20180529Technical Hearing Transcript Vol III part 1.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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 E en
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 III -Pages 647 -1163
ORIGINAL CSB REPORTING
&Certgied Shorthand Reporters
PostOfficeBox9774 Reporter:Boise,Iddx>83707 Constance Bucy,[e-mail] CSRPh:208-890-5198 Fax:[phone]
1 A PPE A R A NCES
2
3 For the Staff:Mk.Brandon Karpen
Deputy Attorney General
4 472 West Washington
Boise,Idaho 83720-0074
5
For Rocky Mountain Ms.Katherine A.McDowell
6 Power:and N .Adam Lowney
McDowell Rackner Gibson PC
7 419 SW 11th Avenue
Suite 400
8 Portland,Oregon 97205
9 For Idaho Irrigation Mk.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:N .Ronald L.Willions
16 Williams,Bradbury,P.C.
1015 West Hays Street
17 PO Box 388
Boise,Idaho 83701
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CSB REPORTING APPEARANCES
208.890.5198
1 I NDEX02WITNESSEXAMINATION BY PAGE
3 Cindy Crane Ms.McDowell (Direct)647
(RMP)Direct Testimony 650
4 Rebuttal Testimony 683
Supplemental Testimony 700
5 Second Supplemental Testimony 713
Supplemental Rebuttal Testimony 724
6 Mr.Budge (Cross)743
Mr.Karpen (Cross)785
7 Commissioner Raper 796
Ms.McDowell (Redirect)799
8
Rick Vail Mr.Lowney (Direct)804
9 (RMP)Direct Testimony 806
Rebuttal Testimony 879
10 Supplemental Testimony 932
Second Supplemental Testimony 945
11 Supplemental Rebuttal Testimony 960
Mr.Budge (Cross)985
12 Mr.Williams (Cross)988
Mr.Karpen (Cross)1001
O 13
Chad Teply Mr.Lowney (Direct)1009
14 (RMP)Direct Testimony 1011
Rebuttal Testimony 1048
15 Supplemental Testimony 1081
Second Supplemental Testimony 1118
16 Supplemental Rebuttal Testimony 1140
Mr.Williams (Cross)1156
17 Mr.Karpen (Cross)1159
Commissioner Kjellander 1161
18 Mr.Lowney (Redirect)1162
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CSB REPORTING INDEX
208.890.5198
1 EXH I B I TS
(III 2
3 NUMBER DESCRIPTION PAGE
4 FOR ROCKY MOUNTAIN POWER:
5 1.Information &Subpart Exhibits Premarked
For the Ekola Flats Proxy Project Admitted 1010
6
2.Information &Subpart Exhibits Premarked
7 For the TB Flats I &TB Flats II Admitted 1010
Proxy Projects
8
3.Information &Subpart Exhibits Premarked
9 For the McFadden Ridge II Proxy Admitted 1010Project
10
4.Transmission Project Overview Premarked
11 Admitted 805
12 5.Exhibit sponsored by Rick Vail Premarked
Admitted 805
13
6.Energy Gateway West Aeolus to Premarked
14 Jim Bridger Admitted 805
15 7.Aeolus Substation drawings Premarked
Admitted 805
16
8.Anticline Substation drawings Premarked
17 Admitted 805
18 9.Confidential exhibit sponsored Premarked
by Rick Vail Admitted 805
19
10.Confidential exhibit sponsored Premarked
20 by Rick Vail Admitted 805
21 11.Confidential exhibit sponsored Premarked
by Rick Vail Admitted 805
22
12.Energy Gateway West Aeolus to Premarked
23 Jim Bridger Admitted 805
24 13.Exhibit sponsored by Rick Vail Premarked
25
Admitted 805
CSB REPORTING EXHIBITS
208.890.5198
1 EXH I B I TS (Continued)
2 NUMBER DESCRIPTION PAGE
3 FOR ROCKY MOUNTAIN POWER:(Continued)
4 14.Exhibit sponsored by Rick Vail Premarked
Admitted 805
5
15.500-kV Transmission Line ROW Premarked
6 on Federal Lands Admitted 805
7 16.Exhibit sponsored by Rick Vail Premarked
Admitted 805
8
17.Aeolus to Jim Bridger Project Premarked
9 Admitted 805
10 18.Aeolus to Jim Bridger Project Premarked
Admitted 805
11
19.Gateway West Transmission Line Premarked
12 Project Admitted 805
O 13 20.Stormwater Pollution Prevention Premarked
Plan Admitted 805
14
21.Major Permits,Approvals,&Premarked
15 Consultations for the Gateway Admitted 805
16 West Transmission Line Project
17 30.Aeolus West Transmission Path Premarked
Transfer Capability Assessment Admitted 805
18
31.Information for the Cedar Springs Premarked
19 Wind Energy Project Admitted 1010
20 32.Information for the TB Flats I &Premarked
II Wind Energy Project Admitted 1010
21
33.Information for the McFadden Premarked
22 Ridge II Wind Energy Project Admitted 1010
23 34.For the Uinta Wind Energy Project Premarked
Admitted 1010
24
O 35.Confidential exhibit sponsored Premarked
25 by Chad Teply Admitted 1010
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 46.Information for the Ekola Flats Premarked
Wind Energy Project Admitted 1010
6
47.Confidential exhibit sponsored Premarked
7 by Chad Teply Admitted 1010
8 48.Interconnection Network Upgrades Premarked
Admitted 805
9
49.QO715 SIS Report &Q0810 SIS Premarked
10 Report Admitted 805
11 50.QO717 SIS Report &Q0708 SIS Premarked
Report Admitted 805
12
51.QO712 SIS Report Premarked
13 Admitted 805
14 52.Q706 Facility Study Premarked
Admitted 805
15
53.EPC and LSA Contract Forms Premarked
16 Admitted 805
17 66.Letter to the Lincoln County Premarked
Commission from the Wyoming Admitted 1010
18 State BLM Director
19 70.Wyoming State Energy Profile Marked 1219
20
71.Order No.30657 in PAC-E-8-03 Marked 1221
21
22 72.PacifiCorp 2017 IRP Identified 1225
Chapter 4 -Transmission
23
73.Cause No.43426 S1 before the Identified 1228
24 Indiana Utility Regulatory
25
Commission
CSB REPORTING EXHIBITS
208.890.5198
1 EXH I B I TS (Continued)
2 NUMBER DESCRIPTION PAGE
3 FOR ROCKY MOUNTAIN POWER:(Continued)
4 74.Comments of Monsanto Company Identified 1481
in PAC-E-17-03
5
6 FOR THE MONSANTO COMPANY:
7 201.Qualifications of Kathryn Premarked
E.Iverson Admitted 1248
8
202.Monsanto Company's Second Data Premarked
9 Request to Rocky Mountain Power Admitted 1248
10 203.Annual Cost (Benefit)of Combined PremarkedProjectsAdmitted 1248
11
204.Qualifications of James R.Premarked
12 Dauphinais Admitted 1165
0 13 205.RMP Response to WIEC 2.2 in Docket Premarked
No.20000-520-EA-17 of the Wyoming Admitted 1165
14 Public Service Commission
15 206.RMP Response to WIEC Informal Premarked
Data Request 1.1 in Docket Admitted 1165
16 20000-520-EA-17 of the Wyoming
Public Service Commission
17
207.RMP Response to WIEC 7.1 in Docket Premarked
18 No.20000-520-EA-17 of the Wyoming Admitted 1165
Public Service Commission
19
208.RMP Response to WIEC 7.3 in Docket Premarked
20 No.20000-520-EA-17 of the Wyoming Admitted 1165
Public Service Commission
21
209.Qualifications of Nicholas L.Premarked
22 Phillips Admitted 1248
23 210.Various RMP Responses to WIEC Premarked
in Docket No.20000-520-EA-17 of Admitted 1248
24 the Wyoming Public Service
25
Commission
CSB REPORTING EXHIBITS
208.890.5198
1 EXH I B I TS (Continued)
2 NUMBER DESCRIPTION PAGE
3 FOR THE MONSANTO COMPANY:(Continued)
4 211.Response to WIEC Data Premarked
Request 22.2 Admitted 1165
5
212.Response to WIEC Data Premarked
6 Request 22.4 Admitted 1165
7 213.March 30,2018,Study Report -Premarked
Aeolus West Transmission Path Admitted 1165
8 Transfer Capability Assessment
9 214.March 22,2018,Updated Study Premarked
Summary Admitted 1165
10
215.Final Facilities Study for Premarked
11 Boswell Wind Projects Admitted 1165
12 216.Response to WIEC Data Premarked
Request 17.7 Admitted 1165
13
217.RMP's Responses to Discovery Premarked
14 Requests Admitted 1248
15 218.Utah Independent Evaluation Premarked
Excerpt Admitted 1248
16
219.Idaho Statues,Title 61 Marked 745
17 Admitted 752
18 220.PacifiCorp 2017 IRP Marked 768Chapter1-Executive Summary
19
221.Dictionary excerpts for the Marked 752
20 word "necessity"Admitted 752
21
22
FOR PACIFICORP IDAHO INDUSTRIAL CUSTOMERS:
23
308.FERC -Order Granting Request Marked 997
24 for Limited Waiver
25
CSB REPORTING EXHIBITS
208.890.5198
1 BOISE,IDAHO,THURSDAY,MAY 10,2018,1:00 P.M.
2
3
4 COMMISSIONER ANDERSON:We will call the
5 meeting back to order.Thanks to everybody for being so
6 timely after lunch,that's perfect,and just a quick
7 reminder for Connie's sake,our court reporter,pull your
8 mics forward and talk a little bit louder,if we can,and
9 a reminder just to go slow,but if you don't go slow,
10 Connie will let you know and then you'll slow down then,
11 so let's continue on with the Company.
12 MS.McDOWELL:Thank you,Commissioner.
13 We would call Ms.Cindy Crane.
14
15 CINDY A.CRANE,
16 produced as a witness at the instance of Rocky Mountain
17 Power,having been first duly sworn to tell the truth,
18 was examined and testified as follows:
19
20 DIRECT EXAMINATION
21
22 BY MS.McDOWELL:
23 Q Good afternoon,Ms.Crane.
24 A Good afternoon.
25 Q For the record,can you please state and
CSB REPORTING 647 CRANE (Di)
208.890.5198 Rocky Mountain Power
1 spell your full name?
2 A Yes,Cindy Crane,C-i-n-d-y,C-r-a-n-e.
3 Q Ms.Crane,how are you employed?
4 A I'm employed by Rocky Mountain Power.
5 Q What's your position at Rocky Mountain
6 Power?
7 A I am the president and CEO.
8 Q In that capacity have you prepared
9 testimony in this proceeding?
10 A Yes,I have.
11 Q And is that testimony your direct,
12 rebuttal,supplemental direct,second supplemental direct
13 testimony with a subsequent correction to that,and then
14 your supplemental rebuttal testimony?
15 A That is correct.
16 Q If I were to ask you the questions that
17 were stated in that testimony today,would your answers
18 be the same?
19 A Yes,they would.
20 Q Do you have any changes or corrections to
21 that testimony?
22 A I do not.
23 MS.McDOWELL:So Commissioner,I would
24 ask that that testimony be spread on the record.
25 COMMISSIONER ANDERSON:Without objection,
CSB REPORTING 648 CRANE (Di)
208.890.5198 Rocky Mountain Power
1 we will spread Ms.Crane's testimony,all those inclusive
2 titles,and exhibits.
3 MS.McDOWELL:Ms.Crane does not have any
4 exhibits.
5 COMMISSIONER ANDERSON:Thank you.
6 MS.McDOWELL:And just for reference,
7 it's on the exhibit list here.She is one of the few who
8 does not have exhibits.
9 COMMISSIONER ANDERSON:Very good.
10 (The following prefiled direct,rebuttal,
11 supplemental direct,second supplemental direct,and
12 supplemental rebuttal testimonies of Ms.Cindy Crane are
13 spread upon the record.)
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CSB REPORTING 649 CRANE (Di)
208.890.5198 Rocky Mountain Power
1 Q.Please state your name,business address,and
2 present position.
3 A.My name is Cindy A.Crane.My business address
4 is 1407 West North Temple,Suite 310,Salt Lake City,
5 Utah 84116.I am the President and Chief Executive
6 Officer of Rocky Mountain Power ("Company"),a division
7 of PacifiCorp.
8 Q.Briefly describe your professional experience.
9 A.I joined the Company in 1990 and have served as
10 Director of Business Systems Integration,Managing
11 Director of Business Planning and Strategic Analysis,
12 Vice President of Strategy and Division Services,and
13 Vice President of Interwest Mining Company and Fuel
14 Resources.My responsibilities in these positions
15 included the management and development of PacifiCorp's
16 10-year business plan,directing operations of the Energy
17 West Mining and Bridger Coal companies,and coal supply
18 acquisition and fuel management for PacifiCorp's
19 coal-fired generating plants.In October 2014,I was
20 appointed to my present position as President and Chief
21 Executive Officer of Rocky Mountain Power.
22 Q.Have you testified in previous regulatory
23 proceedings?
24 A.Yes.I have filed testimony with the public
25 service commissions in all of the states where the
650 Crane,Di -1
Rocky Mountain Power
1 Company serves customers,including the Idaho PublicO2UtilitiesCommission("Commission").
3 PURPOSE AND SUMMARY OF TESTIMONY
4 Q.What is the purpose of your testimony?
5 A.My testimony details the Company's proposal to
6 invest $2 billion in new wind and transmission
7 facilities,all of which would be operational by December
8 31,2020,as required to leverage the full benefit of the
9 federal wind production tax credit ("PTC"),
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651 Crane,Di -la
Rocky Mountain Power
1 the value of which is essential to the combined projects'O 2 overall economic viability.The Wind Projects and
3 Transmission Projects,as defined and described below,
4 are the cornerstones of PacifiCorp's Energy Vision 2020
5 strategy.These projects represent an exciting
6 opportunity for PacifiCorp's customers,who we expect to
7 realize approximately $137 million in benefits over time,
8 with initial rate impacts of less than 1.9 percent.
9 My testimony provides an overview of the
10 Company's Application,which includes a request for
11 certificates of public convenience and necessity
12 ("CPCNs")for new wind and transmission facilities,and a
13 request for binding ratemaking treatment for the
14 investment in the wind and transmission projects,in
15 accordance with Idaho Code §61-541.The Company proposes
16 to construct or procure four new Wyoming wind resources
17 with a total capacity of 860 megawatts ("MW")
18 (collectively,the "Wind Projects")and to construct the
19 Aeolus-to-Bridger/Anticline Line and 230 kV Network
20 Upgrades,as defined and discussed in more detail later
21 (collectively,the "Transmission Projects").I explain
22 why these resource decisions are prudent and in the
23 public interest,discuss the Company's financial ability
24 to invest in the proposed facilities,and describe how
25 the Company has pursued them in good faith.
652 Crane,Di -2
Rocky Mountain Power
1 Q.Please summarize your testimony.
2 A.The Wind Projects and Transmission Projects
3 (collectively,the "Combined Projects")are central to
4 the Company's current long-term energy strategy,Energy
5 Vision 2020,under which the Company plans to use the
6 opportunities presented by the extension of the federal
7 PTC to make major resource investments that provide
8 significant savings to customers over the lives of the
9 resources.The Company identified and presented this
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653 Crane,Di -2a
Rocky Mountain Power
1 opportunity in its 2017 Integrated Resource Plan ("2017
2 IRP").
3 The Transmission Projects and Wind Projects are
4 mutually dependent on one another.The Wind Projects rely
5 on the Transmission Projects for interconnection into the
6 Company's transmission system.In turn,the Transmission
7 Projects are supported by the key economic attributes of
8 the Wind Projects:zero-fuel-cost generation that lowers
9 net power costs and provides ten years of PTCs.The Wind
10 Projects also generate renewable energy certificates
11 ("RECs"),which can be sold in the market and lower net
12 customer costs.The Wind Projects help decarbonize the
13 Company's resource portfolio,mitigating long-term risk
14 associated with potential future state and federal
15 policies targeting carbon dioxide ("CO2")emissions
16 reductions from the electric sector.
17 The Transmission Projects also provide
18 significant benefits to customers.The Aeolus-to-Bridger/
19 Anticline Line is a sub-segment of the Company's Energy
20 Gateway West transmission project,and is an integral
21 component of the long-term transmission plan for the
22 region.The Company,with stakeholder involvement,has
23 pursued permitting of the Energy Gateway West
24 transmission project since 2008.The Transmission
25 Projects relieve congestion on the current transmission
654 Crane,Di -3
Rocky Mountain Power
1 system in eastern Wyoming,provide critical voltage
2 support to the Wyoming transmission network,improve
3 overall reliability of the transmission system,enhance
4 the Company's ability to comply with mandated reliability
5 and performance standards,reduce line losses,and create
6 the potential for further increases to the transfer
7 capability across the Aeolus-to-Bridger/Anticline Line
8 with the construction of additional segments of the
9 Energy Gateway project.
10 Timing is critical for both of these projects.
11 The Combined Projects must
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655 Crane,Di -3a
Rocky Mountain Power
1 achieve commercial operation by the end of 2020 to
2 qualify for the full benefits of the PTCs and maintain
3 favorable economics.Thus,the Company must move quickly,
4 particularly on the Transmission Projects,which will
5 take several years to fully permit,obtain the necessary
6 rights-of-way,and construct.To complete construction of
7 the Combined Projects by December 31,2020,the Company
8 requests that the Commission adopt the proposed schedule
9 for review set forth in the Application.
10 Because of the time-sensitivity of the Combined
11 Projects,the Company is conducting its 2017R Request for
12 Proposals ("2017R RFP")process simultaneously with its
13 request for CPCNs for the Wind Projects.Although
14 unusual,this approach is necessary in this case.If the
15 Company waited until the conclusion of the 2017R RFP to
16 seek CPCNs,the Combined Projects could not be completed
17 by the end of 2020,and customers would lose significant
18 PTC benefits.To allow the Combined Projects to move
19 forward,the Company has pursued the Wind Projects,which
20 will be benchmark resources in the 2017R RFP and proxy
21 resources for purposes of the Application until the 2017R
22 RFP is completed.
23 The Company also requests approval of binding
24 ratemaking treatment for the Combined Projects in
25 accordance with Idaho Code §61-541.The proposed
656 Crane,Di -4
Rocky Mountain Power
1 ratemaking treatment,known as the Resource Tracking
2 Mechanism ("RTM"),is designed to capture customer
3 benefits and match those benefits with the costs of the
4 Combined Projects.The RTM would operate until the costs
5 and benefits of the Combined Projects are fully included
6 in base rates through a general rate case.The RTM would
7 be included as a component of the ECAM.Once the full
8 costs and benefits are included in base rates,only the
9 incremental fluctuations associated with production
10 levels of energy and
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657 Crane,Di -4a
Rocky Mountain Power
1 PTCs would continue to be tracked in the ECAM,as they
2 are today,since these are entirely dependent on the
3 variable output of the Wind Projects.The Company would
4 begin deferring the costs and benefits associated with
5 each new facility in the month it goes into service.
6 Using medium price and CO2 assumptions,the
7 Company's economic analysis demonstrates a present-value
8 reduction in revenue requirement due to the Combined
9 Projects of $137 million over the life of the projects,
i
10 with a year-one rate impact of less than 1.9 percent.
11 Q.What other witnesses will be testifying on
12 behalf of the Company?
13 A.In addition to my testimony,the Company's
14 Application is supported by the testimony of the
15 following witnesses:
16 Mk.Chad A.Teply,Vice President of Strategy
17 and Development,provides a detailed description of the
18 Company's proposed acquisition of the Wind Projects.Mr.
19 Teply describes the Wind Projects,addresses the impact
20 and timing of PTCs on their acquisition,and provides
21 information to respond to the requirements of Rule 112 of
22 the Commission Rules of Procedure ("RP").
23 Mk.Rick A.Vail,Vice President of
24 Transmission,outlines the need for the Transmission
25 Projects,and provides a detailed description of the
658 Crane,Di -5
Rocky Mountain Power
1 transmission facilities.Mr.Vail also addresses theO2requirementsofRP112.
3 Mr.Rick T.Link,Vice President of Resource
4 and Commercial Strategy,testifies regarding the economic
5 analysis that supports the prudence of the Combined
6 Projects,and describes the customer benefits resulting
7 from the timely acquisition and construction of the wind
8 and transmission facilities.Mr.Link explains the
9 planning and
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659 Crane,Di -5a
Rocky Mountain Power
1 analysis of the Combined Projects in the Company's 2017
2 IRP.He also provides background on the pending 2017R RFP
3 for the wind resources.
4 N .Jeffrey K.Larsen,Vice President of
5 Regulation,explains the Company's proposal for
6 ratemaking treatment of the costs and benefits of the
7 Combined Projects,and the inter-jurisdictional
8 allocation of costs.
9 Q.Has the Company developed a schedule that
10 allows the Commission to process this case in an orderly
11 and expeditious manner?
12 A.Yes.The Company's proposed schedule is
13 included in the Application.
14 Q.Is the Company requesting approval of the
15 Combined Projects in any other states?
16 A.Yes.Concurrent with this Application,the
17 Company is requesting approval of the Combined Projects
18 from the Wyoming Public Service Commission and the Public
19 Service Commission of Utah.There are rate-recovery
20 mechanisms in Oregon and Washington for investments in
21 renewable resources that provide a path to seek recovery
22 of the costs and benefits of the Combined Projects closer
23 in time to project completion.In California,the Company
24 is required to file a general rate case in 2019,which
25 may include the costs and benefits of the Combined
660 Crane,Di -6
Rocky Mountain Power
1 Projects;alternatively,California's Post-Test Year
2 Adjustment Mechanism may be used to recover costs
3 incurred after the 2019 general rate case.
4 OVERVIEW OF COMBINED PROJECTS
5 Q.Please describe the Transmission Projects.
6 A.The Transmission Projects include six major
7 elements:
8 (1)The 140-mile,Aeolus-to-Anticline 500 kV
9 line,which includes construction of the
10 new Aeolus and Anticline substations;
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661 Crane,Di -6a
Rocky Mountain Power
1 (2)The five-mile Anticline to Jim Bridger 345
2 kV line,which includes modifications at
3 the existing Jim Bridger substation to
4 allow termination of the new 345 kV line;
5 (3)Installation of a voltage control device
6 at the Latham substation;
7 (4)A new 16-mile 230 kV transmission line
8 parallel to an existing 230 kV line from
9 Shirley Basin substation to the proposed
10 Aeolus substation,including modifications
11 to the existing Shirley Basin substation;
12 (5)The reconstruction of four miles of an
13 existing 230 kV transmission line between
14 the proposed Aeolus substation and the
15 Freezeout substation,including
16 modifications as required at the Freezeout
17 substation;
18 (6)The reconstruction of 14 miles of an
19 existing 230 kV transmission line between
20 the Freezeout substation and the Standpipe
21 substation including modifications as
22 required at the Freezeout and Standpipe
23 substations.
24 Throughout the Company's testimony,items 1-3 above are
25 collectively referred to the Aeolus-to-Bridger/Anticline
662 Crane,Di -7
Rocky Mountain Power
1 Line,and items 4-6 are collectively referred to as the
2 230 kV Network Upgrades.
3 Q.What are the system benefits of the
4 Transmission Projects?
5 A.The benefits of the Transmission Projects fall
6 into three broad categories.First,the Transmission
7 Projects will relieve congestion in eastern Wyoming,
8 which will allow greater resource interconnection in that
9 part of the state.The Company's current transmission
10 system in eastern Wyoming is operating at capacity,which
11 limits transfer of existing resources from eastern
12 Wyoming and precludes the ability to interconnect
13 additional resources east of the proposed Aeolus-to-
14 Bridger/Anticline Line.The
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663 Crane,Di -7a
Rocky Mountain Power
1 Transmission Projects will increase the transfer
2 capability from east to west by 750 MW.When the
3 Transmission Projects are complete,they will allow
4 interconnection of up to 1,270 MW of incremental wind
5 resources,including the Wind Projects that are the
6 subject of this Application.
