the price in 2032 for 2011 and 2010 is
19 approximately 10.50 per MBTU?
20 A Approximately,yes.
21 Q Okay.Now,if we look at the 2012
22 forecast below that that it's approximately $9.00 per
23 MBTU;correct?
24 A Assuming reference to 2032,yes.
25 Q Okay;so if you look at the dates at the
CSB REPORTING 613 LINK (X)
208.890.5198 Rocky Mountain Power
1 beginning point in 2013,you can also see there's a delta
2 between the 2013,which is the September 2012 forecast,
3 and the previous year's forecast as well;correct?
4 A Yes.
5 Q And what is that trend?
6 A In the deltas?
7 Q Yes,in the deltas.
8 A By my judgments,the deltas between the
9 curves look relatively stable.
10 Q No,I mean the amount,so it's going
11 downward,isn't it,the prices?
12 A Yes,the figure shown for the data series
13 labeled as 2012 is lower than the other data series.
14 Q Okay.If you could turn to page 14 of
15 Mr.Yankel's testimony,do you recognize that as a graph
16 coming from the Company's 2015 IRP?
17 A Subject to check,I'll stipulate that that
18 is there,yeah.
19 Q Okay,great;so if you look at the price
20 for 2015 there,looking at that initial mark,do you see
21 that's approximately $3.00,is that correct,per MBTU?
22 A Yes.
23 Q Okay.If we go back in figure --page 12,
24 Figure 2,if you look at 2015 for the forecast in the
25 2013 IRP,the price is approximately $5.00 per BTU;is
CSB REPORTING 614 LINK (X)
208.890.5198 Rocky Mountain Power
1 that correct?
2 A In what year were you referencing in?
3 Q 2015,same year.
4 A It's less than $5.00.
5 Q Okay,approximately 4.50 or so?
6 A Perhaps.
7 Q Okay,but the delta or the trend in the
8 next IRP there on page 14 forecast is that the delta is
9 trending downward or the overall prices are going down;
10 isn't that correct?
11 A Yes,I would say that forward prices in
12 the 2015 IRP were lower than the forward prices in the
13 prior IRP.
14 Q Okay.If you could turn to page 16 of Mr.
15 Yankel's testimony,subject to check,would you agree
16 that that's the Company's forward price curve for the
17 2017 IRP?
18 A Just looking at the labels,subject to
19 check,it looks like it's taken from our IRP,but perhaps
20 maybe not used,and I only state that because it's
21 labeling an annual strip as of a January 20th date,which
22 knowing how we develop our official forward price curve,
23 it's almost always at quarter end on a rolling basis,so
24 it's perhaps taken,but I don't know under what context.
25 I don't know if it was used in the IRP.
CSB REPORTING 615 LINK (X)
208.890.5198 Rocky Mountain Power
1 Q Okay,subject to check,we'll just want to
2 make some comparisons here as to the natural gas prices,
3 so if you look at that,do you agree that the forecast
4 price for 2017 is about approximately 3.25 per million
5 BTU?
6 A Approximately.
7 Q Okay;so then if we look back at the 2015
8 table on page 14,if you look at the 2017 price there,
9 it's approximately $3.60 per million BTU?
10 A Approximately.
11 Q Okay;so from the 2015 IRP to the 2017,do
12 you agree that that's,subject to check,approximately a
13 10 percent decrease between those two forecasts?
14 A I'll just say the numbers referenced,I
15 guess,speak for themselves without having to calculate
16 the percentage.
17 Q Okay.Why don't we jump back to page 16
18 there.Looking at the overall curve that you have on
19 that graph,isn't that shape of that curve different from
20 the previously forecasted prices on page 12 and page
21 14?
22 A Yes.
23 Q Okay.Now,what do you think accounts for
24 that difference in your mind?
25 A It's hard for me to determine what the
CSB REPORTING 616 LINK (X)
208.890.5198 Rocky Mountain Power
1 market,perhaps that a NYMEX futures contract is imputing
2 into those future contract prices,so it's uncertain to
3 me precisely what might be driving the difference in
4 shape.
5 Q Okay,but as we can see here for 2017,the
6 forecasted prices continue to trend significantly
7 downward in the near future,isn't that correct,based on
8 the graph on page 16?
9 A I would describe the trend in the chart on
10 page 16 as trending downward for two years and then a
11 gradual and over time increasingly upward trend through
12 the chart through 2029.
13 Q Could you turn to page 41 of your
14 supplemental rebuttal testimony?
15 A I'm sorry,could you please repeat the
16 page number?
17 Q Yes,page 41,Mr.Link.
18 A Thank you.
19 Q You make reference to Mr.Yankel's
20 testimony that he believes that continued low natural gas
21 prices will be the norm and you make a statement here and
22 put it in quotes and the last sentence says that despite
23 the lack of bias,et cetera,that as noted above and
24 assumes the current price for conditions and you quote
25 "price floor."What are you referencing there by price
CSB REPORTING 617 LINK (X)
208.890.5198 Rocky Mountain Power
1 floor and who said that?
2 A I'd have to go back and check,but I
3 interpret this as the price for conditions as meaning
4 current pricing will persist as noted in the remaining
5 part of that statement through conditions over the next
6 32 years.
7 Q Could you turn to Mr.Yankel's
8 supplemental testimony --
9 A Yes.
10 Q --and specifically Exhibit 401.Exhibit
11 401 is --
12 A I'm not sure I have the Exhibit 401.I
13 have the testimony.Yes,I'm sorry.
14 Q Okay.If you could turn to the last page
15 of that Exhibit 401,I guess the first full paragraph
16 there,it says that this week Jeffries,and this is
17 talking about a financial forecast analysis,lowered
18 their natural gas price forecasts for this year and next
19 to $2.80 per MBTU from 3.25,and that Raymond James
20 predicts an even lower 2.75 over that time.Would you
21 agree that low prices for natural gas are at least in the
22 near term the norm?
23 A I think describing qualitatively whether a
24 price is low is somewhat subjective or is subjective.I
25 would say our forward price curves actually rely on
CSB REPORTING 618 LINK (X)
208.890.5198 Rocky Mountain Power
1 observed market forwards,our base case analysis,whereO2themarketistransactingonagivenpointintime,and
3 so inasmuch as one believes the current market is low,
4 then that is what's in our base case analysis for at
5 least the first six to seven years.
6 MS.OLSEN:I have no further questions.
7 COMMISSIONER ANDERSON:Thank you.Mr.
8 Karpen.
9 MR.KARPEN:Yes,thank you.
10
11 CROSS-EXAMINATION
12
13 BY MR.KARPEN:
14 Q Good morning,Mr.Link.
15 A Good morning.
16 Q I'd kind of like to proceed through my
17 questioning based on category.The Company's view of the
18 need for the combined projects has evolved over the
19 application period;is that correct?
20 A I don't agree with that
21 characterization.
22 Q So you wouldn't agree that in your earlier
23 testimony that you had qualified or classified this as an
24 economic benefit to customers and in your later testimony
25 you have qualified it more as an immediate need for
CSB REPORTING 619 LINK (X)
208.890.5198 Rocky Mountain Power
1 generation?O 2 A I think it can be both at the same time.
3 Q Okay;so let's start here.I apologize to
4 the Commission,I'm getting my pages straight.As
5 everyone is well aware,this record is large and I'm
6 trying to go as expediently as possible.
7 In your direct rebuttal on page 9,you
8 note that the load and resource balance presented in the
9 2017 IRP shows a near-term resource need,accounting for
10 assumed retirement of resources,blah,blah,blah;is
11 that correct?
12 A So I just caught up to you.You're at
13 page 9?
14 Q Page 9.It's the first full question.
15 This confirms that you're stating that there's an
16 immediate need?
17 A Yes.
18 Q Yet,in your direct testimony filed,I
19 believe,six months earlier,if we go to page 6,first
20 full question [sic]you say,"At the same time,the
21 load-and-resource balance developed for the 2017 IRP
22 shows that PacifiCorp would not require incremental
23 system capacity to meet its 13 percent planning-reserve
24 margin until 2028."Is that not --is 2028 immediate?
25 A I would actually like to finish the
CSB REPORTING 620 LINK (X)
208.890.5198 Rocky Mountain Power
1 reference to the rest of that statement,which says --O 2 Q Certainly.
3 A --"accounting for assumed coal unit
4 retirements,incremental energy efficiency savings,and
5 available wholesale-power market purchase opportunities";
6 so when accounting for those additional elements,this
7 statement was intended to represent,which is accurate in
8 the context of our 2017 IRP,that at that time the first
9 generating resource would potentially show up in the 2028
10 time frame.However,when you don't account for
11 uncommitted market purchases,and this is in our 2017 IRP
12 load and resource balance,there is identified in that
13 document the system position is short from 2017 through
14 2036.
15 Q So why wouldn't you account for those as
16 you did in your earlier testimony?
17 A I guess I would separate two issues.
18 There's identification of system position or capacity
19 need.Accounting for unavailable FOTs is one resource
20 option that can be used to meet the need once you've
21 identified it,as well as all others,including demand
22 side management,generating resources of all ilk,whether
23 they're fossil fired,renewable,wind,solar,storage.