7 Second,the Transmission Projects will provide
8 critical voltage support to the transmission system in
9 southeastern Wyoming.Under certain operating conditions,
10 voltage control issues have limited the ability to add
11 additional resources,particularly wind resources.
12 Third,the Transmission Projects will also
13 increase reliability,reduce capacity and energy losses
14 on the transmission system,and provide greater
15 flexibility to manage existing generation resources.
16 Currently,outages on the existing 230 kV system in
17 eastern Wyoming result in deration of the transfer
18 capacity in the area and some outage scenarios require
19 significant generation curtailment.The new 500 kV
20 transmission segment will significantly reduce,if not
21 eliminate,many of the impacts caused by the 230 kV
22 outages.
23 Q.Please describe the proposed Wind Projects.
24 A.The Company requests CPCNs for the construction
25 or acquisition of 860 MW of new wind resources,which are
664 Crane,Di -8
Rocky Mountain Power
1 three 250 MW facilities (referred to as Ekola Flats,TB
2 Flats I,and TB Flats II)and a fourth 110 MW facility
3 (McFadden Ridge II),all located in Wyoming.Mr.Teply's
4 testimony provides additional details on the Wind
5 Projects.
6 Q.Will the Company submit the Wind Projects into
7 the 2017R RFP?
8 A.Yes.Each of the resources will be included in
9 the 2017R RFP as a benchmark resource.Therefore,if
10 other resources are ultimately selected,they will be
11 equal to or better than
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665 Crane,Di -Ba
Rocky Mountain Power
1 the Wind Projects in the Application.The Company submits
2 this Application to facilitate review of this
3 time-limited opportunity to secure CPCNs under the
4 schedule proposed by the Company.
5 Q.What additional information will be provided
6 once the 2017R RFP shortlist is selected?
7 A.After the 2017R RFP shortlist is selected,the
8 Company will supplement this Application to provide the
9 Commission and intervening parties with detailed
10 information about the winning bid(s).
11 Q.What is the status of the 2017R RFP?
12 A.The Company filed for acknowledgment or
13 approval of the proposed 2017R RFP in Utah and Oregon as
14 required in those states.Following those proceedings,
15 the Company anticipates issuing the 2017R RFP to the
16 market in August 2017.The Company plans to complete its
17 final shortlist bid evaluation and finalize the shortlist
18 in early January 2018.Mr.Link's testimony provides
19 additional details on the RFP process.
20 Q.Why is the Company requesting CPCNs for both
21 the Transmission Projects and Wind Projects?
22 A.The Combined Projects are mutually dependent on
23 one another.The Transmission Projects are necessary to
24 relieve existing congestion and will enable
25 interconnection of the proposed Wind Projects into the
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1 Company's transmission system.The Transmission Projects
2 are not economic without incremental,cost-effective Wind
3 Projects generating zero-fuel-cost energy and PTCs.This
4 interdependence requires the Combined Projects'
5 concurrent development.
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1 The renewal of the PTCs has created a unique,
2 time-limited opportunity for the Company to construct
3 critical transmission facilities in eastern Wyoming,
4 while providing substantial customer savings.The
5 economics for the Combined Projects,however,require
6 that they be constructed to meet commercial operation by
7 the end of 2020.
8 Q.Why must the Combined Projects be in commercial
9 operation by the end of 2020?
10 A.The substantial customer benefits resulting
11 from the Combined Projects assumes the Wind Projects will
12 qualify for 100 percent of the PTCs.Each of the Wind
13 Projects are eligible for 100 percent of the PTC benefits
14 if the Wind Projects and the Transmission Projects are
15 commercially operational by December 31,2020.Failing to
16 meet the 2020 deadline puts the Company at risk to lose
17 PTC benefits,and jeopardizes the overall economics of
18 the Combined Projects.
19 Q.How will the Company achieve commercial
20 operation by the end of 2020?
21 A.The Company must obtain CPCNs for the Combined
22 Projects under the timelines proposed,so that equipment
23 and engineering,procurement,and construction contracts
24 can be executed shortly thereafter.Because the lead time
25 for constructing the Transmission Projects is longer than
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1 the lead time to construct the Wind Projects,theO2schedulesfortheTransmissionProjectsdictatethis
3 timeline.The testimonies of Mr.Teply and Mr.Vail
4 provide additional detail on the construction timelines
5 necessary to complete the Combined Projects by the end of
6 2020.
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1 PUBLIC INTERESTO2Q.In its 2017 IRP,did the Company select the
3 Combined Projects as part of the preferred resource
4 portfolio?
5 A.Yes.Both resources are least-cost,least-risk
6 resources,as reflected in the Company's 2017 IRP,filed
7 with the Commission April 4,2017.The 2017 IRP includes
8 the Wind Projects and Transmission Projects as integral
9 components of the Company's preferred portfolio.
10 Q.Do the Combined Projects provide significant
11 benefits to customers?
12 A.Yes.As outlined in Mr.Link's testimony,the
13 Combined Projects will produce customer benefits that
14 significantly outweigh costs.The Company's economic
15 analysis included multiple electricity price and
16 carbon-risk scenarios,measured over several different
17 time periods.In virtually all cases,the Combined
18 Projects result in significant net customer benefits.For
19 example,with medium natural gas and medium CO2 price
20 assumptions over the life of the facilities,the
21 present-value reduction to the change in revenue
22 requirement due to the Combined Projects is $137 million.
23 Because the Company did not quantify the added benefits
24 associated with RECs,the economic analysis is
25 conservative.
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1 Q.What is the projected rate impact to customers
2 of the Combined Projects?
3 A.The rate impact to customers is less than 1.9
4 percent with the first full year of operation in 2021.
5 While this percentage change reflects the year-one impact
6 to customers,it does not fully reflect the value of the
7 Combined Projects due to costs avoided over time.Mr.
8 Link's analysis showing the present-value savings of $137
9 million through 2050 referenced above demonstrates that
10 although there is an initial increase in cost,the
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1 lifetime savings of the Combined Projects are
2 significant.
3 Q.After the Company filed its IRP in April,did
4 Company representatives meet with Idaho stakeholders to
5 provide an overview of the Combined Projects?
6 A.Yes.On May 9,2017,the Company held an
7 informal workshop with Idaho stakeholders to review the
8 details of the Combined Projects,explain the RFP for the
9 wind resources,and discuss the scope and timing of this
10 Application.
11 Q.In addition to the customer benefits you have
12 already mentioned,do the Combined Projects benefit the
13 public interest in other ways?
14 A.Yes.The Transmission Projects will relieve
15 transmission constraints that have limited energy
16 resource interconnection in eastern Wyoming.Once
17 constructed,the Transmission Projects will allow the
18 Company to more efficiently deliver cost-effective energy
19 from Wyoming generation resources.
20 REQUIREMENTS FOR A CPCN AND
BINDING RATEMAKING TREATMENT
21
22 Q.What are the requirements for the Commission to
23 issue a CPCN?
24 A.It is my understanding that the Commission will
25 issue a CPCN if it is in the public interest.To
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1 determine the public interest,the Commission must
2 determine whether the present or future public
3 convenience and necessity require additional resources
4 and whether the proposal is a reasonable means of meeting
5 this need.
6 Q.Does the present or future public convenience
7 and necessity require additional resources?
8 A.Yes.As described above and in more detail in
9 Mr.Link's testimony,the Company's 2017 IRP preferred
10 portfolio includes the Combined Projects as least-cost,
11 least-risk resources to serve long-term customer needs
12 and provide substantial customer benefits.
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1 The time-sensitive opportunity presented by the PTCs
2 allows the Company to provide cost-effective,
3 emission-free generation to serve Idaho customers,while
4 providing the cost savings necessary to construct the
5 required Transmission Projects and provide economic
6 benefits for customers.
7 Q.Are the Combined Projects a reasonable means of
8 meeting the resource need identified in the 2017 IRP?
9 A.Yes.The Wind Projects that will ultimately be
10 constructed or acquired will be the winning bids
11 resulting from the 2017R RFP.The Company intends to
12 supplement the record in this case with the winning bids
13 once they are identified.Importantly,if the RFP results
14 differ from the Wind Projects included here,the selected
15 resources will have been determined to be economically
16 superior.In either case,the Wind Projects represent the
17 most cost-effective resources,based on what is known
18 today.
19 The Transmission Projects are an integral part
20 of the Company's plans to acquire additional resources,
21 relieve existing congestion,and allow additional
22 renewable resources to interconnect into the Company's
23 transmission system.
24 Q.What are the requirements for approval of a
25 binding ratemaking treatment under Idaho Code §61-541?
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1 A.It is my understanding that Idaho Code §61-541
2 allows a utility that is proposing to construct or
3 purchase a generation or transmission facility to request
4 that the Commission determine in advance the ratemaking
5 treatment that will apply to the proposed facility.When
6 reviewing an application for binding ratemaking
7 treatment,I understand that the Commission must maintain
8 a "fair,just and reasonable balance of interests between
9 the requesting utility and the utility's ratepayers,"
10 considering
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1 specific factors.
2 Q.Does the Company's request for binding
3 ratemaking treatment of the Combined Projects fairly,
4 justly,and reasonably balance the interests between the
5 Company and its customers?
6 A.Yes.The Company's request also satisfies each
7 of the requirements set forth in Idaho Code §61-541(4).
8 As described in more detail in Mr.Link's testimony,the
9 Company has a Commission-accepted IRP and its 2017 IRP is
10 currently pending.The 2017 IRP demonstrates that the
11 proposed Wind Projects,together with the Transmission
12 Projects,are the least-cost,least-risk approach when
13 compared to other sources for long-term electric supply,
14 including energy efficiency,demand-side management,and
15 other feasible supply alternatives.
16 In addition,as described above and in Mr.
17 Link's testimony,the Projects will serve the public
18 interest and provide substantial benefits to Idaho
19 customers.
20 The Company also participates in regional
21 transmission planning processes.The Company is a member
22 of the Northern Tier Transmission Group ("NTTG"),which
23 is a regional transmission planning group consisting of
24 seven electric utility members and covering a region that
25 includes portions of seven western states.NTTG develops
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1 a regional transmission plan that addresses new proposed
2 projects and the reliability of the regional transmission
3 system,as required by the Federal Energy Regulatory
4 Commission's Orders Nos.890 and 1000.
5 Q.Does the Company have the ability to finance
6 the Combined Projects?
7 A.Yes.The Company intends to finance the
8 proposed Wind Projects and Transmission Projects through
9 its normal sources of capital,both internal and
10 external,including net
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1 cash flow from operating activities,public and private
2 debt offerings,the issuance of commercial paper,the use
3 of unsecured revolving credit facilities,capital
4 contributions and other sources.Although the proposed
5 Combined Projects are a significant investment on the
6 part of the Company,the financial impact will not impair
7 the Company's ability to continue to provide safe and
8 reliable electricity service at reasonable rates.
9 Q.How will approval support the Company's current
10 credit rating,thereby providing customer benefits?
11 A.Ratings agencies consider the Company's
12 regulatory treatment when establishing its credit rating,
13 and particularly focus on the treatment of capital
14 investments.Supportive treatment through approval of an
15 investment of this magnitude provides assurance to
16 ratings agencies and helps maintain the Company's credit
17 rating.A solid credit rating directly benefits customers
18 by ensuring access to capital markets and reducing
19 immediate and future borrowing costs related to the
20 financing needed to support regulatory operations,and
21 strong ratings will often allow the Company to avoid
22 having to meet costly collateral requirements that are
23 typically imposed on lower-rated companies when securing
24 power in the market.If the Company does not have
25 consistent access to the capital markets at reasonable
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1 costs,its debt issuances and the resulting costs ofO2constructingthenewfacilitiesbecomemoreexpensive
3 than they otherwise would be.
4 Q.Why should the Commission approve the Company's
5 request for binding ratemaking treatment?
6 A.In this case,approval of binding ratemaking
7 treatment is warranted because of the
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1 magnitude of the proposed investment and the significantO2customerbenefitsresultingfromtheCombinedProjects.
3 Providing binding ratemaking treatment here comports with
4 the purpose of Idaho Code §61-541 to facilitate the
5 acquisition and construction of major generation or
6 transmission facilities while balancing the interests of
7 the utility and customers.
8 PROPOSED RATEMAKING TREATMENT
9 Q.Please describe the Company's proposed
10 ratemaking treatment for the Combined Projects.
11 A.The Company proposes a Resource Tracking
12 Mechanism ("RTM")to address the proper ratemaking
13 treatment to match the costs and benefits of the Combined
14 Projects until the costs and benefits are fully reflected
15 in base rates.This primarily includes new capital and
16 operating costs,net power costs savings,and PTC
17 benefits.This mechanism will align the costs and
18 benefits so that customers receive the benefits from the
19 Combined Projects while shareholders receive appropriate
20 cost recovery of the prudent investments.The RTM would
21 be included as a component of the ECAM.Mr.Larsen's
22 testimony provides additional detail on the proposal and
23 further demonstrates how it is consistent with the public
24 interest.
25 Q.Is the RTM a proposal for nontraditional
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1 ratemaking as allowed under the binding ratemakingO2authority?
3 A.Yes.The binding ratemaking authority states
4 that the "requested ratemaking treatments may include
5 nontraditional ratemaking treatments or nontraditional
6 cost recovery mechanisms."Mr.Larsen's testimony
7 provides additional detail on the proposal and further
8 demonstrates how it is consistent with the public
9 interest.
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1 CONCLUSION
2 Q.What is your recommendation to the Commission?
3 A.The Company recommends that the Commission
4 grant CPCNs for the Combined Projects on the timeline
5 requested by the Company.The Combined Projects will
6 provide substantial customer benefits and advance the
7 public interest in Idaho.The Company also requests that
8 the Commission approve the Company's request for binding
9 ratemaking treatment for the investment in the Combined
10 Projects.
11 Q.Does this conclude your direct testimony?
12 A.Yes.
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1 Q.Are you the same Cindy A.Crane 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 SUMMARY OF REBUTTAL TESTIMONY
6 Q.What is the purpose of your rebuttal testimony?
7 A.I provide the Company's overall policy rebuttal
8 to the objections of Monsanto Company ("Monsanto"),
9 PacifiCorp Idaho Industrial Customers ("PIIC"),and the
10 Idaho Irrigation Pumpers Association,Inc.("IIPA")to
11 the Company's request for certificates of public
12 convenience and necessity ("CPCNs")and for binding
13 ratemaking treatment related to the Company's proposal to
14 construct or procure new wind resources ("Wind Projects")
15 and to construct the Aeolus-to-Bridger/Anticline line and
16 230 kV Network Upgrades ("Transmission Projects")
17 (collectively,the "Combined Projects").I also respond
18 to the recommended conditions provided by Staff of the
19 Idaho Public Utilities Commission ("Staff").
20 Q.Please summarize your rebuttal testimony.
21 A.The Combined Projects will provide substantial
22 customer benefits over the long-term and represent the
23 least-cost,least-risk strategy for meeting the needs of
24 Idaho customers.In rebuttal to the parties'objections,
25 the Company shows the Combined Projects are necessary to
683 Crane,Di-Reb -1
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1 meet an identified resource need and present no more riskO2thantypicalutilityinvestments.Therefore,the parties'
3 proposed conditions that shift nearly all risk to the
4 Company are both unprecedented and unwarranted.
5 The Company further demonstrates that it has
6 mitigated many of the risks that
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..i.mm
1 could adversely impact the economics of the Combined
2 Projects,and it intends to carefully manage future
3 project risks either through the off-ramps built into the
4 Combined Projects,or by seeking additional direction
5 from the Commission before or during project
6 implementation.The Company is on track to file
7 supplemental testimony on January 16,2018,which will
8 update the costs of the Combined Projects,validate their
9 economic benefits,and further demonstrate how the
10 Company has managed and mitigated project risk.
11 PUBLIC INTEREST
12 Q.Do the Combined Projects satisfy the public
13 interest standard required for granting a CPCN?
14 A.Yes.It is my understanding that the public
15 interest standard has two components.First,the
16 Commission must determine whether the present or future
17 public convenience and necessity require additional
18 resources.Second,the Commission must determine whether
19 the Combined Resources are a reasonable means of meeting
20 the identified need.
21 As described in the rebuttal testimony of Mr.
22 Rick T.Link,the Company has both near-and long-term
23 needs for incremental generation resources,as set forth
24 in the Company's 2017 Integrated Resource Plan.Mr.Link
25 also describes the solicitation processes underway to
685 Crane,Di-Reb -2
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1 ensure the least-cost,least-risk resources are procured
2 to meet the identified resource need.In his rebuttal
3 testimony,Company witness Mr.Rick A.Vail provides an
4 update on the proposed Transmission Projects and
5 describes how the Company is prudently managing and
6 mitigating development and construction costs and risks.
7 Company witness Mr.Chad A.Teply provides an update on
8 the Combined
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1 Projects,including the benchmark Wind Projects,and
2 describes how the Company is prudently managing the costs
3 and risks of project development and implementation.
4 Together,the evidence demonstrates the Combined Projects
5 satisfy the public interest standard.
6 Q.Do the Combined Projects satisfy the standard
7 for binding ratemaking treatment?
8 A.Yes.When reviewing an application for binding
9 ratemaking treatment,I understand the Commission must
10 maintain a "fair,just and reasonable balance of
11 interests between the requesting utility and the
12 utility's ratepayers."As described in the direct
13 testimony of Company witness Mr.Jefferey K.Larsen and
14 the rebuttal testimony of Ms.Joelle R.Steward,the
15 Company's proposed Resource Tracking Mechanism ("RTM")
16 appropriately matches the costs and benefits of the
17 Combined Projects so that,before the resources are
18 reflected in base rates,customers receive the benefits
19 from the Combined Projects while shareholders receive
20 appropriate cost recovery of the prudent investments.
21 Q.Does Staff agree that the Combined Projects are
22 in the public interest?
23 A.Yes.Staff recommends that the Commission
24 approve the CPCNs,subject to four conditions.First,
25 Staff recommends that the Company continually reassess
687 Crane,Di-Reb -3
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1 the project economics due to changing circumstances and
2 establish off-ramps before development occurs.(Lobb
3 Direct,page 5,lines 23-25.)As described in Mr.Link's
4 and Mr.Teply's rebuttal testimony,the Company fully
5 intends to perform the type of assessment Staff
6 recommends.
7 Second,Staff recommends that the Commission
8 cap the costs of the Transmission Projects for purposes
9 of cost recovery at the level estimated in this filing.
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1 (Lobb Direct,page 6,lines 15-17.)As described in Mr.
2 Vail's rebuttal testimony,the Company intends to update
3 and confirm its construction cost estimate for the
4 Transmission Projects in the Company's supplemental
5 testimony.As discussed by Ms.Steward,consistent with
6 the binding ratemaking treatment law in Idaho,the
7 Company agrees to a soft cap based on the cost estimate
8 included in the Company's supplemental filing.If the
9 actual costs are greater than the final estimate here,
10 the Company agrees it must demonstrate the prudence of
11 the additional costs in a subsequent ratemaking
12 proceeding.
13 Third,Staff recommends that the Company
14 continue to annually track the revenue requirement for
15 the Combined Projects in the RTM after the first general
16 rate case to reflect a declining net rate base.(Lobb
17 Direct,page 9,lines 6-11.)The Company objects to this
18 unprecedented proposal to isolate revenue requirement on
19 specific resources on an indefinite basis because it does
20 not reflect the Company's on-going cost of serving
21 customers.
22 Fourth,Staff recommends that the Company
23 provide a mechanical availability guarantee of 97 percent
24 for the Wind Projects.(Lobb Direct,page 9,lines
25 21-24.)While the Company does not agree that the
689 Crane,Di-Reb -4
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1 Commission should require this condition,as described in
2 Mr.Teply's rebuttal testimony,the Company intends to
3 seek cost-effective availability guarantees for the Wind
4 Projects in any third-party-provided maintenance,as
5 provided by the competitive market.The Company was
6 successful in negotiating similar availability guarantees
7 for its repowered wind facilities in Wyoming.
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1 Q.Monsanto,PIIC,and IIPA argue that the
2 forecasted benefits of the Combined Projects are
3 speculative and,even in the best scenarios,are
4 insufficient in comparison to the overall project costs.
5 Do you agree?
6 A.No.The parties'criticisms are largely
7 premised on their claim that the Combined Projects are
8 discretionary and therefore subject to a higher standard
9 for approval than a project intended to meet customer
10 need.But,as described by Mr.Link,the Combined
11 Projects are not merely an economic opportunity.Instead,
12 the projects are part of the Company's least-cost,
13 least-risk plan for meeting resource needs.The
14 innovation in PacifiCorp's plan is the opportunity to
15 bring near-and long-term benefits-in system reliability
16 and flexibility as well as financial benefits-to
17 customers by capitalizing on the continued (but
18 short-lived)availability of federal production tax
19 credit ("PTCs")acquire new resources without substantial
20 increases in rates.
21 Q.Does Staff agree with the Company that the
22 Combined Projects will meet a customer need?
23 A.Yes.Staff acknowledges the Combined Projects
24 will meet a system need in 2028,and Staff does not argue
25 that the Combined Projects require a higher standard for
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1 approval.(Keller Direct,page 3,lines 6-7.)
2 Q.The parties argue that there is a significant
3 risk that benefits will not materialize as claimed by the
4 Company,and that the Combined Projects may prove
5 uneconomic in the long run for reasons beyond the
6 Company's control.Do you agree?
7 A.I do not.Mr.Link's sensitivity modeling is
8 designed to capture a wide range of conditions and
9 circumstances that could impact the economics of the
10 Combined
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1 Projects.The Company's economic analysis shows that the
2 Combined Projects deliver substantial benefits under most
3 sensitivities.As set forth in Mr.Link's rebuttal
4 testimony,the Company intends to comprehensively update
5 its economic analysis in its supplemental testimony on
6 January 16,2018.
7 While all resource decisions inherently include
8 some risk,the Company has demonstrated a high likelihood
9 the Combined Projects will be beneficial to customers.
10 Moreover,the risks associated with the Combined Projects
11 are typical of all utility investments and,as Mr.Link
12 explains in his rebuttal testimony,there are risks
13 associated with forgoing the time-limited opportunity to
14 secure PTC-eligible resources.
15 Q.Monsanto proposes a series of conditions it
16 recommends the Commission apply if it approves the
17 Combined Projects.(Phillips Direct,page 4,line 6 -
18 28.)Are Monsanto's proposed conditions reasonable?
19 A.No.As explained in Ms.Steward's and Mr.
20 Teply's rebuttal testimony,there is nothing novel or
21 unique about the Combined Projects that require such
22 unprecedented conditions.Monsanto's proposed conditions
23 would shift virtually all risk to the Company,and act as
24 an automatic disallowance of a significant portion of the
25 investment.This treatment is unwarranted because the
693 Crane,Di-Reb -6
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1 Combined Projects do not present risks different than
2 typical utility investments.In fact,just the opposite
3 is true.The Combined Projects provide a unique
4 opportunity to meet customer needs while offsetting a
5 large portion of the projects'revenue requirement with a
6 time-limited availability of PTC.Indeed,the proposed
7 conditions presume that the projects are discretionary
8 investments untethered to a resource need,which,as Mr.
9 Link discusses in his rebuttal testimony,is untrue.
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1 Q.If circumstances arise that make the Combined
2 Projects uneconomic,has the Company structured off-ramps
3 to allow it to stop project development,as Staff
4 recommends?
5 A.Yes.As addressed in Mr.Vail's rebuttal
6 testimony,the Company will soon negotiate and finalize
7 most of the construction contracts for the Transmission
8 Projects,which will lock in pricing.The Company will
9 also prudently negotiate precautionary off-ramps in the
10 contracts to allow it to exit the Transmission Projects
11 if they become uneconomic.The timing and terms of the
12 execution of the contracts necessary to procure or
13 construct the Wind Projects will also provide flexibility
14 to allow the Company to reassess project economics,if
15 necessary,before executing the contracts.
16 Q.How will the Company respond if it receives
17 approval of the Combined Projects in this docket and a
18 subsequent event occurs that adversely affects the
19 economics of the Combined Projects during implementation?
20 A.If an adverse change of circumstances
21 materially affects the Combined Projects'economics,the
22 Company will seek Commission review of whether to proceed
23 with implementation.