24 We look at all of these opportunities and resource
25 alternatives in our IRP,and so in this context,it was
CSB REPORTING 621 LINK (X)
208.890.5198 Rocky Mountain Power
1 highlighting that if one were to assume acquisition ofO2marketpurchasesasameanstoheightentheneedthat
3 shows up in year one,along with these additional
4 elements,that you would likely anticipate the first
5 generating resource in roughly the 2028 time frame;
6 however,with the PTCs on these wind resources at
7 question in this proceeding,they're actually lower cost
8 than those market purchases and lower risk,which is why
9 they're ultimately part of our preferred portfolio.
10 Q Now,when Mr.Louis in his testimony tried
11 to distinguish between the need,the resource need,and
12 need for capacity,in your supplemental rebuttal on page
13 6,I can quote you saying,"Mr.Louis's attempt to
14 distinguish between resource need and the need for
15 capacity to meet load is misguided and not supported,"
16 yet you make that distinction yourself.
17 A Could you please clarify what I'm
18 distinguishing?
19 Q Between resource need and the need for
20 capacity.
21 A I just view those as one and the same in
22 the sense that oftentimes when you have a capacity
23 shortfall,that identifies some sort of need,resource,
24 to fill it,and my point in that statement is to simply
25 identify I don't know how to distinguish between those
CSB REPORTING 622 LINK (X)
208.890.5198 Rocky Mountain Power
1 two terms and so they're one and the same as far as I'm
2 concerned.
3 Q But in your direct testimony they're not.
4 There wasn't a need until 2028.
5 A No,I'm describing there isn't a need
6 after accounting for energy efficiency,coal unit
7 retirements,and market purchases that are not yet
8 committed.
9 Q I'll move on.Mr.Williams talked to you
10 quite a bit about the Oregon independent evaluator.I'll
11 try not to repeat too much.Your rebuttal testimony on
12 page 10 --
13 A Is this supplemental rebuttal?
14 Q No,it is not.
15 A Okay.
16 Q Oh,yes,it is,I apologize.It is
17 supplemental rebuttal.
18 A Thank you.
19 Q You state that you disagreed with Mr.
20 Eldred's conclusion as well as Monsanto and PIIC that the
21 2017 RFP was biased,and your conclusion was that it was
22 directly contrary to the conclusions of the independent
23 evaluators;is that accurate?
24 A Yes.
25 Q So I'll have you refer to the Oregon
CSB REPORTING 623 LINK (X)
208.890.5198 Rocky Mountain Power
1 independent evaluator's report,which I believe isO2CompanyExhibit67.Also,for the ease of reference,it
3 is Staff Exhibit 103.If you can turn to page 5,final
4 paragraph that starts with "Third,"the Oregon
5 independent evaluator states,"While ultimately the issue
6 had no impact on winning projects selected in the RFP due
7 to transmission issues noted,the Company's modeling
8 method,which levelized cost but not benefits of PTC
9 acquisition,could have biased the bid selection to less
10 favorable offers";so would you still conclude that the
11 Oregon IE's conclusion is directly contrary or would you
12 say that their conclusion is that it could have been
13 biased?
14 A Yeah,my statements,I think,are made in
15 other elements of the IE's,I'd have to go and look for
16 them,where they conclude in their ultimate conclusion
17 and review of our RFP process that it was fair,
18 implemented according to how it was approved by the
19 Commission.I think in this content he said it could
20 have been biased;did not conclude that it was biased.
21 Q But it wasn't that it could have not been
22 biased,so it's not directly contrary?
23 A With regard to this statement,I will
24 concede to that.
25 Q Okay.Now,you have created the modeling
CSB REPORTING 624 LINK (X)
208.890.5198 Rocky Mountain Power
1 for the project,the nine cost scenarios that we'll beO2referringtothroughoutthiscase;is that right?
3 A Yes.
4 Q And that is three different price
5 scenarios for potential futures of gas,natural gas,and
6 three different potential futures for CO2;is that
7 right?
8 A Yes.
9 Q In your direct testimony,page 30,you
10 provide a table that is the annual revenue requirement.
11 Obviously,this has been updated for the projects,but I
12 believe this was the first bite that shows the revenue
13 requirements with possible future outcomes,conceding
14 that those numbers have been updated for projects.The
15 conclusion in your direct testimony shows that if the
16 project comes in at the estimated bids,customers will
17 receive benefits in seven of the nine projected
18 scenarios;is that accurate?
19 A Can you please point me to the table
20 number,because I think I might have a slightly different
21 page number?
22 Q Yes,it's Table 3-SD.It's page 30 of
23 your direct --the supplemental,I apologize.
24 A Yeah,I was in my direct instead of my
25 supplemental.
CSB REPORTING 625 LINK (X)
208.890.5198 Rocky Mountain Power
1 Q Bear with me,I'm also trying to navigate.
2 In fact,I have your updated one I just found as well in
3 your second supplemental on page 17.
4 A Okay.
5 Q It compares the updated final shortlist.
6 A Yes.
7 Q And it shows the same,that if the Company
8 comes in at its cost estimates with the Company's
9 projected future scenarios,customers can expect to see
10 benefits in seven of nine possible futures --
11 A Yes.
12 Q --is that right?
13 A Yes.
14 Q That is --that only is the case,though,
15 if the Company comes in at its projected estimates,
16 though;right?If,for example,the Company goes over
17 its estimates that that narrows the likelihood that
18 customers will see benefits?
19 A Certainly,costs higher than the estimates
20 would affect the net benefits.The magnitude of that
21 cost relative to which price policy scenario would
22 vary.
23 Q On page 6 of your direct testimony,this
24 is going back to need,I apologize for jumping around --
25 A Direct,so our initial filing?
CSB REPORTING 626 LINK (X)
208.890.5198 Rocky Mountain Power
1 Q Yes.O 2 A I'm there.
3 Q You state that Wyoming resource selections
4 at or near the limitation on Wyoming wind capacity caused
5 by transmission constraints indicated clear potential for
6 incremental customer benefits if incremental transmission
7 is added to accommodate more PTC-eligible wind resources
8 located in Wyoming.When you say "clear potential,"does
9 this not indicate that the initial transmission is needed
10 only for incremental wind?
11 A No,this statement was made in the context
12 of progressing through our IRP process,our public input
13 process,where initially we were doing runs before we
14 looked at transmission sensitivities or analysis with
15 Energy Gateway projects included in them,and in those
16 studies,we were finding that Wyoming wind resources were
17 being chosen up to a maximum amount we allowed to
18 account --and that the limit was associated with the
19 transmission constraints in that part of the system,so
20 whenever the model is choosing something at the limit,
21 it's highly unusual that is precisely what it would like
22 to do if it had larger opportunity;in other words,it's
23 an indicator that it would love to do more wind,it would
24 love to find more economic wind if it were allowed to do
25 so,and that statement is intended to represent that
CSB REPORTING 627 LINK (X)
208.890.5198 Rocky Mountain Power
1 that's what we were seeing at the time that led us down
2 the path of exploring if we threw in additional
3 transmission,accounting for the costs,is there
4 potential for upside even more benefits from that
5 additional amount of wind and the PTCs,again,accounting
6 for the cost of transmission that would enable that to
7 happen.
8 Q But without the new wind,there's no need
9 for transmission?Without the new transmission,there's
10 no justification for the wind via the PTC benefits?
11 A Well,I would say not in the context of
12 this time and in the IRP framework.As Mr.Vail has
13 testified for the Company,there is a need for the
14 transmission projects given the transmission limitations
15 in that part of the system,that at some point it would
16 likely require some level of investment to update our
17 transmission system in Wyoming,but at this time and in
18 the context solely of the least cost,least risk IRP
19 framework,which is what my testimony was describing,
20 that additional transmission would enable us to at least
21 explore the opportunity of whether there would be
22 additional benefits that could accrue with the additional
23 wind,and ultimately,we found that to be the case and is
24 the start of why we're fundamentally here today.
25 Q I have only got a little bit left.On
CSB REPORTING 628 LINK (X)
208.890.5198 Rocky Mountain Power
1 page 33 of your supplemental rebuttal testimony --
2 A I'm there.
3 Q Strike that,actually.Skip a few more
4 pages,let's go to page 39,I apologize.
5 A Did you say 39?
6 Q Yes.This is an easy one,too.You take
7 issue with Staff witness Eldred's calculations on the
8 breakevens by about 9 million.Staff concedes the
9 calculation errors.You would agree that the
10 calculations by Mr.Eldred are accurate with regard to
11 breakeven pricing of the projects?
12 A To make sure I understand the question
13 correctly,if Staff concedes,then,I think the number
14 stated in that testimony is the accurate number on line
15 18.Well,there's two numbers on line 18,the first
16 number on line 18 which is not confidential,so I'll call
17 it out,205 million.
18 Q With regard to the table created by Mr.
19 Eldred,I believe that was a more extensive breakeven on
20 all nine of your scenarios.Those adjustments made would
21 correct the remaining table;is that right?