24 Q.If significant portions of the Wind Projects do
25 not ultimately qualify for PTCs due to delays or because
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1 they incur unanticipated cost increases within the
2 Company's control,is the Company prepared to bear those
3 risks?
4 A.Yes.The Company will take every precaution to
5 ensure the Wind Projects meet the requirements and
6 timelines to qualify for full PTC benefits.While we do
7 not believe it is appropriate for the Company to absorb
8 risks beyond its control-such as those associated with
9 the actions of the U.S.Congress-we are prepared to
10 accept risks
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1 associated with our performance.We are confident that we
2 will complete the Combined Projects in advance of the
3 2020 deadline.
4 Q.Staff identifies several risks it believes are
5 within the Company's control.(Keller Direct,page 19,
6 lines 15-24.)Do you agree with Staff's
7 characterizations?
8 A.Somewhat.I agree that the following are within
9 the Company's control:meeting the five-percent
10 safe-harbor requirement,meeting regulatory requirements,
11 such as permitting,that are required to place the
12 projects in-service,and achieving timely completion of
13 the Combined Projects.Development and construction costs
14 are largely within the Company's control,but there are
15 potential circumstances outside our control that could
16 impact these costs,such as a force majeure event.Staff
17 also states that life-cycle performance and availability
18 are within the Company's control through proper operation
19 and maintenance.I agree that prudent operation and
20 maintenance are within the Company's control,but there
21 are many other factors influencing performance and
22 availability that are not.
23 Q.How will the Company respond if the federal
24 corporate income tax rate is significantly altered,
25 impacting the economics of the Combined Projects?
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1 A.The Company plans to model actual or potential
2 tax law changes in its supplemental testimony in January
3 2018 to demonstrate the economic impacts on the Combined
4 Projects.If a tax change occurs after the supplemental
5 filing,the Company will refresh the project economics to
6 inform its decision to proceed or terminate.The Company
7 will either update its pending request,or if the change
8 occurs during the implementation of the Combined
9 Projects,the Company will seek guidance from the
10 Commission.
11 If a tax law change occurs after the Combined
12 Projects are completed,then the
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1 change should be addressed like any other factor that
2 occurs after a CPCN is granted by the Commission based on
3 the facts known at the time.There is always a risk that
4 future changes in laws could affect decisions made today,
5 and the Company must operate on the best information
6 available at the time decisions are made.That is why we
7 are before the Commission now-to determine whether the
8 Company has adequately addressed the project risks and
9 whether the Combined Projects are in the public interest
10 given the information currently available.
11 Q.Does this conclude your rebuttal testimony?
12 A.Yes.
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1 Q.Are you the same Cindy A.Crane 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 SUMMARY OF TESTIMONY
6 Q.What is the purpose of your supplemental direct
7 testimony?
8 A.I support the Company's request that the Idaho
9 Public Utilities Commission ("Commission")grant
10 certificates of public convenience and necessity
11 ("CPCNs")to construct and acquire new wind resources
12 ("Wind Projects")construct the Aeolus-to-Bridger/
13 Anticline line and network upgrades ("Transmission
14 Projects")(collectively,the "Combined Projects")and
15 approve the Company's proposal for binding ratemaking
16 treatment to capture the costs and benefits of these
17 facilities.I provide overall policy support for the
18 Company's supplemental testimony describing the results
19 of the Company's 2017R Request for Proposals ("2017R
20 RFP").
21 Q.Please summarize your testimony.
22 A.The results of the 2017R RFP make the Combined
23 Projects an increasingly attractive resource opportunity
24 for customers.The benefits are now greater and more
25 certain,and the risks have decreased.The Combined
700 Crane,Di-Supp -1RockyMountainPower
1 Projects will provide substantial near-term and long-term
2 customer benefits and represent the least-cost,
3 least-risk strategy for meeting the needs of Idaho
4 customers.The Company's supplemental testimony
5 demonstrates the Company has recognized and mitigated all
6 potential risks and concerns.
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1 Q.Based on the results of the 2017R RFP and theO2Company's updated analysis of benefits,costs,and risks,
3 do the Combined Projects satisfy the public interest
4 standard?
5 A.Yes.The Combined Projects are the least-cost,
6 least-risk path available to serve the Company's
7 customers by meeting both near-term and long-term needs
8 for additional resources.Mr.Rick T.Link's supplemental
9 direct testimony and updated economic analysis
10 demonstrates increased customer benefits of $151 million
11 in the medium case through 2050 (as compared to $137
12 million in the original filing),and a range of $333
13 million to $349 million in the medium case through 2036.
14 As described further by Mr.Link,the treatment of
15 production tax credits ("PTCs")in the system modeling
16 scenarios extending out through 2036 has been changed to
17 better reflect how the PTCs will flow through to
18 customers,which makes the treatment consistent with the
19 nominal revenue requirement results that extend out
20 through 2050.Moreover,the updated economic analysis
21 demonstrates the Combined Projects provide net customer
22 benefits under all scenarios studied through 2036,and in
23 seven of the nine scenarios through 2050.
24 The fact that the Combined Projects will
25 provide customer benefits significantly in excess of
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1 their costs is extraordinary.Customers will gain access
2 to significant new wind and transmission resources,with
3 important environmental and system reliability
4 attributes,and still enjoy lower overall costs as a
5 result of this investment.
6 Q.What evidence is the Company including in the
7 supplemental direct filing to demonstrate that the
8 Combined Projects are in the public interest?
9 A.In addition to updating the Company's economic
10 analysis,Mr.Link provides
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1 information on the 2017R RFP,which generated robust and
2 competitive responses from market participants.Mr.Chad
3 A.Teply describes the four Wind Projects,totaling 1,170
4 megawatts ("MW"),that were selected for the final
5 shortlist through this solicitation process:TB Flats I
6 and II;McFadden Ridge II;Cedar Springs;and Uinta.He
7 also details the Company's extensive and ongoing efforts
8 to minimize technical and construction risk associated
9 with the Wind Projects.Mr.Rick A.Vail updates the
10 status of the development of the Aeolus-to-Bridger/
11 Anticline 500 kilovolt ("kV")transmission line,and
12 confirms that the costs of the line (which represents
13 roughly 85 percent of the costs of the Transmission
14 Projects)remain unchanged.Mr.Vail also updates the
15 network upgrade and interconnection facilities based on
16 the outcome of the 2017R RFP.Ms.Nikki L.Kobliha
17 describes the outcome of federal tax reform,and
18 discusses how tax-related risks have been resolved.
19 Together,this evidence shows that the Combined Projects
20 satisfy the Commission's public interest standard.
21 Q.Is the Company's supplemental direct filing
22 consistent with the procedure proposed in the Company's
23 request for resource approval and in the schedule
24 approved by the Commission?
25 A.Yes.The supplemental direct filing allows the
704 Crane,Di-Supp -3
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1 Company to update its pending request for resource
2 approval to reflect the results of the 2017R RFP.This
3 process allows for full review of the Combined Projects,
4 including review of the results of the 2017R RFP,by
5 April 2018,a schedule necessary to preserve for
6 customers the time-sensitive resource opportunity
7 presented by the availability of PTCs for the Wind
8 Projects.
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1 Q.Based on the results of the 2017R RFP,what
2 modification is the Company making to its application for
3 CPCNs?
4 A.The Company's original application sought CPCNs
5 for the construction or acquisition of four new wind
6 resources-three 250 MW facilities (Ekola Flats and TB
7 Flats I and II),and a fourth 100 MW facility (McFadden
8 Ridge II)-for a total of 860 MW.These were the
9 benchmark facilities for the 2017R RFP.
10 Based on the results of the 2017R RFP,the
11 Company is now seeking CPCNs to construct or procure four
12 new Wyoming wind projects with a total capacity of 1,170
13 MW,including three of the benchmark facilities (TB Flats
14 I and II,now combined as a single project,and McFadden
15 Ridge II),and two new facilities (Cedar Springs and
16 Uinta).Uinta is a build-transfer agreement ("BTA"),
17 totaling 161 MW,Cedar Springs is one-half BTA and
18 one-half power purchase agreement ("PPA"),for a total of
19 400 MW,and TB Flats I and II and McFadden Ridge II are
20 Company-built facilities,totaling 500 MW and 109 MW,
21 respectively.Thus,the 2017R RFP will result in 970 MW
22 of Company-owned facilities,and a 200 MW PPA.
23 Q.Has any aspect of the Aeolus-to-Bridger/
24 Anticline transmission line changed as a result of the
25 2017R RFP?
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1 A.No.The proposed route and facilities required
2 for the construction of the Aeolus-to-Bridger/Anticline
3 line have not changed.The only change related to the
4 line is the fact that the costs are now more certain.
5 Q.Are there any modifications to the network
6 upgrades included in the Company's initial filing?
7 A.Yes,in addition to the network upgrades
8 included in the Company's initial filing,there
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1 are additional network upgrades required to interconnect
2 McFadden Ridge II,Cedar Springs,and Uinta.Mr.Vail
3 provides a detailed description of these network upgrades
4 in his supplemental direct testimony.
5 Q.The Company's original filing contained a
6 capital cost estimate of approximately $2 billion for the
7 Combined Projects.With additional wind resources and
8 network upgrades,have the total costs of the Combined
9 Projects changed?
10 A.No.The overall capital cost of the Combined
11 Projects remains the same-approximately $2 billion.This
12 is true even though the supplemental filing reflects 970
13 MW of Company-owned resources,110 MW more than the
14 original filing.As Mr.Link explains,the per-unit
15 capital cost for the benchmark wind projects in the
16 initial filing was $1,590/kW.As a result of the 2017R
17 RFP,the costs of the Company-owned wind projects
18 decreased by roughly 17 percent to $1,320/kW.
19 Q.Please explain how the Company was able to
20 acquire significant additional wind resources for
21 approximately the same overall cost.
22 A.The robust response to the 2017R RFP process
23 reduced costs and enabled the Company to select the most
24 optimal projects to maximize customer benefits,as
25 described by Mr.Link.The Company received 49 bid
708 Crane,Di-Supp -5RockyMountainPower
1 alternatives for 13 wind projects in Wyoming,totaling
2 4,624 MW.The Company also received 15 bid alternatives
3 for six non-Wyoming wind projects,totaling 595 MW.
4 Q.Has the Company further mitigated customer
5 risks associated with the Combined Projects?
6 A.Yes.Three key risks associated with the
7 Combined Projects have been either entirely or
8 substantially mitigated.First,as described by Ms.
9 Kobliha,the uncertainty
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1 surrounding federal tax reform has been resolved.TheO2economicanalysisinMr.Link's testimony accounts for
3 the lower federal corporate income tax rate and
4 demonstrates that the overall cost reduction resulting
5 from the 2017R RFP more than offsets the impact of the
6 lower tax rate.Moreover,the policy discussions
7 surrounding tax reform indicate that it is highly
8 unlikely that PTCs will be extended beyond 2020-meaning
9 that the time to act is now or customers will lose out on
10 substantial savings.
11 Second,the Company has addressed the price
12 risk associated with long-term forecasting by
13 demonstrating the Combined Projects are expected to
14 provide robust customer benefits under all scenarios in
15 the economic analysis through 2036,including the
16 scenario with low natural-gas prices and a zero
17 carbon-dioxide price.
18 Third,the costs and schedule of the Combined
19 Projects are now more certain.Based on the results of
20 the 2017R RFP and the continued development efforts
21 related to the Transmission Projects,the Company is
22 confident that it can deliver the expected customer
23 benefits.
24 Q.Based on the Company's updated economic
25 analysis,has the Company updated its forecast of the
710 Crane,Di-Supp -6
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1 near-term rate impact to Idaho customers?O 2 A.Yes.As explained in the testimony of Ms.
3 Steward,the first-year revenue requirement of the
4 Combined Projects is reduced nearly 20 percent from the
5 initial filing.The near-term rate impact of the Combined
6 Projects is now less than 1.6 percent in 2021,the first
7 full year of operation.
8 Q.Do the results of the 2017R RFP provide
9 additional evidence supporting the need for the
10 Aeolus-to-Bridger/Anticline transmission line?
11 A.Yes.Over 4,500 MW of new high-capacity-factor
12 wind projects that bid into the 2017R
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1 RFP are behind the existing constraint,showing the needO2fornewtransmissioncapacityinsoutheastWyomingto
3 give these potential resources a chance to move forward.
4 The construction of the Aeolus-to-Bridger/Anticline line
5 is a critical step to allow high-capacity-factor wind
6 resource development in this area.
7 In addition,as explained by Mr.Vail,even
8 without the Wind Projects,the Company plans to construct
9 the Aeolus-to-Bridger/Anticline line in 2024 because it
10 is an integral component of both the Company's and the
11 region's long-term transmission plan.Thus,the issue is
12 not if the Aeolus-to-Bridger/Anticline line will be
13 constructed,but when.Under the proposal here,the
14 Company can construct the line by 2020 and provide all-in
15 net benefits to customers,rather than waiting until 2024
16 when PTC-eligible wind is no longer available to
17 subsidize the line.
18 Q.Does this conclude your supplemental direct
19 testimony?
20 A.Yes.
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1 Q.Are you the same Cindy A.Crane who previously
2 filed testimony in this case on behalf of Rocky Mountain
3 Power ("Company"),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 support the request that the Idaho Public
9 Utilities Commission ("Commission")grant certificates of
10 public convenience and necessity ("CPCNs")for new wind
11 resources ("Wind Projects")and for the
12 Aeolus-to-Bridger/Anticline line and network upgrades
13 ("Transmission Projects")(collectively,the "Combined
14 Projects")and approve the Company's proposal for binding
15 ratemaking treatment to capture the costs and benefits of
16 these facilities.I update the Company's policy testimony
17 based on the updated results of the Company's 2017R
18 request for proposals ("2017R RFP").
19 Q.Please summarize your testimony.
20 A.The Company updated the 2017R RFP final
21 shortlist to reflect the results of the interconnection
22 restudy process and new system impact studies ("SISs").
23 The updated final shortlist replaces one Company
24 benchmark resource,McFadden Ridge II,with another
25 benchmark resource,Ekola Flats.The Company's economic
713 Crane,Di-2nd Supp -1
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1 analysis for the updated final shortlist shows an
2 increase in customer benefits,demonstrating that the
3 2017R RFP was robust and produced favorable resource
4 opportunities for customers.
5 SECOND SUPPLEMENTAL DIRECT TESTIMONY
6 Q.Why is the Company making this second
7 supplemental filing?
8 A.In its first supplemental filing,the Company
9 explained that it had selected four Wind Projects,
10 totaling 1,170 megawatts ("MW"),for the 2017R RFP final
11 shortlist:TB Flats
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1 I and II;McFadden Ridge II;Cedar Springs;and Uinta.At
2 that time,however,the Company had not concluded its
3 interconnection restudy process for the Aeolus-to-
4 Bridger/Anticline line or updated its SISs for resources
5 interconnecting to that line,including resources on the
6 2017R RFP final shortlist.This second supplemental
7 filing updates the 2017R RFP final shortlist to reflect
8 the results of the interconnection restudy process and
9 updated SISs.The updated 2017R RFP shortlist consists of
10 1,311 MW,replacing the McFadden II benchmark resource,
11 totaling 109 MW,with another Company benchmark resource,
12 Ekola Flats,totaling 250 MW.
13 Q.Why did the Company select the final shortlist
14 in the 2017R RFP before it had SIS results?
15 A.In the original draft of the 2017R RFP filed in
16 Utah in Docket No.17-035-23,the Company proposed that
17 all bidders have a completed SIS to qualify.The Utah
18 independent evaluator and certain intervenors proposed
19 that the Company require only that bidders show they have
20 requested a SIS.The Company removed the requirement of a
21 completed SIS in the final 2017R RFP approved by the
22 Commission.When the Company announced the final
23 shortlist in January 2018,it still had not completed the
24 interconnection restudy process and updated the SISs.
25 While the interconnection restudy process ultimately
715 Crane,Di-2nd Supp -2
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1 affected the final shortlist,the potential implications
2 of the restudy process,if any,on bid selections were
3 not known until the interconnection restudy process was
4 finalized.
5 Q.What were the results of this process?
6 A.As explained by Company witness Mr.Rick A.
7 Vail and Mr.Rick T.Link,there were two important
8 findings.First,the interconnection restudy process
9 identified that
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1 projects with interconnection queue positions higher than
2 a certain point were not viable without Energy Gateway
3 South,a PacifiCorp transmission project that is not
4 scheduled to be built before the expiration of production
5 tax credits ("PTCs")in 2020.McFadden Ridge II has a
6 queue position higher than the cutoff point,so the
7 Company removed it from the final shortlist.
8 Second,the restudy identified 1,510 MW of
9 total interconnection capacity for projects in eastern
10 Wyoming,up from 1,270 MW.The Company updated its System
11 Optimizer ("SO")model simulations taking into account
12 these findings.The SO model continued to select TB Flats
13 I and II,Cedar Springs,and Uinta,but replaced McFadden
14 Ridge II with Ekola Flats for the 2017R RFP final
15 shortlist now that more interconnection capacity was
16 identified.
17 Q.Did the Company update its SO and Planning and
18 Risk ("PaR")studies to reassess the economic benefits of
19 the Combined Projects?
20 A.Yes.As explained by Company witness Mr.Link,
21 the Company updated the SO and PaR studies for all nine
22 price-policy scenarios.Mr.Link's updated economic
23 analysis demonstrates increased customer benefits of $167
24 million in the medium case through 2050 (as compared to
25 $137 million in the original filing and $151 million in
717 Crane,Di-2nd Supp -3
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1 the first supplemental filing),and an increased benefit
2 range of $357 million to $405 million in the medium case
3 through 2036.Moreover,the updated economic analysis
4 demonstrates the Combined Projects continue to provide
5 net customer benefits under all scenarios studied through
6 2036,and in seven of the nine scenarios through.2050.
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1 Q.Did the Company prepare new sensitivity
2 analyses to test the likelihood of achieving these
3 economic benefits?
4 A.Yes,as in the first supplemental filing,the
5 Company updated several different scenarios to determine
6 their impact on the Combined Projects'economic benefits,
7 including a scenario reflecting the Company's proposal
8 for wind repowering,and one comparing the benefits with
9 and without projects from the pending solar RFP,using
10 the latest pricing information from that RFP.In each
11 case,the scenarios confirm the significant customer
12 benefits associated with the Combined Projects.
13 Q.Based on the results of the 2017R RFP,what
14 modifications is the Company making to its request for
15 resource approval related to the Wind Projects?
16 A.In its first supplemental direct testimony,the
17 Company sought approval to construct or procure four new
18 Wyoming wind projects with a total capacity of 1,170 MW,
19 including three of the benchmark facilities (TB Flats I
20 and II,now combined as a single project,and McFadden
21 Ridge II),and two new facilities (Cedar Springs and
22 Uinta).
23 In this second supplemental filing,the Company
24 still seeks approval of three of the benchmark
25 facilities,but has replaced McFadden Ridge II with Ekola
719 Crane,Di-2nd Supp -4
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1 Flats.The Company seeks resource approval for Wind
2 Projects totaling 1,311 MW,consisting of 1,111 MW of
3 Company-owned facilities,and a 200 MW Power Purchase
4 Agreement.Of the 1,311 MW total,there are 1,150 MW of
5 Wind Projects in eastern Wyoming enabled by the Aeolus-
6 to-Bridger/Anticline transmission line.
7 Q.Has any aspect of the Aeolus-to-Bridger/
8 Anticline transmission line changed as a result of the
9 updated final shortlist?
10 A.No.The proposed route and facilities required
11 for the construction of the Aeolus-to-
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1 Bridger/Anticline transmission line have not changed.
2 Q.Are there any modifications to the network
3 upgrades included in this second supplemental filing?
4 A.Yes.The network upgrades required to
5 interconnect McFadden Ridge II are no longer needed.
6 Based on the results of the updated SISs,however,some
7 additional network upgrades to other Wind Projects are
8 required.Mr.Vail provides a detailed description of
9 these network upgrades.
10 Q.The Company's original and supplemental filings
11 contained a capital cost estimate of approximately $2
12 billion for the Combined Projects.With additional wind
13 resources and network upgrades,have the total costs of
14 the Combined Projects changed?
15 A.Yes.Adding the Ekola Flats wind resource
16 increases total projected capital costs for the Combined
17 Projects from approximately $2 billion to $2.245 billion.
18 Mr.Link explains,however,the Company's capital costs
19 have declined by 18 percent from the initial filing on
20 cost-per kilowatt basis.The per-unit capital cost for
21 the benchmark wind projects was $1,590/kW in the initial
22 filing,and $1,320/kW in the first supplemental filing.
23 The total capital for the Wind Projects in the final
24 shortlist is now $1,310/kW.
25 Q.Based on the Company's updated economic
721 Crane,Di-2nd Supp -5RockyMountainPower
1 analysis,has the Company updated its forecast of the
2 near-term rate impact to Idaho customers?
3 A.Yes.As explained in the testimony of Ms.
4 Steward,the first-year revenue requirement of the
5 Combined Projects is less than 1.7 percent in 2021,the
6 first full year of operation.This is 0.2 percent lower
7 than the increase projected in the initial filing and 0.1
8 percent higher than the increase projected in the first
9 supplemental filing.
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1 Q.Considering the updated results of the 2017R
2 RFP and the Company's updated analysis of benefits,
3 costs,and risks,do the Combined Projects satisfy the
4 public interest standard?
5 A.Yes.The Combined Projects are the least-cost,
6 least-risk path available to serve the Company's
7 customers by meeting both near-term and long-term needs
8 for additional resources.The Combined Projects provide
9 significant benefits to customers under virtually all
10 scenarios and sensitivities studied.
11 Q.Does this conclude your second supplemental
12 direct testimony?
13 A.Yes.
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1 Q.Are you the same Cindy A.Crane who previously
2 provided testimony in this case on behalf of Rocky
3 Mountain Power ("Company"),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.I support the Company's application for
9 approval of certificates of public convenience and
10 necessity ("CPCNs")and binding ratemaking treatment to
11 (1)construct the Aeolus-to-Bridger/Anticline
12 transmission line and network upgrades ("Transmission
13 Projects")and (2)construct or acquire the Ekola Flats,
14 TB Flats I and II,Cedar Springs,and Uinta projects,
15 which are the four new wind resources ("Wind Projects")
16 included on the final shortlist of the 2017R Request for
17 Proposals ("RFP"),(collectively,the "Combined
18 Projects").I provide a policy response to the April 11,
19 2018,testimony filed by the parties.
20 Q.Please summarize your testimony.
21 A.The Company's application has been thoroughly
22 reviewed since it was filed in June 2017.The process has
23 included multiple rounds of testimony and analysis.At
24 this juncture,most of the questions and concerns
25 initially raised have been addressed-tax reform is behind
724 Crane,Supp-Reb -1
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1 us,the Company concluded the 2017R RFP and is
2 negotiating contracts with the winning bidders,the Utah
3 and Oregon Independent Evaluators ("IEs")have reported
4 on the fairness of the RFP,and the process to acquire
5 easements and rights-of-way for the Transmission Projects
6 is underway.The benefits of the Combined Projects are
7 now clear,with millions of dollars in benefits to
8 customers,the addition of new resources that will
9 enhance the ability of the Company to provide safe
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1 and reliable service to Idaho customers with manageable
2 risks.The Combined Projects are in the public interest
3 so the Company requests approval of the application for
4 CPCNs and binding ratemaking treatment.
5 PUBLIC INTEREST
6 Q.Can you provide an overview of how the
7 Company's CPCN application for the Combined Projects
8 serves the public interest?
9 A.Yes.The Combined Projects are a tremendous
10 opportunity for Rocky Mountain Power's customers.They
11 support the public interest in three key ways:
12 o First,by reducing costs to customers by capturing
13 federal production tax credits ("PTCs")that
14 essentially pay for critical new transmission
15 infrastructure through the 140-mile,500 kV
16 Aeolus-to-Bridger/Anticline transmission line.
17 o Second,by providing new wind facilities,adding
18 enough new wind energy to power over 400,000 average
19 homes.
20 o Third,by reducing customer risk by securing
21 zero-fuel cost and emission free generation.