22 A Yes,the difference between the 205
23 million and the 196 million in that paragraph being 9
24 million would be identical across all nine price policy
25 scenarios.
CSB REPORTING 629 LINK (X)
208.890.5198 Rocky Mountain Power
1 Q You were here for Ms.Steward's testimony.O 2 Are you familiar with that as well as the Wyoming
3 stipulation that was entered into;is that right?
4 A Yes.
5 Q Ms.Steward testified that the Company has
6 attained a CPCN in Wyoming related to this project;is
7 that right?
8 A Yes.
9 Q Is that CPCN contingent on anything,for
10 example,contingent on securing your remaining rights of
11 way?
12 A Yes,it's a conditional approval of the
13 CPCNs for these projects with the conditions being just
14 as stated on procurement of the rights of way.
15 Q Has the Company secured all the rights of
16 way?
17 A This would be a question best,I think,
18 directed at Mr.Teply to give an update on the status as
19 that's part of his role,Mr.Teply or Mr.Vail.
20 Q All right,I'll ask them.Finally,
21 Ms.Steward indicated that the Company has agreed to a
22 hard cap in Wyoming.Through her redirect,she indicated
23 that that was over 10 percent above estimates,cost
24 estimates.Without giving the number specifically,would
25 you indicate whether it's more or less than 12 percent
CSB REPORTING 630 LINK (X)
208.890.5198 Rocky Mountain Power
1 above cost estimates?O 2 A I will maybe even do one better and point
3 you to my --let me get the name of my testimony
4 correct --my settlement testimony and that number is
5 shown with the percentage on page 9,row 16.
6 MR.KARPEN:Thank you.I have nothing
7 further for this witness.
8 COMMISSIONER ANDERSON:Thank you.Any
9 questions from the Commission?
10
11 EXAMINATION
12
13 BY COMMISSIONER RAPER:
14 Q Good morning.
15 A Good morning.
16 Q So I'm going to take us out of the weeds a
17 bit.My questions are related to and surround some of
18 the capacity sufficiency questions.In the 2017 IRP
19 that's been filed and I believe acknowledged by this
20 Commission at this point,what was the capacity
21 deficiency date identified in the 2017 IRP?
22 A 2017,so without procurement of any
23 uncommitted resources,market purchases that have not
24 been made or secured,contracted with,there's a
25 capacity --there's a system position shown in the IRP,I
CSB REPORTING 631 LINK (Com)
208.890.5198 Rocky Mountain Power
1 believe it's even Table 5.14 that --I've read a lot of
2 IRPs --highlights that deficiency starting year 1
3 through 2036.
4 Q So if I take you at your word that 2017 is
5 identified as the capacity deficiency date for the
6 utility,then your PURPA projects begin to get payments
7 on their capacity at that moment?I mean,that's the
8 year that I'm looking for in the 2017 IRP.
9 A Sure.I think,and every state is
10 different,from Idaho's perspective,my understanding is
11 it's tied to the date of the generating resource showing
12 in the IRP,but I can't recall specifically.
13 Q Well,I know you were talking about
14 accounting for market purchases --
15 A Yes.
16 Q --doesn't the utility typically account
17 for market purchases when it is determining its capacity
18 sufficiency?
19 A We have shown it on our load and resource
20 balance in our IRP,so that it's clear that if one
21 assumes that those purchases are made up to the limits
22 that we have in our IRP where that first crossover point
23 would occur and historically,absent production tax
24 credit-type benefits that we're looking at here and
25 particularly considering that's done early in the IRP
CSB REPORTING 632 LINK (Com)
208.890.5198 Rocky Mountain Power
1 process what your need looks like,it provides a pretty
2 good indicator of when you're done with the IRP where
3 you're likely to see the first generating resource,and
4 that's why we show here is our system position without
5 anything.Here's our amount of market purchases so that
6 our stakeholders get a sense of where that crossover
7 point were to occur.
8 I think when I'm stating that we have an
9 immediate need,it's recognizing if there's something
10 lower cost than a market purchase when we're doing our
11 IRP,it can show up certainly earlier than that.That's
12 normally not the case in prior IRPs,but the PTCs for
13 these assets really change that and it's why they're
14 meeting that need,part of that need I should even say.
15 There's remaining need after them in lieu of the market
16 purchases.
17 Q Okay,but you talk about resources and you
18 specifically said generating resources,to your
19 knowledge,has this Commission ruled that market
20 purchases and the accounting for market purchases is
21 validly considered as a resource when looking at the
22 utility's capacity sufficiency or deficiency,however you
23 want to identify it?