22 Q.In supplemental testimony,do any parties
23 support the Company's request for CPCN?
24 A.Yes.The Idaho Public Utilities Commission
25 staff ("Staff")recommend conditional approval of the
726 Crane,Supp-Reb -2
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1 CPCN.O 2 Q.What are the requirements for approval of the
3 CPCN in this case,as outlined in your direct testimony?
4 A.It is my understanding that the Commission will
5 issue a CPCN if it is in the public
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1 interest.To determine the public interest,the
2 Commission must determine whether the present or future
3 public convenience and necessity require additional
4 resources and whether the proposal is a reasonable means
5 of meeting this need.In my direct testimony,I explained
6 that the Combined Projects meet this public interest
7 standard,emphasizing the Company's commitment to run a
8 fair and unbiased RFP process and the need for the
9 Combined Projects,as made clear in the Company's
10 long-term transmission plan and the Company's 2017
11 Integrated Resource Plan ("IRP").
12 Q.Now that the Wind Projects have been selected
13 through the 2017R RFP,do the Combined Projects continue
14 to meet the public interest standard?
15 A.Yes,even more clearly.First,no party has
16 challenged the Company's financial ability to construct
17 or acquire the Combined Projects.
18 Second,the 2017R RFP was monitored by two
19 IEs-one appointed by the Public Utility Commission of
20 Oregon and one retained by the Public Service Commission
21 of Utah.The IEs monitored the 2017R RFP to ensure that
22 the RFP was fair,unbiased,and conducted in the public
23 interest.Both of these independent experts affirmed that
24 the 2017R RFP process and results served the public
25 interest,establishing the Company's good faith.
728 Crane,Supp-Reb -3
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1 Third,the Aeolus-to-Bridger/Anticline line is
2 a necessary investment for customers.The addition of
3 this transmission line by 2024 is an important part of
4 the Company's long-term transmission plan,and the line
5 is needed to relieve congestion,provide voltage support,
6 improve reliability,and reduce line losses.The robust
7 response to the 2017R RFP,and the interconnection
8 constraints faced by many of the bidders,reinforce the
9 importance of adding more transmission capacity in
10 Eastern
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1 Wyoming to harness cost-effective generation resources
2 for customers.
3 In addition,the Wind Projects are needed to
4 provide zero-fuel-cost generation to serve customers,
5 minimizing reliance on front-office transactions and
6 reducing net power costs.The Wind Projects provide
7 significant benefits from currently available PTCs.These
8 benefits allow the Company to construct the Transmission
9 Projects with small near-term rate increases and
10 long-term savings.Since the Company's initial filing and
11 the completion of the 2017R RFP,the near-term rate
12 increases have remained modest,while the long-term
13 benefits of the Combined Projects have increased and the
14 risks have decreased.As I explained in my second
15 supplemental direct testimony,the Combined Projects now
16 show benefits of $167 million in the medium case through
17 2050,and a range of $357 million to $405 million in the
18 medium case through 2036.In the 18 scenarios studied
19 (nine each for the 2050 and 2036 analyses),16 of 18
20 cases show net customer benefits.
21 Q.Please summarize the conclusions of the Utah
22 and Oregon IEs regarding the 2017R RFP.
23 A.As discussed in greater detail in Mr.Rick T.
24 Link's testimony,both IEs found that the 2017R RFP was
25 conducted in a manner that produced the most competitive
730 Crane,Supp-Reb -4
Rocky Mountain Power
1 resource options for customers.The Utah IE specifically
2 concluded that the 2017R RFP was fair,reasonable,and
3 generally in the public interest.(Final Report of
4 Merrimack Energy Group,Inc.to Utah Public Service
5 Commission,PacifiCorp Renewable Request for Proposals at
6 70 (Feb.2018)(hereinafter "Utah IE Report")).According
7 to the IE,the RFP was designed to lead to the
8 acquisition of wind-generated electricity at the lowest
9 reasonable cost.(Utah IE Report at 71).The Company used
10 a "detailed state-of-the-art
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
731 Crane,Supp-Reb -4a
Rocky Mountain Power
1 portfolio evaluation methodology"demonstrating that the
2 Combined Projects "should result in significant savings
3 for customers,"particularly in the near-term.(Utah IE
4 Report at 71,83).
5 The Oregon IE concluded that the Wind Projects
6 were the top viable offers and provide the greatest
7 benefits to ratepayers.(Independent Evaluator's Final
8 Report on PacifiCorp's 2017R Request for Proposals at 2-3
9 (Feb.16,2018)(hereinafter "Oregon IE Report")).The
10 Oregon IE verified the Company's modeling with its own
11 cost modeling of each bid and confirmed that the 2017R
12 RFP aligned with the 2017 IRP.(Oregon IE Report at 2-3).
13 Q.How did the IEs conclude that the 2017R RFP was
14 unbiased?
15 A.First,both IEs conducted a detailed and
16 independent assessment of the Company's benchmark
17 resources.The Utah IE noted that the Company's benchmark
18 information exceeded industry standards,the costs were
19 reasonable,and that there was no outward perception of
20 bias.(Link Second Supp.,page 28,lines 4-21).The
21 Oregon IE stressed that it took special care to confirm
22 the selection of the benchmark resources,that the
23 benchmark costs were disciplined by third-party bids for
24 the same resources,and that his thorough assessment
25 concluded that the benchmark costs were reasonable.
732 Crane,Supp-Reb -5
Rocky Mountain Power
1 (Oregon IE Report at 2-3,10-11).
2 Second,to confirm that there was no bias,the
3 Oregon IE requested that the Company perform a
4 sensitivity analysis to compare the Company's selected
5 bids to an alternative portfolio of PPAs.Both IEs agreed
6 that the results of this sensitivity showed that there
7 was no bias.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
733 Crane,Supp-Reb -5a
Rocky Mountain Power
1 Q.Did the IEs address the modeling and evaluation
2 issues raised by the parties in this case?
3 A.Yes.Nearly every criticism leveled at the
4 Company's solicitation process or modeling in the
5 parties'direct and supplemental testimony was addressed
6 and rejected by the IEs:
7 o The IEs confirmed that the Company's refined
8 modeling of PTC benefits to match how PTCs flow
9 through rates did not bias the bid selection in
10 favor of utility-owned resources.
11 o The IEs reviewed the Company's solar sensitivity
12 related to the 2017S RFP and neither disputed the
13 Company's conclusion that solar resources do not
14 displace the Wind Projects-meaning that wind and
15 solar resources are not an either-or proposition.
16 o The IEs confirmed that the Company's determination
17 of project viability based on interconnection queue
18 positions was reasonable.
19 o The IEs confirmed the accuracy of the Company's
20 terminal-value benefits used to evaluate
21 utility-owned resources,and both IEs further noted
22 that the benefit was modest.
23 Q.Monsanto contends that the power purchase
24 agreements in the solar 2017S RFP represent a superior
25 resource option compared to the Combined Projects
734 Crane,Supp-Reb -6
Rocky Mountain Power
1 (Phillips Supp.Direct,page 28,lines 1-4.)Does the
2 Company agree with this contention?
3 A.No.As discussed by Mr.Link,while the base
4 economic analyses of the now-completed 2017S RFP show
5 that there are potential customer benefits from solar
6 PPAs,solar resources are an incremental opportunity,not
7 an alternative to the Combined Projects.Sensitivity
8 analyses show valuation risks that are unique to solar
9 resource opportunities
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
735 Crane,Supp-Reb -6a
Rocky Mountain Power
1 and costs are expected to continue to fall.Because the
2 expiration of the investment tax credit for solar is not
3 imminent,the Company does not need to act now in order
4 to capture these tax savings.PacifiCorp will continue to
5 assess potential economic benefits from solar-resource
6 opportunities in the 2019 Integrated Resource Plan,
7 including a thorough review of valuation risks with full
8 stakeholder engagement,to determine whether a new
9 competitive solicitation process for projects capable of
10 achieving commercial operation by the end of 2021 will
11 provide customer benefits.
12 Q.Did the IE agree with the Company's conclusions
13 on the 2017S RFP?
14 A.Yes.London Economics International,LLC,the
15 IE retained for the 2017S RFP,concluded:1)that the
16 process was conducted in accordance with its RFP
17 documents;2)that the process was conducted in a fair
18 and unbiased manner;3)the modeling and analysis for the
19 final short list process was fair and reflected industry
20 best practices;4)the sensitivity analysis was
21 reasonable;and 5)the decision not to award any solar
22 bids in this RFP was not inconsistent with the process
23 outlined in the RFP.
24 Q.The parties allege that the Combined Projects
25 pose an undue risk to customers.Do you agree?
736 Crane,Supp-Reb -7
Rocky Mountain Power
1 A.No.In the eight-and-a-half months since this
2 case was filed,the risks have decreased.First,the
3 updated economic analysis demonstrates that under the
4 medium natural gas,medium CO2 scenario,customer
5 benefits increased over the life of the Wind Projects.
6 Higher estimated benefits reduce risk by providing an
7 additional cushion to allow for variability in forecasts
8 through 2050.
9 Second,the Company's economic analysis shows
10 that in almost every future scenario,customers are
11 better off with the Combined Projects than under the
12 status quo
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
737 Crane,Supp-Reb -7a
Rocky Mountain Power
1 (which requires greater reliance on the market,coupled
2 with future acquisitions of non-PTC-eligible resources).
3 Mr.Phillips incorrectly suggests forgoing the
4 time-limited opportunity here would be essentially
5 risk-free.The parties have not demonstrated that the
6 status quo is less cost and less risk in the face of
7 current market opportunities.
8 Third,as project implementation has continued,
9 there is now greater certainty related to the costs of
10 the Combined Projects.Development of the Transmission
11 Projects continues on schedule,and the Company is
12 steadily progressing through the process to acquire
13 necessary easements and rights-of-way in parallel with
14 the regulatory-approval process.The risk of changes in
15 the federal tax code has been resolved.The Company
16 remains confident that the Combined Projects will be in
17 service by 2020,and the Wind Projects will be eligible
18 for 100 percent PTC benefits.
19 Fourth,the selection of primarily self-build
20 or build-transfer agreements ("BTA")bids does not
21 increase the risk profile of the Wind Projects as
22 compared to power purchase agreements ("PPAs").Contrary
23 to Mr.Phillip's claims,the advantages of PPAs,solar or
24 otherwise,is not clear-cut.As Mr.Link explains,PPAs
25 have a different profile of risks and benefits relative
738 Crane,Supp-Reb -8
Rocky Mountain Power
1 to utility-owned resources,but they are not an
2 inherently superior resource option for customers.The
3 bids received in the 2017R RFP reflected both resource
4 options,and the Company used an unbiased analysis to
5 select the best option for customers.In one case,that
6 was a PPA (one-half of Cedar Springs),in other cases it
7 was a benchmark resource (TB Flats I and II and Ekola
8 Flats)or a BTA (Uinta and the other half of Cedar
9 Springs).
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
739 Crane,Supp-Reb -8a
Rocky Mountain Power
1 Q.Does the Company stand by its commitment to
2 assume the risk of non-qualification for PTCs if it is
3 related to the Company's performance?
4 A.Yes.If the Wind Projects are not 100-percent
5 PTC eligible because of some occurrence within the
6 Company's control,shareholders will hold customers
7 harmless.
8 Q.Monsanto recommends that the Company hold
9 customers harmless even for events outside its control.
10 (Phillips Supp.Direct,page 3,lines 9-11).Is this a
11 reasonable condition for approval of a CPCN?
12 A.No.As Ms.Steward,Mr.Teply,and Mr.Link
13 discuss,the parties'proposed conditions are
14 unprecedented and contrary to well-established customer
15 protections provided by the Commission through its
16 traditional ratemaking process.Moreover,the basis for
17 these conditions-that the Combined Projects are
18 discretionary-is unfounded.Notably,Mr.Keller agrees
19 that the Company should protect customers from those
20 risks it can control and mitigate those risks that are
21 beyond its control.(Keller Direct,page 4,lines 5-15).
22 The Company agrees with Mr.Keller and has implemented
23 measures to mitigate risks within its control and
24 believes that the existing regulatory process,reflected
25 in the Commission's past practice,is sufficient to
740 Crane,Supp-Reb -9
Rocky Mountain Power
1 address risks that are beyond the Company's control.
2 Q.What is your request to the Commission in this
3 case?
4 A.For the future of our customers,I firmly
5 believe that the Combined Projects are a prudent and
6 beneficial investment,and their development and
7 acquisition is in the public interest.Respectfully,I
8 ask the Commission to approve the CPCNs and binding
9 ratemaking treatment for the Combined Projects.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
741 Crane,Supp-Reb -9a
Rocky Mountain Power
1 Q.Does this conclude your supplemental rebuttal
2 testimony?
3 A.Yes.
4
5
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7
8
9
10
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12
13
14
15
16
17
18
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742 Crane,Supp-Reb -10
Rocky Mountain Power
1 (The following proceedings were had in
2 open hearing.)
3 MS.McDOWELL:With that,Ms.Crane is
4 available for Commissioner questions and
5 cross-examination.
6 COMMISSIONER ANDERSON:Thank you.Mr.
7 Budge.
8 MR.BUDGE:Thank you,Mr.Chairman.
9
10 CROSS-EXAMINATION
11
12 BY MR.BUDGE:
13 Q Good afternoon,Ms.Crane.
14 A Good afternoon.
15 Q You're the Company's policy witness,as I
16 understand it?
17 A That's correct.
18 Q And I wanted to ask you about some of the
19 fundamental issues in the case.There's a fundamental
20 disagreement between intervenors and the Company on some
21 basic issues,and one that the Commission will have to
22 decide is whether these combined projects meet the Idaho
23 statutory requirement for a CPCN and also whether they
24 meet the statutory requirement for binding ratemaking
25 treatment,and your testimony addressed both of those
CSB REPORTING 743 CRANE (X)
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1 issues,if I recall correctly.O 2 A That's correct.
3 Q Would you agree that that is a fundamental
4 threshold issue for the Commission to decide is whether
5 or not those statutory requirements are met?
6 A That's correct.
7 Q And with respect to that testimony,
8 assuming the Commission makes a determination that there
9 is a necessity for these particular projects,the next
10 major issue would be is this particular combined project
11 in fact the least cost,least risk resource;would you
12 agree that's a significant issue for them to decide?
13 A Yes,that's my understanding.
14 Q And I think that's one we also have a
15 disagreement on there is the Company's testimony that
16 this is the least cost,least risk resource and there's
17 some testimony that perhaps a solar resource falls in
18 that category,but in any event,that's one of the
19 fundamental issues the Commission has to decide,and
20 assuming that --the third issue,as we see it,I wanted
21 to see if you viewed it the same way,that would be
22 significant,if the Commission in fact finds that there's
23 a necessity for this project and that the combined
24 projects are indeed least cost,least risk,then they'll
25 have to address that issue that remains open in the
CSB REPORTING 744 CRANE (X)
208.890.5198 Rocky Mountain Power
1 settlement stipulation is,is what kinds of conditions
2 should be imposed,including whether or not a hard cap
3 may or may not be appropriate.
4 A That's my understanding based on the
5 parties'positions in their filings.
6 Q Okay;so do you see those as the
7 fundamental issues that are presented to the Commission
8 here?
9 A I do.
10 Q All right,I would like to --because you
11 had some specific testimony with respect to the statutory
12 requirements and I know Ms.Steward who testified earlier
13 also talked specifically about those statutory
14 requirements,I wanted to ask you a few questions about
15 those and I thought it might be best that we actually
16 have the statutes in front of us so I can ask you
17 questions specifically to the statute that relates to the
18 CPCN,which has a different standard than the statute
19 that relates to binding ratemaking treatment,so if I
20 may,Mr.Chairman,I'll hand the witness what we'll mark
21 as Monsanto Exhibit 219.
22 (Mr.Budge approached the witness.)
23 (Monsanto Company Exhibit No.219 was
24 marked for identification.)
25 MS.McDOWELL:So I don't interrupt
CSB REPORTING 745 CRANE (X)
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1 counsel's cross-examination,I do just want to state anO2objectioninadvancetoquestionsonbindingratemaking
3 treatment.The testimony this morning is that the
4 Company has withdrawn the request for binding ratemaking
5 treatment.It's no longer a part of the Company's
6 filing,because it's not a part of the stipulation and as
7 I indicated this morning,we are here really presenting
8 that stipulation and asking for the Commission's approval
9 of that stipulation.
10 COMMISSIONER ANDERSON:Mr.Budge.
11 MR.BUDGE:Thank you.That was going to
12 be my very first question of Ms.Crane,so you beat me to
13 the punch on that one.
14 Q BY MR.BUDGE:That being confirmed,we'll
15 simply focus on the CPCN questions,so the statutes that
16 you referred to in your testimony are Idaho Code 61-526,
17 that is the second statute,and as part of that exhibit
18 is the binding ratemaking statute 61-541,so we won't ask
19 any questions with respect to that particular portion of
20 the exhibit,and I will note for the record that the
21 highlighting in there is mine simply to be able to
22 identify the portions of the statute easily that we're
23 looking at,because these statutes are one sentence the
24 whole page,so with respect to the first page on Exhibit
25 219,which is Idaho Code section 61-502A,that is
CSB REPORTING 746 CRANE (X)
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1 basically the fundamental statute that the Commission hasO2todecideinanyratemakingprocessiswhetherornotthe
3 resource is currently used and useful which I've
4 underlined there.
5 MS.McDOWELL:Excuse me,I'd like to
6 object.Unless there is a citation to her testimony
7 where she's testified on this statute,I'm not sure this
8 is within the scope of her testimony.
9 MR.BUDGE:I can respond.Certainly,
10 it's within the scope.The entire scope of her testimony
11 is that this particular project meets the Idaho statutory
12 requirements for a CPCN,and under Idaho law,all
13 utilities,the Commission is basically prohibited from
14 approving any project that is not used and useful,so
15 this is somewhat of a preliminary question,but it
16 certainly relates to the CPCN statute that deals with the
17 fundamental issue of necessity.
18 MS.McDOWELL:If I can just respond,
19 Ms.Crane is not a lawyer.She certainly has cited the
20 CPCN statute and is available for questions on the CPCN
21 statute,but the used and useful statute and the
22 connection to the used and useful statute to the CPCN
23 statute,she's not testified on that.She's not a lawyer
24 and I don't think it's appropriate to ask her questions
25 about the relationship between those statutes when she's
CSB REPORTING 747 CRANE (X)
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1 not,you know,provided any testimony on that subject.
2 MR.BUDGE:With due respect to counsel,I
3 won't belabor the point,because I think we can move one.
4 While I recognize Ms.Crane is not a lawyer,she chose to
5 present testimony providing legal opinions on the
6 statutes and how they should be interpreted within the
7 context of the evidence presented by the Company,and she
8 specifically testified that we meet the Idaho statutory
9 requirements.
10 COMMISSIONER ANDERSON:Well,I think the
11 Chair is going to rule that I would put it more of what
12 her opinion would be at this point and is there somebody
13 else that's going to be a witness that you could actually
14 confirm what you're trying to get to?I mean,is there a
15 way to address that down the road?
16 MR.BUDGE:She is the only witness that
17 has presented testimony that the filing meets the Idaho
18 requirements to move forward.
19 COMMISSIONER ANDERSON:I'll permit the
20 question to be asked,provided that you don't go too far
21 as her expertise would limit her as not being an
22 attorney.
23 MR.BUDGE:Okay,thank you.
24 MS.McDOWELL:Commissioner,can I just
25 ask if Mr.Budge could point to a portion of the
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1 testimony that he's referring to where he's indicated
2 that Ms.Crane has testified as he has so stated?
3 COMMISSIONER ANDERSON:You certainly can
4 ask.I think we were about to get there anyway,so you
5 may ask.
6 MR.BUDGE:Let's do this:Idaho Code
7 502A is what it is and I think the Commission is well
8 aware that they have to make a determination that the
9 asset,if constructed,is used and useful,and my only
10 question to the witness would pertain to that,but let's
11 move instead,if we could,to the second page of the
12 exhibit,which is the --
13 COMMISSIONER ANDERSON:Mr.Budge,I think
14 the question that you were trying to ask,though,and
15 let's be careful that we don't try to do this too many
16 times,if you're asking a witness whether or not they
17 agree with what state law is,we don't need to go
18 there.
19 MR.BUDGE:I don't intend to do that.
20 COMMISSIONER ANDERSON:Okay,thank you.
21 MR.BUDGE:I have no intention to do
22 that.
23 Q BY MR.BUDGE:So Idaho Code section
24 61-526 sets forth the criteria for a CPCN and if you can
25 follow along with me,the highlighted portion says that
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1 no electric corporation shall heretofore begin theO2constructionofaplantwithouthavingfirstobtained
3 from the Commission a certificate that the present or
4 future public convenience and necessity require or will
5 require such construction.What I wanted to focus on is
6 the fundamental issue in this case and that is necessity,
7 and do you have --there isn't a definition in the
8 statute or elsewhere in the Code that I could find for
9 the word necessity.When you rendered opinions and
10 testimony in this case,you talked about various benefits
11 from the project.Is it your testimony that the word
12 necessity simply means if the project provides benefits
13 it meets this necessity requirement under the statute?
14 A No,if I could clarify,and I'd also refer
15 us to the stipulation itself on page 3,paragraph 9,
16 where the stipulating parties are requesting that the
17 Commission find --I mean,the stipulating parties are in
18 agreement that what we have brought forward in this
19 proceeding is in accordance with the Code and is a
20 reasonable way to meet the present or future public
21 convenience and necessity,so maybe that just as a
22 backdrop.
23 From the standpoint of necessity,need,
24 whatever term we're going to envelope it with there,the
25 Company does extensive resource planning.We've got our
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1 long-term transmission plans and we've got our integrated
2 resource plans and we do those every other year and
3 update them on the off year.
4 Q I apologize for interrupting you up front,
5 but I want to just get back first to the questions I ask
6 rather than reiteration of the testimony of the Company,
7 so my question is do you have a definition of necessity
8 that you use for purposes of making or coming to your
9 conclusion that this project does meet the necessity
10 requirement?How do you define necessity?
11 A The fact that the Company does have an
12 open position and the Company always looks to fill that
13 open position in the least cost possible way.
14 Q How would you define the word necessity?
15 A We have a requirement to meet our load,
16 right,so we have to serve it one way or another and so
17 the necessity is we have a gap.We have to serve that
18 gap to meet our load obligations and our reserve
19 obligations,so we do have a need and it's a matter of
20 how you fill that need.
21 Q So you would basically equate a need to
22 the word necessity?
23 A Yes.
24 MR.BUDGE:Can I have the witness please
25 handed what we've marked as Monsanto Exhibit 221?
CSB REPORTING 751 CRANE (X)
208.890.5198 Rocky Mountain Power
1 (Monsanto Company Exhibit No.221 was
2 marked for identification.)
3 COMMISSIONER ANDERSON:Mr.Budge,would
4 you like 219 and 221 entered into the record?
5 MR.BUDGE:Yes.
6 COMMISSIONER ANDERSON:So be it.
7 (Monsanto Company Exhibit Nos.219 &221
8 were admitted into evidence.)
9 Q BY MR.BUDGE:So Ms.Crane,in Exhibit
10 221,I've included at least what a dictionary definition
11 of the word necessity would be.The first page you would
12 note is an Oxford Dictionary definition and you'll notice
13 the words there,state of being unavoidable or an
14 indispensable thing.If you turn to the second page,
15 this is from the Merriam Webster Dictionary,Merriam
16 Webster Dictionary.It's very,very similar.It defines
17 necessity as something that is inevitable or unavoidable
18 or compulsory,and the third definition comes from
19 Dictionary.com,little eager to find on my phone,but it
20 uses the same words,something that is indispensable or
21 imperative,and would you disagree that these dictionary
22 definitions are appropriate definitions of the word
23 necessity?
24 A No.In fact,I find them very applicable
25 to the need that we have an obligation to fulfill.
CSB REPORTING 752 CRANE (X)
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1 Q And is it your testimony that this
2 particular wind project is indispensable in the sense
3 that the Company would have an inability to serve its
4 load if this project were not built as scheduled?