24 A Sure.I'm not familiar with all of the
25 Commission's Orders in that context.
CSB REPORTING 633 LINK (Com)
208.890.5198 Rocky Mountain Power
1 Q Okay,would you trust me,subject to
2 check --
3 A I believe I would.
4 Q --that this Commission has,because it
5 has been different utilities in the state positions that
6 market purchases should be accounted for --
7 A Sure.
8 Q --within that category,so then with the
9 original application PacifiCorp made,860 megawatts,
10 where does that push the capacity deficiency date to if
11 you assume that because December 31st,2020,is the date
12 you have to have those in service,right,in order to
13 secure those PTCs;is that right?
14 A Uh-huh,by the end of 2020.
15 Q Okay;so then you add 860 megawatts to
16 your system,what does that immediately on January 1,
17 2021,where does that deficiency date move to?How long
18 is the Company capacity sufficient with a an additional
19 860 megawatts?
20 A Sure,860 megawatts on a capacity planning
21 basis accounts for about --we have about 15 percent of
22 that is what's available at the time given that wind is a
23 variable resource.Its capacity contribution value is
24 15.8 percent of the 860,so it is --I'm trying to do
25 that math in my head quickly.Let's call that around 80,
CSB REPORTING 634 LINK (Com)
208.890.5198 Rocky Mountain Power
1 plus half of that,so 120 megawatts,roughly,of capacity
2 that could be used to hit that capacity position.
3 Q I haven't heard a date.I'm looking for a
4 year that the Company becomes capacity sufficient with
5 that energy.
6 A From the traditional IRP view,which is
7 what I am familiar with,which does look --has looked at
8 FOTs as a resource within PacifiCorp for as long as I've
9 been doing the IRP,we would still be short immediately
10 capacity.The 100 and --what did I just say,120
11 megawatts of the 860 is not enough to offset the
12 immediate capacity deficiency period in our forecast.
13 That's true in the IRP and also our IRP update,which we
14 just filed earlier this week.
15 Q So then the settlement stip that you
16 entered into with the Staff which removes one of those
17 wind generators,so you have three remaining,.would
18 clearly put you in a capacity deficiency scenario
19 immediately as well,because you're losing one of your
20 wind generators?
21 A Except I would highlight that now that
22 number is 1,150 megawatts instead of 860 even without the
23 project that we're removing.The 860 in our initial
24 application was a proxy estimate at the time.Having
25 gone through the IRP,now with that project removed,
CSB REPORTING 635 LINK (Com)
208.890.5198 Rocky Mountain Power
1 we're at 1,150.That's about 180 megawatts of capacity
2 contribution value to our system,and yes,it doesn't
3 entirely offset.There is still need beyond that,which
4 our plan shows would be met with other resources,like
5 market purchases and energy efficiency and DSM.
6 Q So if you were to add market purchases to
7 that number at December 2020,where would that put you?
8 A We would buy sufficient market purchases
9 at that point to balance our system to our 13 percent
10 planning margin.
11 Q And that would put you at what year?
12 A We do that in every year,so we would buy
13 less in,say,2020 by about 180 megawatts,assuming low
14 growth is flat just for sake of just relative to the
15 prior year,so that 180 megawatts of new wind capacity
16 contribution would defer the need to buy 180 megawatts,
17 roughly,of market purchases,but every year we're making
18 sure we balance our system to hit our needs with the 13
19 percent margin.
20 Q Understood,but I'm not getting a lot of
21 years out of you and I appreciate that you function on a
22 megawatt basis.What I'm trying to get at is it looks
23 like a lot of energy all at once when your market
24 purchases,accounting for market purchases,wouldn't have
25 you adding that otherwise.Now,I appreciate that your
CSB REPORTING 636 LINK (Com)
208.890.5198 Rocky Mountain Power
1 testimony is that with the PTCs,which are also
2 contingent on getting everything built by the end of
3 2020,with the PTCs,that offsets the difference,is that
4 right,that then market purchases aren't your least cost
5 scenario?
6 A That's correct.
7 Q As long as the PTCs are accounted for?
8 A Yes.
9 COMMISSIONER RAPER:I still didn't get
10 the years,but I think I got to where I needed to be.
11 Thank you.
12 THE WITNESS:You're welcome.
13 COMMISSIONER ANDERSON:Redirect?
14 MS.McDOWELL:Thank you.
15
16 REDIRECT EXAMINATION
17
18 BY MS.McDOWELL:
19 Q Maybe just to see if we can clarify that
20 last point,I believe your testimony has been that these
21 resources serve both the short-and long-term need.Can
22 you address the long-term need that you allude to in that
23 testimony?
24 A Yes,building on the conversation or
25 question that we just had,what I was describing is what
CSB REPORTING 637 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 is occurring in the near term right out of the gate in
2 2021,but as you progress further out in time,the 180
3 megawatts in the example of the stipulated projects,
4 which is what we're supporting now,would begin in,say,
5 that 2028 time frame when there was otherwise a
6 generating resource showing up would start to displace in
7 the future higher cost resource alternatives,like
8 generating assets or direct load control programs or
9 whatever those may be in context of our planning
10 process.
11 Q And with the displacement of that
12 longer-term resource,how far back in your planning
13 process does that push that new generating resource?
14 A It doesn't entirely eliminate it.It
15 generally starts to change the resource mix,so the
16 combination is lower cost,because there's 180 megawatts
17 less of capacity that's needed to procure,so
18 timing-wise,subject to checking the exhibits from our
19 latest runs,would show that it's in the 2028-2029 time
20 frame for just lower cost capacity.
21 Q So I believe it was Mr.Karpen addressed
22 your benefits chart and your most recent version
23 indicating in a 2015 nominal look that there's net
24 benefits in seven of the nine scenarios.Do you recall
25 that testimony?
CSB REPORTING 638 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 A Yes.Yes,I do.
2 Q So I believe he asked you were there
3 benefits in seven of the nine scenarios.Can you explain
4 what benefits exist in all nine scenarios?
5 A Yes,I can.I believe the range is
6 somewhere between 1.14 billion on a present value basis
7 and 1.4 or so billion dollars.That's kind of the gross
8 benefit and so in the numbers shown that we were walking
9 through on the exhibits,that's net benefits,so net of
10 the project cost,but the gross benefits associated with
11 net power cost savings from the zero fuel cost energy,
12 the production tax credits,the resource deferral,the
13 capacity,you know,resource deferral benefits are
14 incorporated into that larger number and that's over a
15 billion dollars for each of these,if I recall.
16 Q In all nine scenarios?
17 A Yeah,in all nine.They range across the
18 cases,but they're substantial.
19 MR.BUDGE:For clarification,counsel,
20 when you say in all nine scenarios,do you mean on a
21 combined basis?
22 MS.McDOWELL:Yes,I'm talking about the
23 chart that Mr.Karpen asked him about.I can clarify
24 that.
25 MR.BUDGE:Clarifying your question,you
CSB REPORTING 639 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 intended to say the combined benefit is all nine projects
2 combined?The good ones and the bad ones still end up
3 with a benefit;is that what you're --
4 MS.McDOWELL:No,let me just clarify my
5 question.
6 COMMISSIONER ANDERSON:I'd like to maybe
7 have it directed to the Chair,too.If you have a
8 question,bring it to me and I'll see if I want to even
9 entertain it,and what we're going to do right now and I
10 was hoping we could wrap up this portion of it,but we're
11 going to take a break,and my job is to direct traffic
12 and if we don't get out of this traffic jam,you better
13 start thinking about what you want for dinner,because
14 we're going to stay tonight.We're going to stay for
15 awhile,because if we've got two days allocated to us to
16 do this hearing,we're going to get moving along and
17 we're going to let everybody have their opportunities,
18 but I don't want side banter.I don't want any of that
19 going on.We're taking a break for five minutes.
20 Thanks.
21 (Recess.)
22 COMMISSIONER ANDERSON:Ms.McDowell,you
23 can continue with your redirect.
24 MS.McDOWELL:Thank you.
25 Q BY MS.McDOWELL:Good morning,Mr.Link.
CSB REPORTING 640 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 A Good morning.
2 Q Before the break I was asking you about
3 your benefits table.I was just asking you about it
4 without actually having pointed you to a page,so I'd
5 like to direct your attention to page 6 of your
6 settlement testimony,your most recent testimony.
7 A Yes,I'm there.
8 Q And just to be clear,the most recent
9 cost-benefit analysis the Company has done would be the
10 second column over in that chart at the bottom of page 6;
11 is that correct?
12 A Yes.This chart shows a high-level
13 estimate across all nine price policy scenarios
14 accounting for removal of one of the projects.
15 Q And can you describe in your opinion,are
16 those numbers conservative in terms of the Company's
17 analysis?
18 A Yeah,I think,yes,I would highlight
19 there are a level of conservative assumptions into our
20 analysis that were highlighted in my testimony,a handful
21 of these.One is to note that we have not accounted in
22 these figures for any renewable energy credit or REC
23 revenue that could potentially accrue with the additional
24 energy produced by these projects and for every
25 megawatt-hour of output,there's a REC essentially
CSB REPORTING 641 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 produced for that,so these don't capture any upside
2 benefits in that regard.