5 A I define need as we have an open position
6 and we have to fill it.That's the need and that is
7 unavoidable.We are required to meet our obligations.
8 It's how we do it that the wind project comes into play
9 and we do it in the least cost,least risk manner.
10 Q Thank you.Now,I can appreciate that's
11 the Company's testimony,but my question was a little
12 more specific.If this project is not constructed as
13 scheduled,will the Company have its ability to meet its
14 load in 2021?
15 A The Company will rely on higher cost front
16 office transactions and it will cost our customers more
17 money.
18 Q And will it have the ability to meet its
19 load in 2025,'26,'27,and '28 without building any new
20 capacity resources?
21 A It depends on what circumstances evolve at
22 the time --
23 Q And did --
24 A --but we would continue to rely on
25 available market purchases at much higher cost.
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1 MS.McDOWELL:Can I just interrupt forO2onesecond,and actually,my objection here is to the
3 fact that the witness is continually being interrupted
4 and not being allowed to finish her answers,and I'm
5 afraid we're going to have a record that is jumbled if
6 she cannot complete her answers before the next question
7 comes on.
8 MR.BUDGE:I fully agree and I'd simply
9 ask that the witness be responsive to the question that
10 is asked.The questions so far could all be answered yes
11 and no,and the witness has gone on,but in due respect,
12 I'll try to let the witness answer within reason if
13 she'll be responsive to the questions.
14 MS.McDOWELL:And I just want to object
15 to that characterization,because she has been very
16 responsive.It's just that her answers may not be to Mr.
17 Budge's liking.
18 COMMISSIONER ANDERSON:Well,let's all
19 try to not talk over one another,and if you would like
20 something to be more specific,direct it that way and if
21 it's not answered that way,then --
22 MR.BUDGE:All right.
23 Q BY MR.BUDGE:So is it a fact that if the
24 Company does not build this particular transmission line
25 it in fact will be able to meet all of its load through
CSB REPORTING 754 CRANE (X)
208.890.5198 Rocky Mountain Power
1 2028?O 2 A Based on our planning,yes,at a higher
3 cost.
4 Q So one of the real issues in this case
5 deals with whether the projects are in fact a want or a
6 real true necessity and I have a little bit of an analogy
7 here --
8 MS.McDOWELL:Objection.I don't know if
9 he's trying to characterize Ms.Crane's testimony,but
10 that is not a correct characterization of her
11 testimony.
12 MR.BUDGE:Well,this is
13 cross-examination,so I think I'm entitled to ask
14 questions of the witnesses based upon whatever factual
15 situation I'm on.
16 COMMISSIONER ANDERSON:I think Mr.
17 Budge's summation of what his understanding of what this
18 case is,I think the Commission understands that's what
19 he's saying,an overall,so I'll let this continue.
20 Q BY MR.BUDGE:Ms.Crane,and this is what
21 I was trying to get to,you're contending that the
22 definition of necessity is in fact being met,that even
23 though you do not need new transmission and even though
24 you do not need new capacity until 2028,there is in fact
25 a necessity today to build this project simply to be able
CSB REPORTING 755 CRANE (X)
208.890.5198 Rocky Mountain Power
1 to displace market purchases that may or may not be more
2 expensive in the future;would that be an accurate
3 statement of what you're claiming?
4 A Yes.I mean,I think we have fully
5 demonstrated on the record through all of the integrated
6 resource planning that the Company one,has a need and it
7 has a need today;and two,the Company has met that need
8 historically with front office transactions;and No.3,
9 we have a circumstance today because of the production
10 tax credit value that for the first time we're actually
11 seeing these projects displace front office transactions
12 because they're lower cost.
13 Q Let me give you an analogy of perhaps
14 another example of what may be a necessity versus a
15 discretionary project,that being an area of disagreement
16 not only between the Company and the intervenors,but
17 also a disagreement between the Company and Staff with
18 respect to whether this is discretionary,so when my wife
19 goes into the Lexus dealer a few years ago,she said that
20 there's an exciting opportunity for me to buy a new car
21 that's a hybrid and it's going to be more reliable.It's
22 going to get better gas mileage.
23 This is kind of a limited opportunity,
24 because I have an opportunity to sell my car for a short
25 period of time,and this hybrid that is a pretty
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1 expensive car,they have a special deal in place until
2 the first of the month and if I buy now,I get a better
3 deal,and so our discussion goes on that does your car
4 that you have now work?Does it get you from point A to
5 point B,and it does,so would you agree that buying a
6 new car under those circumstances is not necessarily a
7 necessity if in fact you're able to get from point A to B
8 in some fashion or another?
9 A Certainly.It doesn't appear that that
10 scenario would indicate a need.
11 Q And so me being the practical husband like
12 the ratepayers here say I'm kind of concerned that buying
13 this car,a new car is going to drive up the payments,in
14 response to which my wife said this is going to get
15 really good gas mileage.I mean,how does that pen out
16 to me as a customer with respect to future payments,and
17 the pen-out is well,if gas prices will go up to $5.00 a
18 gallon,we'll be able to justify this additional hybrid
19 cost over the next 10 years,and because she had a want,
20 the car got bought.
21 It turned out that over that period of
22 time gas prices have never gone above $4.00 and at the
23 end of the day when the car gets ready to trade in,it
24 actually trades in at a discount because hybrids are no
25 longer the latest technology.Folks want other types of
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1 cars,but at the end of the day,the dealer's perspective
2 is this was still an exciting opportunity,but from the
3 perspective of the customer,the opportunity was no
4 longer quite so exciting when in fact it costs you money
5 rather than saves you money,and I think would you agree
6 that that's a bit of what we have here?
7 This project is an exciting opportunity
8 for the Company because it has the ability to make a
9 large,huge investment in capital and earn a rate of
10 return,but the concern from customers,I want to know if
11 you appreciate the concern from customers,is the
12 potential that we will have a rate increase now that we
13 may not otherwise have had going forward depending on gas
14 prices and all of those things,so I want to know if you
15 can appreciate the fact that intervenors have concern
16 that this project might drive rates up,not down.
17 MS.McDOWELL:I just want to object.There
18 are about four questions in that question and I'm not
19 quite sure which one is pending.
20 Q BY MR.BUDGE:You can answer the last
21 one.
22 A We are always concerned about our
23 customers and we take --every decision we make is based
24 on what believe is in the best economic interest of our
25 customers,so that's not even a question to me.I mean,
CSB REPORTING 758 CRANE (X)
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1 that is how we run our Company.
2 Q Let me ask you a little bit more about the
3 amount of the investment costs and I know that's changed
4 over the course of the project,but I understand that
5 approximately $2.2 billion is the total cost of the
6 project?
7 A I believe it's more of an approximate
8 two.
9 Q Okay,but approximately 2 billion.Is it
10 true that this would be the largest capital investment
11 made by PacifiCorp in its history since it was acquired
12 by MidAmerican Energy,now Berkshire Energy,in about
13 2005?
14 A Well,I certainly haven't been involved in
15 every one of those investment decisions since then,but
16 it is certainly one of the largest.It is a portfolio,
17 obviously,of multiple wind facilities and transmission
18 together to make it work.
19 Q But you're not aware of any projects of
20 this magnitude of capital investment?
21 A Not that I am aware of beyond maybe back
22 when we built the big fleet.
23 Q There's been a lot of testimony filed with
24 respect to the benefits to the customers.I wanted to
25 ask you with respect to the benefit to the Company,how
CSB REPORTING 759 CRANE (X)
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1 would you do the calculation on a $2 billion investment
2 under Idaho's authorized rate of 9.8 percent?
3 A Well,all of that is actually --it's not
4 about how would I do it.It's how it's been calculated.
5 In the economic analysis that Mr.Link has done an
6 extensive amount on,it includes the cost.It includes
7 the return.It includes the benefits,and it identifies
8 that there is a net benefit under the scenarios that he
9 has run.
10 Q Let me ask it a different way:Do me the
11 math on how the --what the rate of return would be to
12 the Company on an investment of that size?How do you do
13 the math in dollars?
14 A Well,if you --
15 Q From the customer's standpoint,what is
16 the amount the Company gets paid to have its return on
17 its equity investment of 2 billion?
18 A The Company gets an allowed rate of return
19 that is determined by the Commission at any point in
20 time.
21 Q The current authorized rate of return in
22 Idaho is 9.8 percent,so would the math be that times the
23 $2 billion number or whatever it is?That would be the
24 return on investment to the Company?
25 A One could do it that way,yeah.
CSB REPORTING 760 CRANE (X)
208.890.5198 Rocky Mountain Power
1 Q That would be an annual amount based on
2 whatever that base rate number is over the years?
3 A Yes,offset by any depreciation.
4 Q So when you testified in this case and I
5 believe also in Wyoming that this is an exciting
6 opportunity,would it be fair to say that it's an
7 exciting opportunity for the stockholders of PacifiCorp
8 and the owners to be able to make an investment of this
9 magnitude and earn a 9.8 percent rate of return,is that
10 an exciting opportunity from their perspective as well?
11 A Well,I think it's an exciting opportunity
12 because it's a limited opportunity for all parties,and
13 when we started this process,we did not have any
14 certainty that at the end of the day out of the RFP
15 processes that the Company would own any of these
16 projects.That gets determined from the RFP process,and
17 in fact,the Company benchmarks did prevail,but also,a
18 power purchase agreement for 200 megawatts also
19 prevailed,so I mean,there was no guarantee in our mind,
20 nor did we start that way going into this opportunity.
21 It was about capturing the production tax
22 credit value for the benefit of our customers.It was
23 about adding no fuel resources for long-term benefits for
24 our customers and being able to essentially pay to have
25 transmission built by having the production tax credit
CSB REPORTING 761 CRANE (X)
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1 value actually pay for the cost and get the reliability
2 benefits and everything associated with that as well.
3 Q So part of the economic benefits that
4 accrue to Idaho would not accrue to --excuse me,it
5 would accrue to Wyoming.If we were trying to compare
6 the Wyoming stipulation with Idaho,there would be a
7 significant difference in that Wyoming,does it not,get
8 the economic benefit of the $2 billion investment;
9 correct?
10 A Yeah;so obviously,in Wyoming where
11 assets are being built,there are economic benefits to
12 the communities and the economy,but those are not
13 factored into the analysis to justify the net benefit of
14 these projects.
15 Q Well,there was some discussion here,I
16 want to point out that the Wyoming settlement has facts
17 that are substantially different from the Idaho
18 settlement that's being proposed by the Company and
19 Staff,and one of them is the pure economic benefits in
20 that the jobs for construction would all be in Wyoming;
21 correct?
22 A That is correct for these.
23 Q And there's about 1,000 construction jobs
24 involved?
25 A Thereabouts.
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1 Q And isn't it true that the full-time
2 employees of 75 to 100 as been estimated by the Company
3 would all be in Wyoming;correct?
4 A That is correct.
5 Q And then the tax benefits would accrue to
6 Wyoming;would that be correct?
7 A That would be correct.
8 Q And the Company's filing indicates that
9 there's like $70 million in tax revenues that would
10 accrue in Wyoming?
11 A During construction.
12 Q And would the Wyoming settlement be under
13 circumstances different than we have here,because we're
14 simply talking about one case,a new wind transmission
15 project here,where in fact Wyoming was a cumulative
16 settlement of the new wind as well as the repower in
17 addition to the tax case?
18 A Could you repeat the question?
19 Q Yes;so another difference between --the
20 issue in this case is simply the combined projects,but
21 when the settlement was made in Wyoming,weren't in fact
22 the settlement resolving the new wind case that we're
23 talking about here,the wind repower case as well,and
24 there was also a component that settled the tax act case
25 in Wyoming?
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1 A Yes,that is the case.That is whatO2Ms.Steward also testified on today.
3 Q Would you agree that this rather huge
4 investment is coming at a time when we have surplus
5 energy throughout the West?
6 A At points in time we have surplus energy,
7 but we always have.
8 Q And would you agree that over the last
9 several years,the last decade,we've seen rather
10 dramatic changes in the energy market in the West?
11 A Definitely we have at certain times of the
12 day and in certain times of the year.
13 Q And are those dramatic changes that we've
14 seen over the last decade or so in electricity costs,
15 solar costs,and the like,are those in fact driven in
16 part by technology changes over that period of time?
17 A In part.I'd say it's mostly been driven
18 by public policy in specific Western states,but yeah.
19 Q And is it also driven by resource finds?
20 A Resource what?
21 Q In other words,there's been lots of gas
22 developed in the Balkan area and now in the Texas area.
23 I picked that up from your IRP that gas supplies have
24 increased dramatically.
25 A Yeah,and that's why we've seen lower gas
CSB REPORTING 764 CRANE (X)
208.890.5198 Rocky Mountain Power
1 prices.O 2 Q In your position as a policy manager for
3 the Company,would you have reason to believe that we
4 should expect similar changes in the future that
5 technology is going to have an impact on prices as well
6 as other factors,policy changes and the like?
7 A I think we always have market dynamics.
8 They don't always go in our customers'favor,so is there
9 going to be new technology advancements in the future,
10 absolutely.What are they,when are they coming,are
11 they economic,it's your crystal ball or mine,I mean.
12 Q And that's something we're all speculating
13 about a little bit as to whether or not this project that
14 looks good today would look as good in 2028 when there's
15 actually a need for a new capacity resource?
16 A Well,actually we have a need today.
17 We're currently filling it with a higher cost solution,
18 which is front office transactions and we've done the
19 analysis and this is lower cost for our customers and it
20 also allows us to secure zero fuel cost resources.
21 Q And whether that will be a lower cost
22 going forward is a direct dependent --is directly
23 dependent upon what future market and gas prices are in
24 the West;correct?
25 A Not necessarily.
CSB REPORTING 765 CRANE (X)
208.890.5198 Rocky Mountain Power
1 Q So it has --
2 A The Company has an open position and --
3 Q Let's --
4 A --will continue to have an open position.
5 I mean,that's what Mr.Link has clearly demonstrated.
6 MS.McDOWELL:I just would like to renew
7 my objection to Mr.Budge interrupting Ms.Crane when
8 she's one sentence into her answer.
9 MR.BUDGE:I apologize.
10 Q BY MR.BUDGE:So if in fact the Company
11 has assumed in its economic analysis a medium gas pricing
12 scenario going forward,if in fact prices continue to
13 decline,isn't it a fact that market purchases may be the
14 least cost resources going forward if gas prices and
15 electricity continue to decline?
16 A But that might displace other resources in
17 our portfolio.
18 Q But it's also possible,is it not,that if
19 we have declining gas prices that the energy produced
20 from the wind projects is no longer in the market?
21 A Zero fuel cost resources will always
22 compete in the market.
23 Q So basically if I understand the Company's
24 position,this $2 billion is a desired hedge against
25 future cost increases in market prices?
CSB REPORTING 766 CRANE (X)
208.890.5198 Rocky Mountain Power
1 A I did not say that.
2 Q Would you consider it to be a hedge?
3 A I do not consider it to be a hedge.I
4 consider it to be an opportunity to be able to capture
5 $1.2 billion in production tax credit value for the
6 benefit of our customers and then be able to have zero
7 fuel cost resources that will continue to serve our
8 customers well into the future.
9 Q So when this case was filed and updated
10 following the RFP earlier this year,it was largely based
11 upon and supported by the 2017 IRP;is that correct?
12 A That's correct.
13 Q And more recently the Company has filed an
14 update to that on May 1st,2018?
15 A Yes,we did.
16 Q And I'd like to ask you some questions on
17 that update and because it's a lengthy document,let me
18 hand you what's been marked as Monsanto Exhibit 220 and
19 I'll represent that this is a selected number of pages
20 from the May 1st,2018,update of the Company's 2017 IRP.
21 MS.McDOWELL:So we just want to indicate
22 here that Mr.Link who testified here and for whom Mr.
23 Budge had no questions is our manager of the IRP process.
24 He is the one who authored and was in charge of the IRP
25 update,so I just want to put out there that he is
CSB REPORTING 767 CRANE (X)
208.890.5198 Rocky Mountain Power
1 probably the person who is much more qualified to answer
2 questions on the IRP update than Ms.Crane who is our
3 policy witness in this case.
4 MR.BUDGE:Well,if appropriate,I can
5 re-call him as a witness later,but I think these
6 questions are of a general nature to take up with this
7 witness.
8 COMMISSIONER ANDERSON:We'll give it the
9 weight.Go ahead.
10 (Monsanto Company Exhibit No.220 was
11 marked for identification.)
12 Q BY MR.BUDGE:So if you'd turn to page 2
13 of this update,it's the first bullet point,it states,
14 "With reduced loads and lower renewable resource costs,
15 the updated preferred portfolio contains no new natural
16 gas resources through the 20-year planning horizon.This
17 is the first time an IRP has not included a new
18 fossil-fueled generation as a least cost,least risk
19 resource."
20 It also goes on,if you would,if you'd
21 turn to the next page when the IRP begins to talk about
22 things that have changed in the update,Figure 1.1 is
23 essentially showing that the peak load forecast is
24 reduced rather considerably in the update from what was
25 being forecast at the time of the 2017 IRP;would that be
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1 correct?O 2 A I believe that's what it reflects.
3 Q And the explanation at the bottom shows
4 that the forecast of natural gas and energy prices have
5 declined from those that were in the 2017 IRP;correct?
6 A That's what the document says.
7 MS.McDOWELL:I would like to renew my
8 objection to this witness being questioned on this IRP
9 update.This is not in her testimony.Mr.Link is our
10 witness on the IRP.He has testimony on the IRP.Mr.
11 Budge has not pointed to any testimony that he is
12 cross-examining Ms.Crane on.He's just physically
13 reading the IRP and asking her to agree that it says what
14 it says.If he's got questions in the IRP,he ought to
15 call Mr.Link.
16 MR.BUDGE:Well,due respect to counsel,
17 this witness has testified that there is a present need
18 for this new resource and this an appropriate document
19 for cross-examination,which I'm going to get to,because
20 she has indicated that the Company has managed to rely
21 upon market purchases which may be more costly,and this
22 updated IRP not only shows that costs are going downward,
23 it shows as a result of that their load deficit and need
24 has diminished some 4-500 megawatts,so my area that I
25 intend to go in with her is to ask her in lieu of these
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1 declining prices,this update would seem to suggest that
2 some of the price concerns that the Company is relying
3 upon are not necessarily materializing at the rate they
4 expected.
5 MS.McDOWELL:If I can just say
6 generally,my concerns are that we have yet to have Mr.
7 Budge point Ms.Crane to a particular question and answer
8 in her testimony that he's cross-examining her on.I
9 mean,typically,in our cross-examination here,we file
10 our direct testimony and our supplemental testimony and
11 people cross-examine off of that.Mr.Budge has yet to
12 point to an item in Ms.Crane's testimony that he's
13 actually cross-examining her on,and it just seems
14 inappropriate to let him go especially into an area where
15 we have another witness who's much better qualified and
16 actually has testimony on this issue that should be
17 subject to cross-examination,if anyone is,on these
18 issues.
19 MR.BUDGE:If the witness wants to defer
20 the question to another witness,I'm fine with that,but
21 to the extent that she's able to answer questions with
22 respect to how the new IRP update has reduced prices and
23 changed load that affects how they're able to make front
24 office purchases to meet their loads through 2028,this
25 is kind of the policy witness.
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208.890.5198 Rocky Mountain Power
1 COMMISSIONER ANDERSON:Well,I thinkO2certainlyifthat's the case,then we should allow the
3 witness to deflect to somebody else to testify,and I
4 agree with counsel that your questioning so far has just
5 been to confirm that this is an IRP and that you're not
6 getting to the questions.If you have a question to ask,
7 let's assume that we all agree this is in the IRP.It is
8 the IRP,so it's what it says and it's self-evident to
9 me.If you have a specific question to ask and then she
10 can defer if she wishes.
11 MR.BUDGE:Thank you.
12 Q BY MR.BUDGE:So on page 4,the
13 highlighted portion says that load and resource balance
14 capacity need has decreased by an average of 408
15 megawatts,relative to the 2017 IRP,reflecting a lower
16 load forecast and an increase in qualifying facility
17 contracts,so my question is to the extent that the
18 resource balance has decreased by some 408 megawatts,
19 would it not be likely that the Company will have the
20 ability to meet its needs from front office transactions
21 at least until 2028 or even beyond?
22 A It's my understanding that the analysis
23 that Mr.Link has prepared and filed of most recent for
|
24 the stipulated projects is based on and takes into
25 consideration the IRP update.He is certainly the
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1 witness that can speak to that and the detail aboutO2that.
3 Q Does this indicate,also,that the
4 Company's projection of when its new resources will be
5 needed continues to be pushed out as they file each IRP
6 going forward over the years?
7 A Well,what it's demonstrating is that
8 there are no other resources in his current --in the IRP
9 update that displace front office transactions until that
10 thermal resource that's outside the window.
11 Q If the needs have decreased by 400
12 megawatts from what it was just a few months ago,doesn't
13 that mean the need for the new resources would simply be
14 pushed out farther?
15 A No.Actually,the new resources are in
16 this portfolio.
17 Q The ability to meet your load needs by
18 market purchases will be easier to make than it would
19 have been before now that the load growth has gone
20 down?
21 A Well,front office transaction is always a
22 part of how we meet our load.It is a factor of how deep
23 is the market and what's the price and is there something
24 more economic to displace it.
25 Q So is it true that while the Company will
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1 try to model and forecast future gas prices,that's one
2 of the items factored in here that are beyond the control
3 of the Company?
4 A Certainly.
5 Q And so is that one of the risks that you
6 expect the customers to bear going forward?
7 A Well,I think the price of natural gas is
8 a variable in the marketplace and depending upon whether
9 it goes up or down depends on how the fleet dispatches.
10 Again,in a dispatch mode,a zero fuel cost resource will
11 always dispatch first.
12 Q And so what you're suggesting is that we
13 should spend $2 billion as a hedge against market prices
14 essentially going up?
15 No,what I said previously is this is an
16 opportunity to capture over 1,000,200,000 in production
17 tax credits and an opportunity to meet this need for our
18 customers and provide significant net benefits for our
19 customers in the tune of hundreds of millions.
20 MR.BUDGE:May I have just a moment here?
21 Just a couple other questions,if I could.
22 Q BY MR.BUDGE:Is it true that the Company
23 currently meets all reliability standards with its
24 current transmission?
25 A I am not a transmission expert.
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208.890.5198 Rocky Mountain Power
1 Q You're not aware of any standards thatO2aren't being met?
3 A I'm not aware that they're not being met.
4 If we weren't meeting them,I would be aware.How we're
5 meeting them,I do not have the detail of that.Mr.Vail
6 would be your witness.
7 Q Thank you.Would you say the Company
8 provides good reliable service with customers at this
9 point in time?
10 A I would say we strive very hard to do so,
11 yes.
12 Q Do you expect the Company will have the
13 ability to do so going forward at least for the next
14 several years whether or not you build the combined
15 projects?
16 A I am not the person that has visibility to
17 what the growing reliability standards are,but we are
18 always getting new reliability standards placed on us.
19 That would be Mr.Vail.
20 Q What about renewable portfolio standards,
21 to your knowledge,is the Company in full compliance with
22 all existing renewable portfolio standards?
23 A Yes,we are.
24 Q And do you expect to continue to be in
25 compliance in the next several years going forward?
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208.890.5198 Rocky Mountain Power
1 A Yes,we do.O 2 Q And I believe some states,Washington,
3 Oregon,in fact,have a large bank of credits that have
4 been built up with respect to renewables?
5 A Yes,that is accurate,and the Company has
6 never taken a position that this stipulated set of
7 projects is to meet any renewable portfolio standard
8 need.In fact,it is not.
9 Q Are you familiar with the testimony in
10 here that the Company filed with respect to the solar
11 alternative PPA that was proposed through the Utah order?
12 Are you generally familiar with the fact that the solar
13 PPA is an issue that's been presented in this case as
14 possibly a lower cost resource,lower risk resource?
15 A What I'm familiar with is that Utah did
16 request us to also do a solar RFP,and we did conduct a
17 solar RFP and we did have a robust response and that Mr.