3 I also highlighted in my testimony that we
4 anticipate that there are likely to be operations and
5 maintenance cost savings relative to the assumptions used
6 in our financial analysis.This is largely driven by the
7 fact that on several of the projects,there are much
8 larger wind turbine generators,so there's ultimately
9 because they're bigger turbines relative to other
10 technologies,there are fewer turbines per site and that
11 lowers overall O&M costs.Our estimates used in the
12 analysis are based on our operational experience of
13 operating our existing wind fleet which don't have those
14 larger turbines,so they're conservative in that regard.
15 The analysis from a CO2 perspective,we
16 used real costs instead of nominal inadvertently when we
17 updated our studies.It's a pretty minor upside
18 adjustment,but recognizing that if CO2 prices were to
19 accrue,these are understating a little bit the benefits
20 for those cases that have CO2 price assumptions applied.
21 And I think maybe even another one to
22 highlight,if the Company were to proceed down the path
23 of having to construct the transmission line at some
24 point down the road after the availability of these PTCs
25 as those things ramp down,that would be a cost increase
CSB REPORTING 642 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 to kind of the base case world without the stipulated
2 projects.That is not reflected at all in any of these
3 analyses,which would be a pretty substantial upside
4 under that scenario.
5 Q Mr.Link,you were also asked some
6 questions about the Oregon IE report and my notes are
7 unclear about which of the counsel asked you this
8 question,but I recall you were asked a question about
9 whether it was somehow inconsistent for you to cite the
10 Oregon IE report as supportive of the Company's
11 shortlist.Do you recall that question?
12 A Yes.
13 Q And you indicated that there were
14 provisions of the report that supported that testimony,
15 but you just didn't recall them offhand.Do you recall
16 that testimony?
17 A Yes.
18 Q So can I direct your attention to page 2
19 and 3 of the Oregon IE report where the Oregon IE has
20 that summary?I believe that's Exhibit 67.
21 A Yes,I'm there.
22 Q Do you have that?
23 A Yes.
24 Q So does that refresh your recollection
25 about the IE's conclusions that supported your
CSB REPORTING 643 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 testimony?
2 A Yes.
3 Q And can you expand on that,please?
4 A There are,I think,several areas here.
5 The IE notes that the selected bids,you know,the first
6 bullet under the recommendation that supports the basis
7 for the Oregon IE's recommendation to the Oregon
8 Commission to acknowledge the shortlist of bids is that
9 they were the top offers that are viable under the
10 current transmission assumptions,and I'm paraphrasing
11 for sake of time.They've confirmed in their own
12 independent analysis that the bids were reasonably
13 priced;that they worked them through their own models
14 and they looked at all the terms and conditions of each
15 bid.
16 They confirmed the accuracy of the
17 benchmark costs at the bottom bullet on page 2.They did
18 their own independent review of all of our benchmark
19 bids,which were locked down and submitted before any
20 market bids came in,so that review was done even in
21 advance of any other bids coming in through the door.
22 They also note that it aligns,the RFP
23 itself aligns,with the IRP,and I'm on page 3,that it
24 used current assumptions from the IRP,noting that the
25 model we applied in the RFP bid selection process was the
CSB REPORTING 644 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 same models we used in the RFP itself --sorry,I mean
2 IRP.I think that generally summarizes those points.
3 MS.McDOWELL:That's all I have for this
4 witness.Thank you.
5 COMMISSIONER ANDERSON:Thank you,Ms.
6 McDowell.
7 (The witness left the stand.)
8 COMMISSIONER ANDERSON:Ms.McDowell,just
9 a quick note,did you intend originally to have the
10 exhibits also entered in the record?
11 MS.McDOWELL:Yes,I did.
12 COMMISSIONER ANDERSON:So without
13 objection,Mr.Link and Ms.Steward's exhibits will be
14 also be entered into the record.
15 MS.McDOWELL:Thank you very much.
16 (Rocky Mountain Power's exhibits sponsored
17 by Ms.Joelle Steward and Mr.Rick Link were admitted
18 into evidence.)
19 COMMISSIONER ANDERSON:Well,thank you
20 very much,Mr.Link.
21 THE WITNESS:Thank you.
22 (The witness left the stand.)
23 COMMISSIONER ANDERSON:We're going to go
24 ahead and do lunch right now.It's going to be a short
25 lunch.We'll be back at 1:00,as close to 1:00 as we
CSB REPORTING 645 LINK (ReDi)
208.890.5198 Rocky Mountain Power
1 can.
2 MS.McDOWELL:Thank you.
3 (Lunch recess.)
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING 646 COLLOQUY
208.890.5198