18 Link in his analysis managed all of that RFP and the
19 economics around all the bids,and he also did
20 comparisons of the solar shortlist,and his determination
21 was that they did not displace the stipulated projects.
22 Q And the Company takes the position that
23 one of the reasons the solar PPA should not be considered
24 at this point in time is because in fact solar prices are
25 going down and you expect it to be even a lower cost
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1 resource in the future?O 2 A Well,I think there's a couple reasons why
3 we don't believe now is the right time.That is one of
4 them.
5 Q Okay,thank you.
6 A The other one is that the --oh,now I
7 lost my train of thought,so we'll have to come back to
8 that one.
9 Q Okay,well,I won't ask you the other one.
10 I think you were trying to get to another reason besides
11 solar costs were going down --
12 A The other reason --
13 Q --and to defer it because it may be less
14 expensive to build in a year or two?
15 A So certainly,the solar costs are on a
16 downward decline.That is absolutely something that
17 we've cited.The other thing is there is no timeline
18 opportunity in order to have to make those decisions
19 today.The investment tax credit is not phasing out at
20 the same level and time frame as the production tax
21 credit,so we have the opportunity to continue to
22 monitor,which we plan to do very extensively,and
23 continue to analyze additional solar in our 2019 IRP and
24 continue to look at that opportunity,because we do think
25 the prices will continue to come down and there will be a
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1 better economic opportunity.I will go back to theO2analysisthatMr.Link has done.Even adopting the
3 shortlist out of the solar RFP and running it in the IRP
4 models,it does not displace the stipulated projects.
5 Q So if this Commission were to decide
6 there's not a necessity today for the combined projects,
7 is it the Company's position that we should further defer
8 solar for a couple of years because you expect those
9 prices to go down?
10 A The Company's position is that we should
11 be proceeding with the stipulated projects,because we
12 have an opportunity to capture significant net benefits
13 for customers and zero fuel resources and that's our
14 position.
15 Q Okay,that wasn't my question.My
16 question was if the Commission determines that there's
17 not a necessity to build the combined projects today,if
18 I understand the Company's testimony,they would suggest
19 that we defer solar projects as well for a couple more
20 years,because you see solar prices going down?
21 A The Company doesn't believe that --the
22 Company believes we have a need.The Company believes
23 and has done a robust analysis and a competitive RFP and
24 has identified that this is a unique opportunity to
25 capture the benefits of the production tax credits and
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1 deliver hundreds of millions of dollars in benefits to
2 our customers.That's the Company's position.
3 Q Let me ask the question one more time.I
4 think we're well aware of the Company's position.My
5 question was if this Commission rejects your project on
6 the basis that there is not a necessity today,given the
7 Company's testimony that solar costs are going down,
8 would you defer any action on a solar PPA to see whether
9 or not costs continue to decline?
10 A If the Commission were to not approve the
11 stipulated projects going forward,the Company would have
12 to reassess everything and it isn't just about solar.
13 Q One of the other significant differences
14 with the solar PPA is the Company would not get any
15 capital investment or return on investment;is that
16 true?
17 A If they came through as PPAs,that would
18 be accurate.
19 Q And if a solar PPA was invested in,there
20 would be no risk to the customers with respect to what
21 future gas prices may be,because you'd be contracting to
22 buy energy at a specific price?
23 A Maybe not specific to gas,but there are
24 other risks.You could be locking in high on a PPA
25 that's long term.I mean,there's a variety of risks
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1 that you could look at there.
2 Q But it's true that the risks associated
3 with the uncertainty of future gas prices would be
4 eliminated through a solar PPA if you choose to take that
5 as a resource?
6 A I don't know how that eliminates those
7 risks.
8 Q One of the issues that remains is whether
9 or not the Company should have a hard cap,and as I
10 understand it,Staff's position remains with respect to
11 the settlement stipulation that there should be a hard
12 cap on all capital costs for both the wind facilities and
13 the transmission and as I understand,the Company opposes
14 that hard cap;correct?
15 A That's correct,that's what Ms.Steward
16 testified to.
17 Q Would you agree that the exciting
18 opportunity that the Company sees for this project would
19 be shared more by the customers if in fact they had some
20 hard cap protections?
21 A I wouldn't agree with that.I think $338
22 million in net benefits is an exciting opportunity to
23 capture and I think our customers think that that's
24 exciting as well.
25 Q Well,my question was that the intervenors
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1 and Staff believe there are significant risks that theO2costsmayinfactgoupandwealreadyknowwe'll have a
3 rate increase from the testimony of Ms.Steward earlier
4 of about 1.7 percent the first few years of the project.
5 My question was don't you believe the Company or the
6 customers would have a degree of excitement about the
7 project if they knew the risks of their rates going up
8 were diminished by a hard cap?
9 A I don't know how that links to excitement,
10 but --
11 Q Let's assume that the Commission chose to
12 place a hard cap based on the Company's capital cost
13 filings,is it true that even with a hard cap of that
14 nature,the customers would have some risks,and one of
15 those risks would be that gas prices,market prices,
16 continued to decline and we are in the two of the nine
17 scenarios that provide a cost rather than a benefit?
18 A I'm not how sure you're correlating a cost
19 cap with a gas curve.
20 Q Poorly asked question,but assuming that
21 we had a hard cap on capital costs,the customers are
22 still at risk if gas prices decline in the future;
23 correct?
24 A Again,I don't see a correlation between
25 gas prices and a capital hard cap cost.
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208.890.5198 Rocky Mountain Power
1 Q I'm simply trying to point out that the
2 customers will still have risks that they have a $2
3 billion investment in a project that is not in the money,
4 because there are less costly resources out there or
5 there are less costly market purchases available.That's
6 still a risk that the customers would have even with the
7 cost cap;correct?
8 A Well,once the facilities are built,they
9 will dispatch first.There is a zero fuel cost.That is
10 how the dispatch works.
11 Q With respect to the PTCs,isn't it true
12 that even if we had a hard cap that the customers are at
13 risk that the PTCs may not fully be generated if in fact
14 the wind didn't blow as much or if the wind blows at a
15 time during the middle of the day when there's lots of
16 solar and not at night when they might be needed,so the
17 actual PTC revenues that are based upon generation is a
18 risk that we would still take as customers even if we had
19 a hard cap on capital costs;correct?
20 A That's correct.We can't guarantee the
21 wind,that it blows and when it blows.What I can tell
22 you is you can look at our history of our wind fleet and
23 our wind projects have produced higher net capacity
24 factors than what our initial estimates on those were,so
25 that's just factual information.
CSB REPORTING 781 CRANE (X)
208.890.5198 Rocky Mountain Power
1 Q So would you agree that absent a hard cap,
2 the Company is essentially assuming no risk with respect
3 to this project?
4 A I would disagree with that 100 percent.
5 Q What risks would the Company be assuming
6 other than perhaps cost overruns that require prudency
7 review?
8 A So the Company has already accepted the
9 PTC qualification risk to get them qualified,so we have
10 taken that risk.
11 Q Is there any other risk you're assuming?
12 A We've also taken the risk that if there
13 are overruns,we may not get them approved.We carry
14 that risk.
15 Q I want to talk to you about that.Has
16 there ever been a situation where the Company had made a
17 large investment in your other transmission plants that
18 you were not able to get approval during prudency
19 review?
20 A I am not the detail person that I can tell
21 you about each of those investments.Have we had
22 investments disallowed from a general statement,yes,we
23 have.
24 Q Would you agree when it comes to prudency
25 review,it's a fairly low bar for the Company to cross
CSB REPORTING 782 CRANE (X)
208.890.5198 Rocky Mountain Power
1 once the cement and steel are in the ground?
2 A We don't view it as a low bar.We view it
3 as a huge obligation on our part to be able to
4 substantiate it.
5 Q Well,I think that the customers'ability
6 to come in and prevail in a prudency review once $2
7 billion has been spent on steel and cement is a pretty
8 high bar;would you agree?
9 A I would not agree with that.If the
10 Company has mismanaged and had imprudent costs,that's
11 what the prudency review looks at.
12 Q Let me take you back to the example of the
13 Populus to Terminal project which we remember very well.
14 When the merger occurred,MidAmerican came in and
15 indicated that line would be constructed to deal with the
16 constraints and the line was going to cost $80 million.
17 When the Company later built the project and came in to
18 have it approved,it cost 800 million and no part of the
19 project was disallowed.
20 MS.McDOWELL:I just want to object.You
21 know,Mr.Budge is testifying here.There is a whole
22 history and,you know,long set of details around that
23 transmission line which he has just misstated,so it's
24 not appropriate for him to misstate the facts,which are
25 not in evidence,and then ask Ms.Crane a question about
CSB REPORTING 783 CRANE (X)
208.890.5198 Rocky Mountain Power
1 them.O 2 MR.BUDGE:I'll ask it a different way.
3 Q BY MR.BUDGE:To the best of your
4 knowledge,I know you're not the person that may have all
5 the details,but during your career with PacifiCorp,is
6 it true that you have never seen a multi-billion dollar
7 project once it's constructed not get full review in a
8 general rate case project --in a general rate case
9 process,get full admission into rate case in a general
10 rate case?
11 A I am familiar with some investments that
i
12 have not been put in rates and it varies in different
13 states and they're different investments.There's no
14 blanket yes,this one.
15 Q But your belief is it doesn't create a
16 high bar for the Company once the projects have been
17 fully built and the steel and cement is in the ground?
18 A No,I think I said just the opposite of
19 that.
20 MS.McDOWELL:I'm going to object to
21 that.She has asked --
22 THE WITNESS:There is a high bar.
23 MS.McDOWELL:Sorry,I just want to make
24 my objection because I think this question has now been
25 asked about three or four times and each time she's said
CSB REPORTING 784 CRANE (X)
208.890.5198 Rocky Mountain Power
1 she does not agree.
2 MR.BUDGE:I'll withdraw the question.
3 MS.McDOWELL:Thank you.
4 COMMISSIONER ANDERSON:Thank you.
5 MR.BUDGE:No further questions.Thank
6 you.
7 COMMISSIONER ANDERSON:Thank you.
8 Mr.Williams.
9 MR.WILLIAMS:No questions.
10 COMMISSIONER ANDERSON:Mr.Olsen.
11 MR.OLSEN:No questions here.
12 COMMISSIONER ANDERSON:Staff.
13
14 CROSS-EXAMINATION
15
16 BY MR.KARPEN:
17 Q Good afternoon,Ms.Crane.
18 A Good afternoon.
19 Q I'm going to keep this brief.Mr.Budge
20 talked to you about the CPCN 61-526.As you're aware,
21 we've agreed --
22 COMMISSIONER RAPER:Your mic is on Mr.
23 Budge.Thank you.
24 Q BY MR.KARPEN:I'll start over.As
25 you're aware,Staff and the Company have agreed that this
CSB REPORTING 785 CRANE (X)
208.890.5198 Rocky Mountain Power
1 project falls under or qualifies under 51-526 [sic].You
2 are also likely aware that there is some disagreement
3 over whether there is a present or a future need that is
4 being met under the CPCN.Is that accurate with what the
5 Company and the Staff positions are?
6 A Correct.You said 51-526,it's 61-526.
7 MR.KARPEN:Numbers aren't my thing.
8 THE WITNESS:You may have to repeat the
9 question now.
10 Q BY MR.KARPEN:So I'll start over.As
11 you're aware,we agree that this project qualifies under
12 61-526 and as you are also aware where we do disagree is
13 between if the combined projects present a present or a
14 future need;is that accurate?
15 A I am not familiar with that distinction.
16 I'm looking at the stipulation and the stipulating
17 parties are requesting --so I'm on page 3,paragraph 9,
18 and it says,"The stipulating parties request that the
19 Commission find that:(1)the stipulated projects are
20 prudent and in the public interest,and (2),"which I
21 think is to your point,"in accordance with Idaho Code
22 61-526,the stipulated projects are a reasonable way to
23 meet the present or future public convenience and
24 necessity."
25 Q Okay;so I guess I will represent to you
CSB REPORTING 786 CRANE (X)
208.890.5198 Rocky Mountain Power
1 for the purposes of these questions that Staff is of the
2 belief that this meets a future necessity and my
3 understanding of Company testimony is that this meets a
4 present necessity;is that an accurate description of at
5 least the Company's position?
6 A The Company agrees with the stipulation
7 that it meets the present and/or future.
8 Q Okay.Now,in your direct testimony as
9 well as your supplemental testimony,I'm not going to
10 hold you to any numbers,as we've already illustrated,
11 I'm not so good at those,you talk about the significant
12 benefits,I'll just leave it at significant benefits,
13 that will accrue to customers once the projects have been
14 completed.Would you agree that those significant
15 benefits will only accrue if the Company comes in at its
16 estimated costs and there is a risk potential that if the
17 Company does not come in at its cost,the significant
18 benefits will diminish or perhaps disappear entirely?
19 A No,I would not agree.I believe what
20 we've testified is that the analysis we believe that
21 substantiates the significant benefits is also a
22 conservative analysis,and I believe when Mr.Link was up
23 here,he also referenced several items,one being
24 renewable energy credit revenues and others that actually
25 we have not built into the analysis that have a high
CSB REPORTING 787 CRANE (X)
208.890.5198 Rocky Mountain Power
1 probability of adding additional benefits,so I think
2 there's even potential for greater benefits would be my
3 answer.
4 Q So you wouldn't agree that,for example,
5 if there was a cost overrun by 25 percent that these
6 projects would not be beneficial to customers?
7 A I would have to do the math,but we
8 certainly have done some calculations as to what the
9 breakeven is and we know that that number is in the
10 hundreds of millions'difference there,and that,too,
11 has not taken into consideration the conservative other
12 items that are not in the analysis that we believe that
13 there are strong probabilities will manifest to benefits
14 as well.
15 Q You were here when Mr.Link was testifying
16 earlier;correct?
17 A Yes,I was.
18 Q And you were also here when Mr.Link
19 testified on cross that even --that even two of the nine
20 possible future scenarios would not show customer
21 benefits,namely,low gas,zero CO2,low gas,medium CO2
22 regardless of cost overruns;isn't that correct?
23 A I don't remember the details of the
24 testimony.It's obviously on the record.
25 Q Okay.In your rebuttal testimony,you
CSB REPORTING 788 CRANE (X)
208.890.5198 Rocky Mountain Power
1 talk about the Company agreeing to a soft cap based on
2 cost estimates if the actual costs are greater than the
3 final estimates here.I'm quoting on page 4 of your
4 rebuttal.
5 A Okay,thank you.
6 Q If actual costs are greater than the final
7 estimate here,the Company agrees it must demonstrate the
8 prudence of the additional costs in a subsequent
9 ratemaking proceeding,so I kind of have a couple of
10 questions for you on that.In standard ratemaking,would
11 the Company need to demonstrate prudence of any cost
12 regardless of being additional or not?
13 A Absolutely.
14 Q So in that regard,the soft cap serves
15 pretty much the same as a standard ratemaking
16 procedure?
17 A I think what the soft cap is doing is,
18 especially as we've built it into the stipulation,the
19 soft cap has capped,you know,the mechanisms and,you
20 know,essentially kept costs and benefits balanced and
21 only up to that soft cap can flow through the,whether
22 it's the,RTM or the ECAM combined --
23 Q Yeah,I'm --
24 A --and therefore,anything else would have
25 to come forward in a future rate proceeding.
CSB REPORTING 789 CRANE (X)
208.890.5198 Rocky Mountain Power
1 Q And I apologize for interrupting you.
2 What I'm talking to is an overall project cost cap,not
3 the caps associated with the RTM.
4 A They are two of the same,but okay.
5 Q Well,in the RTM,I suppose,when I refer
6 to that,I mean an overall capital cost rather than those
7 that are passed through on a year-by-year basis.
8 A Let me go to the stipulation,because I
9 don't want to misspeak,but my understanding is we did
10 both.The Company in the stipulation,I'm looking for
11 the exact spot,so subject to check,obviously,the
12 stipulating parties agreed that even in the mechanisms,
13 we are capped at the soft cap for anything to be able to
14 go through those mechanisms.
15 Q Okay;so maybe I should clarify,and I'm
16 coming from the position of the Staff proposal of
17 imposing --requesting that the Commission impose a hard
18 cap and that would serve a different purpose than a soft
19 cap that's associated with the RTM.
20 A Definitely two different things,there's
21 no doubt about that.
22 Q Okay.In your direct rebuttal on page 8,
23 you were talking about risks that are within the
24 Company's control and you said you somewhat agreed with
25 Staff's characterization,such as meeting the safe harbor
CSB REPORTING 790 CRANE (X)
208.890.5198 Rocky Mountain Power
1 requirement to qualify for the PTCs,meeting regulatory
2 requirements,permitting that are required to place the
3 projects in service,achieving timely completion of
4 combined projects.I'd like to focus on achieving the
5 timely completion of the combined projects.At this
6 point in time at the decisional point,would you agree
7 that the closer that we get to the end of 2020 deadline
8 the higher the risk is there would be for a potential
9 cost overrun?
10 A No,no,I wouldn't necessarily agree with
11 that.I think as you go through a project,actually
12 risks decrease because things get more certain and more
13 firmed up as you go through the cycle even once you are
14 in construction,because you know what you're dealing
15 with.You're actually on the ground and so I actually
16 don't believe that risks grow as you get towards the
17 deadline.
18 Q Okay;so I'll get back to that in a little
19 bit.I'm assuming you're familiar with Mr.Teply's
20 testimony.I won't hold you to anything that he's
21 testified to,of course,but he goes into some pretty
22 extensive detail about the schedule.He calls it a
23 critical path,in fact,which I like that phrase.
24 A Standard project management dialogue.
25 Q Yes,but Mr.Teply's critical path notes
CSB REPORTING 791 CRANE (X)
208.890.5198 Rocky Mountain Power
1 that the CPCNs must be attained from all threeO2jurisdictions,Wyoming,Utah,and Idaho,by,originally
3 it was,the end of March of this year and that was the
4 only way that this critical path could be met.Here we
5 are now in mid May and I believe that the hearing for
6 this project in Utah is another two weeks out,so it
7 seems that we are off of the critical path;would you
8 agree with that?
9 A So as regulatory schedules had got set and
10 then some were modified,our project teams have gone
11 back,whether it's on the transmission or otherwise gone
12 back,and looked at,you know,how can we manage by doing
13 some things in parallel,and so we have adjusted our
14 activities to do a little bit more in parallel in order
15 to substantiate and support the regulatory schedule and
16 that's how we've adjusted for it.
17 Q So if we get to a point hypothetically,
18 say,down the road that there are delays in perhaps
19 acquiring all of the rights of way in Wyoming or there
20 are unforeseen circumstances that require maybe some
21 overtime that comes out to build the transmission line,
22 you would not agree that the closer we get to that 2020
23 deadline the more likely the overtime or just pay them to
24 get the right of way would occur?
25 A No,I don't agree with that,because we
CSB REPORTING 792 CRANE (X)
208.890.5198 Rocky Mountain Power
1 don't conduct our business that way.What I can tell you
2 is that we are making great progress on our rights of
3 way.As I think you're all aware,we have secured the
4 CPCNs from Wyoming and we were also able to reach terms
5 with several of the large landowners on the rights of way
6 as part of that process and continue to make good
7 progress on those remaining,so actually,we think that
8 we are actually ahead of schedule when it comes to those
9 things,because we made tremendous progress as we were
10 going through the Wyoming proceedings and so,you know,
11 from that standpoint.Now,that said,you always have
12 things in a project that give and take and,you know,you
13 flex,but never in a mindset of just throw money at it.
14 Q This kind of actually speaks to your
15 certainty and I said I'd go back to that,in your
16 supplemental rebuttal testimony on page 8,you state that
17 there's now greater certainty related to the costs of the
18 combined projects.You include with that,as you just
19 mentioned,the rights of way and the parallel regulatory
20 approval process,the resolution of the federal tax code.
21 You seem pretty confident that you're meeting that
22 critical path that Mr.Teply refers to;is that --
23 A I've lost track of where you were at,but
24 I got the question,though.
25 Q Okay,I apologize.It was supplemental
CSB REPORTING 793 CRANE (X)
208.890.5198 Rocky Mountain Power
1 rebuttal page 8 and I'm not trying to trick you.I'm
2 just saying your quote is there is now greater certainty
3 related to the costs of the combined projects.
4 A Yes.
5 Q You would agree with that.How,I guess,
6 how certain?Let me rephrase that.Do you believe it's
7 certain enough that the Company should be willing to bet
8 on it,if you will,if it had to?
9 A The certainty around things are as we're
10 going through the process,so,you know,we've got RFPs,
11 we've got EPC contracts,you know,getting through the
12 bid cycles and getting contracts locked down,
13 negotiating,you know,the wind turbine equipment and
14 those types of contracts.Where we're not at in the
15 cycle yet is actual on-the-ground construction and
16 certainly,you've got weather variables,a lot of
17 different things that come into play when you are in
18 construction and so I think certainty and uncertainty
19 changes and evolves as you move through this life cycle
20 of a project.Certainly,as the risks --this is getting
21 to the risks that were being raised in the filings and
22 yes,we are making great strides in greater certainty
23 around those,rights of way,those type of items that
24 were raised.
25 Q Mr.Budge asked you about some of the
CSB REPORTING 794 CRANE (X)
208.890.5198 Rocky Mountain Power
1 conditions in Wyoming,the employment and the tax
2 benefits that the State of Wyoming will benefit from that
3 Idaho won't benefit from.Do you recall that line of
4 questioning?
5 A Yeah,I'm aware of the economic
6 benefits.
7 Q Okay.Do you believe that those economic
8 benefits played into the calculation of the hard cap that
9 Wyoming agreed to?
10 A No,I do not.
11 Q So you don't believe that Wyoming agreed
12 to a higher hard cap than it would have otherwise because
13 of the substantial benefits that would be seen through
14 taxes and jobs?
15 A No,I believe that the parties,WIEC and
16 the OCA,actually followed their authorities,which was
17 what was before them,which was the projects that were
18 being asked for the CPCNs,and it was all based on those
19 economics for the net benefit for customers,and so the
20 cap that got agreed to in that stipulation was calculated
21 as a breakeven on the projects.It had nothing to with
22 those economic things that accrue to the counties and the
23 cities,because they're not anywhere in the case.
24 They're referenced,but they're not in the numbers.
25 Q To clarify,it's a breakeven on the medium
CSB REPORTING 795 CRANE (X)
208.890.5198 Rocky Mountain Power
1 gas,medium CO2?
2 A That is correct.
3 Q Okay,under those circumstances,customers
4 would see benefits in four-and-a-half of the
5 four-and-a-half potential futures that the Company
6 calculated;is that accurate?
7 A Mr.Link could answer that question.He's
8 more familiar with all his scenarios.
9 MR.KARPEN:I understand.That's all I
10 have for you,Ms.Crane.Thank you.
11 THE WITNESS:You bet.
12 COMMISSIONER ANDERSON:Thank you.
13
14 EXAMINATION
15
16 BY COMMISSIONER RAPER:
17 Q I don't want to unnecessarily elongate
18 this.I just want to go back to the discussion of market
19 purchases,front office purchases.The Company
20 standardly holds open as a portion of its resource stack
21 this opportunity,right,for market purchases?
22 A Based on the economics,we fill a front
23 office position based on other opportunities,other
24 options,other resource options,to fill it.They're not
25 as economic as what the forward transactions are at that
CSB REPORTING 796 CRANE (Com)
208.890.5198 Rocky Mountain Power
1 time.
2 Q Right.Outside of the scenario of these
3 projects,just generally speaking,but doesn't the
4 utility look at it as part of their resource stack and
5 will utilize the front office transactions if they are
6 economic?
7 A Yes,we will and in fact,we will increase
8 those if the economics in the marketplace actually are
9 beneficial for us to ramp down our other resources in
10 order to capture those low cost benefits for our
11 customers.
12 Q So your counsel can object to this being
13 not part of your testimony if she'd like --
14 MS.McDOWELL:I won't.
15 Q BY MR.LOWNEY:--but is that part of176wherethebenefitsthe
EM
berecptuceom
from the realtime
18 market,so yes,right,so from a front office
19 transaction,I could be over my ski tips,but Mr.Link
20 will straighten it out for me if we need it,but we do
21 realtime transactions,but we also do day-ahead
22 transactions,you know,and if we see a weather pattern
23 coming or,you know,we're starting to see some movement,
24 we'll do a few days or three,you know,type of things
25 out into the market,so there's no cookie cutter from
CSB REPORTING 797 CRANE (Com)
208.890.5198 Rocky Mountain Power
1 that standpoint and we will adjust based on what the
2 market is doing and what demand is projected to be
3 doing.
4 Q Okay,I guess I ask that because it seems
5 as if what the Company has shown to this point is that
6 there are great benefits being generated through the
7 EIM --
8 A That's correct.
9 Q --not my statement for the benefit of the
10 record,but what the Company has shown so far.We have
11 made no determination on that as a Commission.I guess
12 the question would be we're not going to lose the
13 benefits that are being gained,then,through the EIM
14 market by eliminating --I mean,if you replace those
15 market transactions,those market purchases,with these
16 wind projects,you're not losing somehow the benefits
17 that are being gained through that EIM market?
18 A No,we are not.
19 Q Okay,and one more thing,so if the
20 Company has cost overruns,to kind of get to what Mr.
21 Budge was talking about earlier and the hard caps and
22 soft caps,if the Company has cost overruns,is it your
23 understanding that the Company is at risk of not
24 recovering that anyway?
25 A It's my position that the Company has the
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208.890.5198 Rocky Mountain Power
1 prudence obligation and we bear that obligation,and whenO2wecomeforwardtoputtheprojectsintogeneralrates,
3 any overruns that we have experienced,we will to have to
4 be able to defend their prudence.
5 Q Do you agree with Mr.Budge that it's a
6 low bar for prudency review at this Commission?
7 A No,I do not.
8 COMMISSIONER RAPER:Neither do I.That's
9 all I have.Thank you,Chair.
10 COMMISSIONER ANDERSON:I won't talk about
11 my thoughts on high or low bars and prudency.
12 You may redirect.
13 MS.McDOWELL:Thank you.
14
15 REDIRECT EXAMINATION
16
17 BY MS.McDOWELL:
18 Q Ms.Crane,just to close up this set of
19 questions,I hope,on the market purchases,do you have
20 Monsanto's Exhibit 220,the IRP update,there in front of
21 you still?
22 A I do.
23 Q And on page 5,can you turn to that
24 particular page for me?
25 A Yes,I'm there.
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208.890.5198 Rocky Mountain Power
1 Q And I'll represent to you that this is aO2graphthatdemonstratestheCompany's open position
3 before any new generation is added or front office
4 transactions are acquired.Are you generally familiar
5 with this capacity position comparison?
6 A Yes,I am.
7 Q And do you understand that the different
8 blue bars show --
9 MR.WILLIAMS:Objection,Mr.Chairman.
10 This is her own witness.I think she's leading the
11 witness.
12 MS.McDOWELL:I can the ask the questions
13 in a more open way if you'd like.It's up to you.I
14 mean,technically,I should ask open questions,not
15 leading questions,but everybody else is.
16 Q BY MS.McDOWELL:But I'll just say this:
17 What do the blue bars show,Ms.Crane?
18 MR.BUDGE:I would have the same
19 objection that Ms.McDowell had to me,that it was not
20 appropriate to present questions to this witness about
21 the IRP which should have been presented to Mr.Link.
22 MS.McDOWELL:And let me just say that he
23 went ahead and asked those questions.She answered them
24 and now I'm redirecting,so it's completely appropriate.
25 If she can't answer my redirect,then she can --
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208.890.5198 Rocky Mountain Power
1 MR.KARPEN:I had no questions withO2respecttopage5orFigure1.3.
3 COMMISSIONER ANDERSON:Ms.McDowell,
4 let's try to refrain from you giving testimony,too.I
5 mean,it does borderline on that a little bit.
6 MS.McDOWELL:I'll be careful about
7 that.
8 COMMISSIONER ANDERSON:Ask a specific
9 question and we'll move forward and move on.
10 Q BY MS.McDOWELL:So,Ms.Crane,does this
11 chart show the open position of the Company before any
12 front office transactions,the Company makes any front
13 office transactions,during the planning period up to
14 2027?
15 A Yes,it does.
16 Q And based on this graph after the Company
17 adds the stipulated projects,would the Company still
18 have an open capacity position?
19 A Yes,it will from a capacity position
20 standpoint.
21 Q So,Ms.Crane,you were also asked,I
22 believe,by Mr.Karpen about whether in certain scenarios
23 if there were cost overruns whether the projects would no
24 longer be beneficial and I just want to ask you this
25 question because there's some concern about or some
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208.890.5198 Rocky Mountain Power
1 confusion about net benefits versus benefits and so canO2youanswerinascenariowheretherearenonetbenefits,
3 in your opinion,are the projects,do the projects remain
4 beneficial?
5 A I believe they bring a lot of different
6 benefits that are not in a net neutral,yes,because we
7 are acquiring zero fuel resources and getting a
8 transmission line that is free net capacity and allowing
9 greater dispatch of existing resources,and so I do
10 believe there are a lot of benefits that are not just
11 quantified in the net benefit analysis that we have in
12 the case.
13 Q Then,last,I wanted to ask you,there was
14 some confusion,I think,when Mr.Budge was asking you
15 about needs and wants and he asked you specifically about
16 both the need for new resources by 2028 and then I
17 believe asked you about the need for new transmission by
18 2028,what is your understanding about the timeline that
19 the Company has in its planning horizons for new
20 transmission?
21 A Yeah,our long-term transmission plans do
22 reflect the Aeolus-to-Bridger/Anticline project coming
23 on-line in the 2024 time frame and that is not driven by
24 any resources that are associated with it.That is
25 driven by what transmission planners are required to do
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208.890.5198 Rocky Mountain Power
1 to comply.
2 MS.McDOWELL:That's all I have.Thank
3 you.
4 COMMISSIONER ANDERSON:Thank you.Thank
5 you,Ms.Crane.
6 THE WITNESS:Thank you.
7 (The witness left the stand.)
8 COMMISSIONER ANDERSON:We'll take a
9 five-minute break.
10 (Recess.)
11 COMMISSIONER ANDERSON:Back in order and
12 you may continue with calling your next witness.
13 MR.LOWNEY:The Company calls Rick Vail.
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING 803 CRANE (ReDi)
208.890.5198 Rocky Mountain Power
1 RICK A.VAIL,
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 MR.LOWNEY:
9 Q Mr.Vail,could you please state and spell
10 your name for the record?
11 A Yes,it's Rick Vail.That's R-i-c-k
12 V-a-i-l.
13 Q And Mr.Vail,how are you employed?
14 A I am the vice president of transmission at
15 PacifiCorp.
16 Q And are you the same Rick Vail that filed
17 direct testimony on June 30th of 2017?
18 A Yes.
19 Q And did you also file rebuttal testimony,
20 supplemental direct testimony,second supplemental direct
21 testimony,and supplemental rebuttal testimony in this
22 case?
23 A Yes,I did.
24 Q Do you have any additions or corrections
25 that you'd like to make to that prefiled testimony
CSB REPORTING 804 VAIL (Di)
208.890.5198 Rocky Mountain Power
1 today?O 2 A No,I do not.
3 Q And if I were to ask you the questions hat
4 are set forth in that prefiled testimony,would your
5 answers be the same?
6 A Yes,they would.
7 MR.LOWNEY:Commissioner Anderson,I
8 would move that Mr.Vail's prefiled testimony and
9 exhibits be spread upon the record as if read.
10 COMMISSIONER ANDERSON:Without objection,
11 we will spread Mr.Vail's testimony and exhibits across
12 the record.
13 (Rocky Mountain Power exhibits sponsored
14 by Mr.Rick Vail were admitted into evidence.)
15 (The following prefiled direct,rebuttal,
16 supplemental direct,second supplemental direct,and
17 supplemental rebuttal testimonies of Mr.Rick Vail are
18 spread upon the record.)
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CSB REPORTING 805 VAIL (Di)
208.890.5198 Rocky Mountain Power
1 Q.Please state your name,business address,and
2 present position with PacifiCorp.
3 A.My name is Rick A.Vail.My business address is
4 825 NE Multnomah,Suite 1600,Portland,Oregon 97232.My
5 present position is Vice President of Transmission.I am
6 responsible for transmission system planning,customer
7 generator interconnection requests and transmission
8 service requests,regional transmission initiatives,
9 asset management,capital budgeting for transmission,and
10 administration of the Company's Open Access Transmission
11 Tariff ("OATT").I am testifying on behalf of Rocky
12 Mountain Power ("Company").
13 QUALIFICATIONS
14 Q.Please describe your educational background and
15 professional experience.
16 A.I have a Bachelor of Science Degree with Honors
17 in Electrical Engineering with a focus in electric power
18 systems from Portland State University.I have been
19 employed at the Company since 2001,and have had a range
20 of management responsibility within the asset management
21 group,including capital planning,maintenance policy,
22 maintenance planning,and investment planning.I served
23 as director of asset management from 2007 to 2012.I
24 became Vice President of Transmission in December 2012.
25 PURPOSE AND SUMMARY OF TESTIMONY
806 Vail,Di -1
Rocky Mountain Power
1 Q.What is the purpose of your testimony?
2 A.My testimony supports the Company's Application
3 for Certificates of Public Convenience and Necessity
4 ("CPCNs")for the construction or acquisition of four
5 wind facilities in Wyoming ("Wind Projects")totaling
6 approximately 860 megawatts ("MW")and the construction
7 of new transmission facilities that are necessary to
8 relieve existing congestion and enable interconnection of
9 the proposed Wind Projects into the
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807 Vail,Di -la
Rocky Mountain Power
1 Company's transmission system.Specifically,my testimony
2 describes the purpose for and customer benefits resulting
3 from the construction of the "Transmission Projects":
4 "Aeolus-to-Bridger/Anticline Line"
5 o A 140-mile,500 kilovolt ("kV")transmission
6 line ("Aeolus-to-Anticline line"),which
7 includes construction of the new Aeolus
8 (500/230 kV)and Anticline (500/345 kV)
9 substations;
10 o A five-mile,345 kV transmission line that will
11 extend from the proposed Anticline substation
12 to the Jim Bridger substation,along with
13 associated interconnection facilities at the
14 Jim Bridger substation to accommodate the
15 interconnection of the 345 kV line from the
16 proposed Anticline substation;
17 o A voltage control device at the existing
18 Latham substation.
19 "230 kV Network Upgrades"
20 o A new 16-mile 230kV transmission line parallel
21 to an existing 230 kV line from Shirley Basin
22 substation to the proposed Aeolus substation,
23 including modifications to the Shirley Basin
24 substation to accommodate the new line;
25 o The reconstruction of four miles of an existing
808 Vail,Di -2
Rocky Mountain Power
1 230 kV transmission line between the proposed
2 Aeolus substation and the Freezeout substation,
3 including modifications of the Freezeout
4 substation to accommodate the new line;and
5 o The reconstruction of 14 miles of an existing
6 230 kV transmission line between the Freezeout
7 substation and the Standpipe substation,
8 including modifications to the Freezeout and
9 Standpipe substations to accommodate the
10 transmission lines.
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809 Vail,Di -2aRockyMountainPower
1 The reconstructed sections are proposed to be
2 in a parallel alignment to the existing 230 kV
3 transmission line.The 230 kV Network Upgrades are needed
4 to support interconnection of the Wind Projects,which
5 are described in the testimony of Company witness Mr.
6 Chad A.Teply.
7 My testimony and exhibits provide the
8 information required by Rule 112 of the Idaho Public
9 Utilities Commission's ("Commission")Rules of Procedure
10 ("RP"),related to applications for CPCNs for the
11 Transmission Projects.
12 Q.Please summarize your testimony.
13 A.The Transmission Projects support the Company's
14 short-and long-term energy demands and will strengthen
15 the overall reliability of the existing transmission
16 system.While the Aeolus-to-Bridger/Anticline Line has
17 long been recognized as an integral component of the
18 Company's long-term transmission planning,its
19 construction and that of the other components of the
20 Transmission Projects has not been economic until now.
21 Renewal of the federal wind production tax credits
22 ("PTC")has created a time-limited opportunity for the
23 Company to acquire significant cost-effective,
24 zero-fuel-cost wind resources,generating PTCs that
25 provide cost savings necessary to construct the
810 Vail,Di -3
Rocky Mountain Power
1 Transmission Projects.
2 To achieve the full customer benefits of the
3 PTCs,however,the Company must develop the Wind Projects
4 with the Transmission Projects and bring them into
5 service by December 31,2020.The Wind Projects are not
6 economic without the Transmission Projects,which are
7 needed to relieve existing congestion and to interconnect
8 new PTC-eligible wind facilities in high-wind areas of
9 Wyoming.The Transmission Projects are not economic
10 without incremental cost-effective wind
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811 Vail,Di -3a
Rocky Mountain Power
1 facilities producing zero-fuel-cost energy and PTCs.
2 Congestion on the current transmission system
3 in eastern Wyoming limits the ability to deliver energy
4 from eastern Wyoming to the Jim Bridger energy hub.The
5 Aeolus-to-Bridger/Anticline Line will relieve this
6 congestion and increase the transmission capacity across
7 Wyoming by 750 MW.The Transmission Projects will allow
8 the Company to interconnect up to approximately 1,270 MW
9 of wind resources,including the 860 MW of Wind Projects
10 that are the subject of this Application,and create
11 substantial benefits for Idaho customers and customers
12 throughout the Company's service area.Construction of
13 the Transmission Projects will also enable the Company to
14 more efficiently utilize existing generation resources in
15 Wyoming to serve loads in Idaho,Wyoming,Utah and the
16 Pacific Northwest.The Transmission Projects also better
17 position the Company to interconnect and integrate future
18 resources in southeastern Wyoming and more efficiently
19 serve expected customer load.
20 In addition to increasing the transmission
21 capacity out of southeastern Wyoming,the Transmission
22 Projects will also provide critical voltage support to
23 the Wyoming transmission network and enhance the overall
24 reliability of the transmission system by adding
25 incremental new transmission capacity westbound between
812 Vail,Di -4
Rocky Mountain Power
1 the Company's existing thermal and renewable facilities,
2 the proposed Wind Projects in eastern Wyoming,and other
3 sources of energy in northern Utah.Additional
4 transmission paths will mitigate the impact of outages on
5 the existing system.The Transmission Projects will also
6 enhance the Company's ability to comply with mandated
7 North American Electric Reliability Corporation ("NERC")
8 and Western Electricity Coordinating Council ("WECC")
9 reliability and performance standards.
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813 Vail,Di -4a
Rocky Mountain Power
1 The Aeolus-to-Bridger/Anticline Line is also anO2importantcomponentoftheCompany's Energy Gateway
3 Transmission Expansion Project ("Energy Gateway")and has
4 long been recognized as a key transmission segment in the
5 region's long-term transmission planning.By acting on
6 this time-limited opportunity to develop the Transmission
7 Projects and the associated Wind Projects,the Company
8 can provide substantial customer benefits.
9 GENERAL DESCRIPTION OF THE TRANSMISSION PROJECTS
10 Q.Please describe the Aeolus-to-Anticline line.
11 A.The proposed Aeolus-to-Anticline line is a
12 single-circuit 500 kV line that will begin at the
13 proposed Aeolus substation,which will be located
14 approximately 11 miles northwest of Medicine Bow,
15 Wyoming.From the Aeolus substation,the transmission
16 line will run west across the Medicine Bow River past the
17 Hanna Draw.The line will then continue southwesterly to
18 Walcott Junction and then west across the Platte River
19 and south of Sinclair and Rawlins,where it will then
20 largely follow an existing 230 kV transmission line to
21 the proposed Anticline substation.
22 From the proposed Anticline substation,the
23 Company will construct a 345 kV transmission line that
24 will extend north for approximately five miles and
25 terminate into an expansion of the existing Jim Bridger
814 Vail,Di -5
Rocky Mountain Power
1 generating plant substation.
2 The Aeolus-to-Anticline line will be located in
3 Sweetwater and Carbon Counties and will primarily cross
4 open rangeland.Approximately 49 percent of the land
5 crossed is federally owned,seven percent state owned,
6 and nearly 44 percent privately owned.
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815 Vail,Di -5a
Rocky Mountain Power
1 Attached as Exhibit No.4 is a map showing the
2 proposed route for the Aeolus-to-Anticline line,along
3 with the other facilities included in the Transmission
4 Projects.
5 Q.What types of towers and conductors will be
6 used to construct the Aeolus-to-Anticline line?
7 A.The Aeolus-to-Anticline line segment will be
8 constructed using approximately 522 lattice steel towers
9 with heights about 115 to 160 feet.The steel towers will
10 have a "flat"configuration with each phase being
11 parallel to each other in a horizontal arrangement.
12 Attached to my testimony as Exhibit No.5 is a sample
13 drawing of proposed 500 kV tower designs.
14 The conductor for the Aeolus-to-Anticline line
15 will be triple bundled 1272 kcmil 45/7 Aluminum Conductor
16 Steel Reinforced ("ACSR")"Bittern"per phase.Each
17 conductor in the phase bundle will have a diameter of
18 1.345 inches,with three phases,comprised of three
19 conductors each,for a total of nine conductors in the
20 circuit.
21 The 345 kV Anticline-to-Jim Bridger line
22 segment will use 25 to 30 of either of the following
23 types of structures:(1)tubular steel H-frames;or (2)
24 poles with heights from about 110 to 150 feet.Attached
25 to my testimony as Exhibit No.6 is a sample drawing of
816 Vail,Di -6
Rocky Mountain Power
1 proposed 345 kV tower designs.The conductor for this
2 segment will also be triple bundled 1272 kcmil 45/7 ACSR
3 Bittern per phase.The steel poles will have two arms on
4 one side,with one arm on the other side to carry one
5 phase per arm.
6 In addition,each of the transmission line
7 segments will also carry two overhead ground wires.One
8 of the wires will be galvanized steel while the other
9 will be Optical Ground Wire ("OPGW")to facilitate
10 communications.Each wire will have a diameter of
11 approximately 0.5 inches.
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817 Vail,Di -6a
Rocky Mountain Power
1 Q.Please describe the proposed new Aeolus
2 substation.
3 A.The new Aeolus 500/230 kV substation will be
4 located approximately 11 miles northwest of Medicine Bow,
5 Wyoming,and will be sited on a Company-owned parcel of
6 land (Township 24 North,Range 80 West,Section 35)and
7 occupy approximately 100 acres.The substation will
8 include security fencing and an improved access road from
9 U.S.Highway 30.The substation will be constructed using
10 conventional air insulated bus and equipment and connect
11 to existing Shirley Basin and Freezeout substations via
12 the connection of an existing 230 kV transmission line
13 into the new Aeolus site (discussed in more detail
14 below).Attached to my testimony as Exhibit No.7 are
15 the preliminary Aeolus substation one-line diagram and
16 general arrangement drawings.
17 Construction of the Aeolus substation will
18 require the following:
19 o Construction of a 230 kV yard,including all
work to support the installation of 230 kV
20 breaker bays for termination of the existingFreezeout-to-Shirley Basin 230 kV transmission
21 line and to support the low side of the 500/230
kV transformer;
22
o Installation of a 230 kV shunt reactor;
23
o Completion of all site development,civil work,
24 bus work,protection and controls,security and
communications,and construction of a control
25 building;
818 Vail,Di -7
Rocky Mountain Power
1 o Construction of a 500 kV yard including all
work to support the termination of one 500 kV
2 transmission line to Anticline substation,including two 500 kV breaker bays to support
3 termination of the 500 kV line and connection
to the high side of a 500/230 kV transformer;
4
o Installation of three single phase 500/230 kV
5 transformer units with one additional spare
unit;
6
o Installation of one 500 kV shunt capacitor,
7 three single phase line reactors and one 500 kV
neutral reactor;
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819 Vail,Di -7a
Rocky Mountain Power
1 o Construction of a replacement access bridge
over the Medicine Bow River and associated
2 upgrades to an existing unpaved county road
from U.S.Highway 30 to the substation
3 location.The bridge will be constructed toWyomingDepartmentofTransportationHS-20
4 ("Highway Semi-trailer")specifications.Upon
completion,the bridge will become the property
5 and responsibility of Carbon County;
6 o Completion of all site development,civil work,
bus work,protection and controls,security,
7 communications,and construction of a controlbuildingincludingsiteemergencypower;and
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o Implementation of a new generation tripping
9 remedial action scheme,which would tripgenerationintheFooteCreek/Aeolus area in
10 the event the Aeolus-to-Jim Bridger lines (ortransformers)trip during high transfers on the
11 Aeolus West transmission path.Initial
technical studies indicate tripping up to
12 approximately 660 MW of generation at the
following wind farms during high-transfer
13 conditions:
14 o Foote Creek:108 MW
15 o Carbon County 1 (Q706):250 MW
16 o High Plains/McFadden Ridge 1:245 MW
17 o Seven Mile I and II:53 MW.
18 o Specific remedial action scheme arming levels
for lower flow conditions will need to be
19 determined via follow-on technical studies.
20 In addition,the Aeolus substation will be
21 designed to facilitate future expansion of the site for
22 additional resources.
23 Q.Please describe the proposed new Anticline
24 substation.
25 A.The new Anticline 500/345 kV substation will be
820 Vail,Di -8
Rocky Mountain Power
1 located approximately three miles northeast of Point of
2 Rocks,Wyoming and will be sited on a Company-owned
3 parcel of land (T20N,R100W,Sec.13)and occupy
4 approximately 140 acres.The new substation will include
5 security fencing and an improved access road and will be
6 constructed using conventional air insulated bus and
7 equipment.The Anticline substation will connect to the
8 existing Jim Bridger generating plant substation via a
9 new 345 kV transmission line (discussed above)and can be
10 expanded to accommodate
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821 Vail,Di -8a
Rocky Mountain Power
1 future 500 kV transmission lines.Attached to my
2 testimony as Exhibit No.8 are the preliminary Anticline
3 substation one-line diagram and general arrangement
4 drawings.
5 Construction of the Anticline substation will
6 require the following:
7 o Construction of the new 500 kV substation yardincludingallworktosupportthetermination
8 of one 500 kV transmission line to the Aeolus
substation;
9
o Construction of two 500 kV breaker bays to
10 support termination of the 500 kV line and
connection to the high side of a 500/345 kV
11 transformer;
12 o Installation of three single phase 500/345 kV
transformer units with one additional spare
13 unit;
14 o Installation of one 500 kV shunt capacitor,
three single phase line reactors and one 500 kV
15 neutral reactor;
16 o Construction of a 345 kV yard which includes a
ring bus and 345 kV breakers to facilitate 345
17 kV line termination to Jim Bridger and future
installation of phase shifting transformers;
18 and
19 o Completion of all site development,civil work,
bus work,protection and controls,security and
20 communications,and construction of a control
building including site emergency power.
21
22 Q.Please describe the modifications to the Jim
23 Bridger generating plant substation that will be
24 necessary to interconnect the new Anticline substation to
25 the Jim Bridger generating plant substation.
822 Vail,Di -9
Rocky Mountain Power
1 A.The new Anticline substation will interconnect
2 to the Jim Bridger substation via a new,five-mile,345
3 kV transmission line (discussed above).The Jim Bridger
4 substation is located west of,and immediately adjacent
5 to,the Jim Bridger power plant.To accommodate the
6 interconnection of the Anticline substation,the Jim
7 Bridger substation will be expanded to include an
8 additional transmission line termination bay.Attached to
9 my testimony as Confidential Exhibit No.9 are the
10 preliminary Jim Bridger
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823 Vail,Di -9a
Rocky Mountain Power
1 substation one-line diagram and general arrangement
2 drawings related to the construction at the Jim Bridger
3 substation,which will include the following:
4 o Expanding the existing 345 kV substation yard
to add one new 345 kV line termination bay to
5 the existing yard;
6 o Relocating the existing shunt capacitor to
facilitate connection of a new line termination
7 bay to the existing 345 kV bus;
8 o Completion of all site development,civil work,
bus work,protection and controls,security and
9 communications;
10 o Modification to the Jim Bridger remedial action
scheme will be needed due to the re-dispatch of
11 Jim Bridger generation necessary to accommodate
new wind generation in eastern Wyoming,while
12 maintaining the 2,400 MW rating on the Bridger
West transmission path;and
13
o Modification of existing protection and control
14 systems within the existing 345 kV yard to
enable safe operation of the expanded facility.
15
16 In addition,the existing Latham substation,
17 located approximately four miles south of Interstate Exit
18 187,adjacent to Wyoming Highway 789,will be expanded to
19 include a voltage control device.The type and design of
20 the device will be defined pending completion of future
21 technical studies.The Company plans to install the
22 device within the constraints of the currently-leased
23 property boundaries.Attached to my testimony as
24 Confidential Exhibit No.10 are the existing Latham
25 substation one-line diagram and general arrangement
824 Vail,Di -10
Rocky Mountain Power
1 drawings.The substations will be modified once finalO2designdetailsofthevoltagecontroldeviceare
3 determined.
4 Q.Please describe the 230 kV transmission line
5 from the Shirley Basin substation to the Standpipe
6 substation.
7 A.The proposed 230 kV transmission line projects
8 will begin at the Company's existing Shirley Basin
9 substation,located approximately 1.5 miles east of the
10 south junction of state highways 77 and 487.A new 230 kV
11 line will parallel an existing 230 kV
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825 Vail,Di -10a
Rocky Mountain Power
1 transmission line running southwesterly along the western
2 side of the Freezeout Mountains and will connect into the
3 Aeolus substation.South of Aeolus substation to
4 Standpipe substation,via the Freezeout substation,the
5 230 kV project is a reconstruction of the existing 230 kV
6 line.The line continues south out of the Aeolus
7 substation across the Medicine Bow River and connects
8 into the Company's existing Freezeout substation located
9 between the Pine and South Pine Draws.The 230 kV line
10 then continues in a southwesterly direction to the
11 Company's existing Standpipe substation,which is located
12 approximately two-and-one-half miles southeast of Hanna,
13 Wyoming.
14 All of the 230 kV segments are located in
15 Carbon County and the new line will cross areas of
16 mountainous terrain reaching elevations of approximately
17 7,500 feet.Attached to my testimony as Confidential
18 Exhibit No.11 are the existing Shirley Basin,Freezeout
19 and Standpipe substations one-line diagrams and general
20 arrangement drawings.These substations may be modified
21 to accommodate the 230 kV transmission line project.
22 Final drawings will be provided when they become
23 available.
24 Q.What types of towers and conductors will be
25 used for the 230 kV transmission line?
826 Vail,Di -11
Rocky Mountain Power
1 A.The single circuit 230 kV transmission line
2 will be rebuilt using either wood or steel H-frame
3 structures with heights ranging from 90 to 120 feet.
4 Attached to my testimony as Exhibit No.12 is a sample
5 drawing of proposed 230 kV tower designs.The conductor
6 for the section north of the Aeolus substation to the
7 Shirley Basin substation will be double bundled 1575
8 kcmil ACSR/TW "Potomac"per phase.The conductor for
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827 Vail,Di -lla
Rocky Mountain Power
-s 1 the section south of the Aeolus substation will be double
2 bundled 1272 kcmil 45/7 ACSR Bittern per phase.
3 Q.Please describe the estimated total cost of the
4 Transmission Projects.
5 A.The Aeolus-to-Bridger/Anticline Line is
6 estimated to cost (redacted),as summarized in
7 Confidential Table 1 below:
8
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Confidential Table 1
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20 The entire cost of the Aeolus-to-Bridger/Anticline Line
21 will be paid by the Company without contribution from any
22 third-party customer projects.
23 The 230 kV Network Upgrades are estimated to cost
24 (redacted)as summarized in Confidential Table 2 below:
25 /
828 Vail,Di -12
Rocky Mountain Power
1
2
Confidential Table 2
3
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11 The Company expects that the costs of the 230 kV
12 Network Upgrades will be re-assessed and assigned to the
13 wind resource facilities selected via the Company's 2017R
14 request for proposals ("RFP")process under their
15 respective interconnection
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829 Vail,Di -12aRockyMountainPower
1 agreements.The 230 kV Network Upgrades and are necessary
2 to support the interconnection of up to 1,270 MW of new
3 or repowered wind generation in eastern Wyoming.
4 Q.When does the Company expect to complete the
5 construction of the Transmission Projects?
6 A.The Transmission Projects are being developed
7 together with the Wind Projects,which will generate
8 zero-fuel-cost energy and PTCs that make the codependent
9 projects economic.To obtain the full benefits of the
10 PTCs,the Transmission Projects and the Wind Projects
11 must be in service no later than December 31,2020.
12 Q.Why must the Company receive a CPCN now for a
13 project that is not scheduled for completion until
14 December 2020?
15 A.The Company does not currently have all of the
16 necessary rights-of-way to construct the Transmission
17 Projects.To achieve an in-service date before the end of
18 2020,the Company must acquire the necessary
19 rights-of-way by March 31,2019.The Company must obtain
20 a CPCN from the Commission under the schedule it has
21 proposed in the Application to meet this schedule.A
22 delay in approval of the CPCN jeopardizes the December
23 31,2020 deadline and risks the loss of PTC
24 benefits-which will mean that neither the Transmission
25 Projects nor the Wind Projects will move forward.A
830 Vail,Di -13
Rocky Mountain Power
1 project critical path schedule is attached to my
2 testimony as Exhibit No.13.
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831 Vail,Di -13a
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1 BENEFITS OF THE TRANSMISSION PROJECTS
2 Q.How will the Transmission Projects benefit
3 customers and improve system performance?
4 A.The Transmission Projects will:(1)relieve
5 congestion and increase transmission capacity across
6 Wyoming,allowing interconnection of new generation
7 resources and greater flexibility in managing existing
8 resources;(2)provide critical voltage support to the
9 transmission system;(3)improve system reliability;and
10 (4)reduce energy and capacity losses.Because the cost
11 of the Transmission Projects are substantially offset by
12 the generation of zero-fuel-cost energy and PTCs from the
13 Wind Projects,customers receive substantial benefits as
14 quantified by Mr.Link.
15 Q.How will the Transmission Projects increase
16 transmission capacity in southeastern Wyoming?
17 A.Currently,the Company's transmission system in
18 southeastern Wyoming is operating at capacity,which
19 limits transfer of existing resources from eastern
20 Wyoming.Also,due to limited fault current in the
21 southeastern portion of the transmission system,which
22 indicates a weak grid,interconnection of additional
23 resources in this prime wind region is precluded to
24 maintain grid stability.The Transmission Projects will
25 not only increase the transfer capability from east to
832 Vail,Di -14
Rocky Mountain Power
1 west by 750 MW,but will also improve the fault current
2 providing "stiffness"to the grid.This will allow
3 additional wind facilities in and around the proposed
4 Aeolus substation,which is not possible today.
5 When the Transmission Projects are complete,
6 the Company estimates that it can interconnect up to
7 approximately 1,270 MW of additional wind facilities east
8 of the Bridger/Anticline substation.The assumed level of
9 new wind resources is higher
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833 Vail,Di -14a
Rocky Mountain Power
1 than the assumed incremental transfer capability of the
2 transmission facilities because wind resources do not
3 generate at their full capability in all hours of the
4 year.At times when wind resources in southeastern
5 Wyoming are operating near full output,other resources
6 in the area can be re-dispatched to accommodate
7 PTC-producing wind generation.Installing more variable
8 resources in an area relative to total transmission
9 capacity allows for more efficient use of the
10 transmission system and the ability to use the most
11 cost-effective resources to meet customer demand.
12 The increased capacity also provides improved
13 access to existing generation resources,and increased
14 opportunities to move incremental energy from Wyoming to
15 offset higher-priced generation in the PacifiCorp system
16 or other energy imbalance market participants'systems,
17 as noted by Mr.Link.
18 Q.Is the increased capacity from the Transmission
19 Projects consistent with the Company's obligation to
20 provide transmission service under its OATT?
21 A.Yes.The Company's OATT,approved by the
22 Federal Energy Regulatory Commission ("FERC"),details
23 the Company's requirements and obligations to provide
24 transmission service.Section 28.2 defines the Company's
25 responsibilities,which include the requirement to "plan,
834 Vail,Di -15
Rocky Mountain Power
1 construct,operate and maintain the system in accordance
2 with good utility practice."Section 28.3 states the
3 requirement for the Company to provide "firm service over
4 the system so that designated resources can be delivered
5 to designated loads."The Company is required to provide
6 adequate and non-discriminatory service to all network
7 customers.Although the Transmission Projects are not
8 specifically mandated by the Company's obligations under
9 its OATT,the Transmission Projects will allow the
10 Company to more efficiently meet current and
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835 Vail,Di -15a
Rocky Mountain Power
1 forecasted customer energy demand by relieving the
2 existing transmission congestion in southeastern Wyoming.
3 Q.Will the up-front transmission costs of the
4 Transmission Projects be recovered in PacifiCorp's
5 transmission rates?
6 A.Yes,the Transmission Projects are considered
7 network transmission assets under PacifiCorp's OATT and
8 provide a number of benefits to the transmission grid,as
9 discussed earlier in my testimony.Because the
10 Transmission Projects are integrated into PacifiCorp's
11 transmission network and provide benefits to that
12 network,such as congestion relief,increased
13 transmission capacity and improved system reliability,
14 FERC precedent for ratemaking supports rolling the costs
15 of these assets into PacifiCorp's transmission rates.
16 Q.How will the costs of the Transmission Projects
17 flow into PacifiCorp's transmission rates,and who will
18 pay these rates?
19 A.All transmission rates charged to wholesale
20 transmission customers must be approved by FERC.
21 PacifiCorp's transmission rate structure is a FERC-
22 approved formula that has been in place since 2012.A
23 formula rate is a method of calculating a rate,but is
24 not the rate itself;the actual transmission rate that is
25 charged to wholesale transmission customers is produced
836 Vail,Di -16
Rocky Mountain Power
1 annually by updating FERC-approved inputs to the formula
2 rate.Formula rates rely on annual updates using inputs
3 from the detailed,publicly available,and audited FERC
4 Form No.1,along with other Company data.The annual
5 update process includes transmission capital additions
6 such as the Transmission Projects.
7 PacifiCorp's merchant function is the largest
8 transmission customer of PacifiCorp's transmission
9 system,but there are third-party transmission customers
10 as
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837 Vail,Di -16a
Rocky Mountain Power
1 well.While all transmission customers pay OATT
2 transmission rates,third-party transmission customers
3 generate revenue credits that offset the cost of
4 PacifiCorp's transmission revenue requirement in retail
5 rates,as discussed in Mr.Link's testimony.
6 Q.What are the benefits resulting from the
7 critical voltage support that will be provided by the
8 Transmission Projects?
9 A.Under certain operating conditions,voltage
10 control issues have limited the ability to add additional
11 resources,particularly wind facilities,in southeastern
12 Wyoming.The Transmission Projects will solve the voltage
13 control issues and allow up to 1270 MW of additional wind
14 generation to be interconnected into the transmission
15 system.
16 Q.How will the Transmission Projects improve
17 system reliability?
18 A.The transmission grid can be affected in its
19 entirety by what happens on an individual transmission
20 line or path.For example,the transmission system
21 between eastern and central Wyoming is comprised of
22 several individual transmission lines or line segments.
23 Attached to my testimony as Exhibit No.14 is a diagram
24 of the existing Wyoming transmission system.A single
25 outage on any of the individual lines or line segments
838 Vail,Di -17
Rocky Mountain Power
1 due to storm,fire,or other interference can and does
2 cause significant reductions in transmission capacity and
3 can negatively impact the Company's ability to serve
4 customers.Line outages require the Company to
5 significantly curtail generation resources to stabilize
6 system voltages and require less efficient re-dispatch of
7 system resources to meet network load requirements.
8 In the event of a line outage,the redundancy
9 provided by the Transmission Projects will allow the
10 Company to continue to meet native load service
11 obligations and continue to meet other contractual
12 obligations to third parties.Strengthening this
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839 Vail,Di -17a
Rocky Mountain Power
1 path and increasing system redundancy with the new
2 Transmission Projects will benefit all customers by
3 reducing the risk of outages and inefficient dispatch
4 resulting from those outages.
5 In addition,the Transmission Projects will
6 improve the Company's ability to perform required
7 maintenance without significant operational impacts to
8 the system,and will reduce impacts to customers during
9 planned and forced system outages.Transmission line and
10 substation maintenance windows are currently limited
11 because the system is highly utilized.By relieving
12 congestion and providing additional transmission paths,
13 the Transmission Projects will allow greater flexibility
14 for the Company.
15 Q.Can you provide an example where the
16 Transmission Projects will mitigate the impact of an
17 outage on the 230 kV transmission system?
18 A.Yes.The following are examples of potential
19 outages that will be mitigated by the Transmission
20 Projects:
21 o For an outage of the Latham-to-Point of Rocks
230 kV line,the Project eliminates the
22 overload on the Dave Johnston to Amasa 230 kV
line;
23
o For an outage of the Mustang-to-Spence 230 kV
24 line,the Project eliminates the overload on
230 kV lines west of Platte;
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Rocky Mountain Power
1 o For an outage of the Riverton-to-Wyopo 230 kV
line,the Project eliminates overloads on 230
2 kV lines west of Platte;
3 o For an outage of the Dave Johnston-to-Amasa 230
kV line,the Project eliminates the overload on
4 the 230 kV lines west of Platte;and
5 o For an outage of the Platte-to-Standpipe 230 kV
line,the Project eliminates the need to trip
6 approximately 130 MW of generation at Foote
Creek.
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1 Q.Will the Transmission Projects also enhance the
2 Company's ability to meet the reliability standards
3 applicable to its transmission system?
4 A.Yes.Although the Company currently meets or
5 exceeds the applicable reliability standards and
6 criteria,the addition of the Transmission Projects will
7 allow the Company to more efficiently meet or exceed
8 those standards and criteria.
9 Q.Please describe the applicable reliability
10 standards.
11 A.The Company plans,designs,and operates its
12 transmission system to meet or exceed NERC Standards for
13 Bulk Electric Systems ("BES")and WECC Regional standards
14 and criteria.The NERC standards are set forth in 18 CFR
15 Part 40 (Mandatory Reliability Standards for Bulk-Power
16 Systems).The WECC standards and criteria are deemed
17 necessary for the Western Interconnection to meet or
18 exceed NERC standards.The Company must currently comply
19 with more than 100 approved NERC standards.These
20 standards dictate the minimum levels of transmission
21 system reliability,redundancy,and performance required
22 for transmission facilities.
23 The most relevant standard here is NERC's
24 Transmission Planning Performance Requirements set forth
25 in NERC TPL-001-4,which establishes transmission system
842 Vail,Di -19
Rocky Mountain Power
1 planning performance requirements intended to ensure that
2 the BES will operate reliably over a broad spectrum of
3 system conditions and following a wide range of probable
4 contingencies.
5 Q.How do NERC's and WECC's standards and criteria
6 influence the need for the Transmission Projects?
7 A.The mandatory standards,particularly,NERC's
8 TPL-001-4 standard,require the Company to have a
9 forward-looking transmission plan to reliably serve
10 current and
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843 Vail,Di -19a
Rocky Mountain Power
1 anticipated customer demands under all expected operating
2 conditions,including normal system operations (all
3 system elements in service)and during system
4 contingencies (where elements of the transmission system
5 are out of service),both planned or otherwise.
6 The Company performs annual reliability
7 assessments to determine whether its transmission system
8 complies with minimum mandatory system performance
9 standards,which require that during loss of any single
10 transmission system element ("N-1 single contingencies")
11 that firm service is maintained,no system overloads
12 exist,and there is no loss of customer demand.
13 The Aeolus-to-Anticline line is sub-segment D.2
14 of Gateway West,which,as part of Energy Gateway,has
15 been included in the Company's annual TPL-001-4
16 assessment as part of its short-and long-term plans to
17 dependably meet NERC and WECC reliability requirements.
18 The Transmission Projects'new transmission segments are
19 particularly effective in increasing system reliability
20 under the various multiple contingency categories of the
21 TPL-001-4 standard.
22 Q.Can you explain the TPL-001-4 standard?
23 A.Yes.The NERC Standard TPL-001-4 requires the
24 Company to plan for a scenario with outages of multiple
25 transmission elements.The Company must plan how it will
844 Vail,Di -20
Rocky Mountain Power
1 adjust the transmission system after the first outage and
2 then respond to the second outage (this type of scenario
3 is referred to as an N-1-1 condition).The Aeolus-to-
4 Anticline line will significantly help under these types
5 of N-1-1 conditions.For example,without the Aeolus-to-
6 Anticline line,the N-1-1 outage of Riverton to Wyopo 230
7 kV line followed with an outage of Spence to Mustang 230
8 kV line would require curtailment of the
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845 Vail,Di -20a
Rocky Mountain Power
1 TOT 4A path by approximately 500 MW.But with the
2 addition of the Aeolus-to-Anticline line,this
3 curtailment would not be required.The study was
4 performed with TOT 4A flows at 1,030 MW in the original
5 case.The addition of the Aeolus-to-Anticline line
6 prevents thermal overload on the 230 kV transmission
7 system west of Platte.
8 Q.What are the WECC path rating studies?
9 A.The WECC path rating studies follow a
10 three-phase process established by the Planning
11 Coordination Committee ("PCC")that utilizes peer review
12 study groups,made up of the project sponsor and other
13 interested WECC members,to establish a path rating for a
14 given transmission path or set of transmission paths,
15 which may exhibit simultaneous interactions with each
16 other.Path rating studies utilize a transmission model
17 of the Western Interconnection and will take multiple
18 months to evaluate the performance of the new
19 transmission facilities and to demonstrate that the
20 proposed transmission project will have no negative
21 impacts on previously established transmission path
22 ratings.The path ratings that are established following
23 this process represent the "Maximum Path Transfer
24 Capability"of a transmission path.
25 Once projects complete the second phase of the
846 Vail,Di -21
Rocky Mountain Power
1 path rating studies,they are granted an "Accepted"
2 rating and placed in Phase 3 (construction phase)status.
3 After the Accepted status is granted,other projects
4 currently going through the WECC path rating process must
5 recognize the project in their studies and cannot
6 negatively impact the path rating for the project.
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1 Q.Has the Aeolus-to-Anticline line been includedO2inWECCpathratingstudies?
3 A.Yes.The Aeolus-to-Anticline line has undergone
4 WECC's's Three Phase Ratings Process,and has been
5 approved by WECC for Phase 3 Construction Phase status as
6 part of the overall Energy Gateway project.The Aeolus
7 West transmission path and three other Gateway West
8 transmission paths (TOT 4A,Bridger/Anticline West,and
9 Path C)have completed the Three Phase Rating Process and
10 were granted Phase 3 status on January 5,2011.This WECC
11 approval is necessary because it allows the Company to
12 interconnect the Aeolus-to-Anticline line to the wider
13 transmission system in the area and to reliably operate
14 the project at its approved ratings.This line will
15 strengthen the Company's transmission capacity and
16 flexibility,especially when complemented with other
17 Energy Gateway projects,specifically
18 Anticline-to-Populus,Aeolus-to-Clover and
19 Oquirrh-to-Terminal.The Aeolus-to-Anticline line is
20 regarded as a necessary interconnection point to support
21 the long-term transmission expansion planning established
22 in the WECC Region plans and in the most recent Northern
23 Tier Transmission Group sub-regional plan.The
24 construction of this project,as an integral component of
25 the larger Energy Gateway project,provides options to
848 Vail,Di -22
Rocky Mountain Power
1 access additional resources.
2 Q What are the impacts to the system and the
3 Company if the Transmission Projects are not completed?
4 A.If the projects are not completed,the existing
5 congestion will remain and the Company's ability to
6 deliver resources to load will remain constrained.
7 Because the Company currently meets all applicable system
8 reliability and performance criteria,the Transmission
9 Projects are not strictly required to satisfy those
10 standards.Rather,the
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849 Vail,Di -22a
Rocky Mountain Power
1 Transmission Projects have long been identified as an
2 important addition to Wyoming's transmission system,and
3 the zero-fuel-cost energy and PTCs generated by the
4 incremental wind resources provide a time-limited
5 opportunity to build the projects now and deliver
6 significant savings to customers over the projects'life.
7 Q.How will the Transmission Projects reduce
8 energy and capacity losses?
9 A.Reduced energy and capacity losses on the
10 transmission system have the potential to provide
11 significant cost savings over time.Generally,the
12 addition of a new transmission path in parallel with
13 existing lines,like the Transmission Projects,will
14 reduce the energy and capacity losses by reducing the
15 impedance of the transmission system.Reduced line losses
16 mean more efficient delivery of energy and capacity at
17 reduced costs.
18 Q.Did the Company consider alternatives to the
19 Transmission Projects?
20 A.Yes.While long-term alternatives to
21 constructing a new transmission line are limited,the
22 Company did consider other approaches,but none were as
23 cost-effective.As described more fully in the testimony
24 of Mr.Link,the Transmission Projects and Wind Projects
25 were included in the Company's 2017 Integrated Resource
850 Vail,Di -23
Rocky Mountain Power
1 Plan,where they were analyzed in comparison to
2 alternatives.The resource portfolios that included the
3 Transmission Projects and Wind Projects were consistently
4 least cost,least risk.
5 Q.Has the Company considered any other
6 alternatives to the Transmission Projects?
7 A.The Company also considered the ability to
8 obtain additional transmission capacity by upgrading the
9 existing transmission system or implementing alternative
10 transmission technologies.Since 2013 the Company has
11 completed several important projects to enhance the
12 transmission system in southeast Wyoming,including the
13 dynamic line
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851 Vail,Di -23aRockyMountainPower
1 rating of the Miners (Standpipe)-Platte 230 kV line
2 (2013),Southern Wyoming Voltage Control Scheme,which
3 coordinated wind generation reactive output to stabilize
4 local area voltages (2015),and construction of the
5 Standpipe substation and (60 MVAr)synchronous condenser
6 for voltage control (2016).These projects allowed the
7 Company to delay the Transmission Projects until 2020,
8 but are not a long-term substitute for the Transmission
9 Projects.
10 REQUIREMENTS OF RP 112
11 Q.Please summarize how the Company's Application
12 meets the requirements for a CPCN application.
13 A.RP 112 describes what must be included in an
14 application for a CPCN.I have incorporated exhibits to
15 my testimony that include the required information for
16 the Transmission Projects.
17 Q.What is required by RP 112(1)?
18 A.This section of the rule requires a statement
19 or prepared testimony and exhibits explaining why the
20 Transmission Projects are in the public convenience and
21 necessity.The Company's testimony and exhibits as a
22 whole address this requirement.
23 Q.Have you provided the description of the
24 Transmission Projects required by RP 112(2)?
25 A.Yes.In addition to the description included in
852 Vail,Di -24
Rocky Mountain Power
1 the introductory sections of my testimony,Exhibits Nos.
2 5,6,7,8,12 and Confidential Exhibits Nos.9,10 and
3 11 provide engineering specifications,drawings,and
4 other pertinent technical information for the
5 Transmission Projects.
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853 Vail,Di -24a
Rocky Mountain Power
1 Q.Have you provided a map of the Transmission
2 Projects required by RP 112(3)?
3 A.Yes.The Transmission Projects will be sited
4 entirely in Wyoming's Carbon and Sweetwater counties and
5 the terrain is primarily open rangeland.The map attached
6 as Exhibit No.4 describes the proposed route for the
7 transmission lines and the proposed locations for the
8 associated substations.Cadastral surveying (which is a
9 field survey that establishes or re-establishes legal
10 property boundaries)for all transmission lines and
11 associated access roads is in progress,so metes and
12 bounds descriptions are not available at this time.The
13 Company will provide the results of the surveys once they
14 are complete.The attached Confidential Exhibit No.15
15 provides the Transmission Projects'sections on federal
16 lands and the Transmission Projects'sections on private
17 and state lands.
18 Q.Have you also prepared a geological report of
19 the proposed sites of the Transmission Projects?
20 A.Yes.As part of the federal permitting process
21 for the Energy Gateway project,the Company conducted a
22 two-year geotechnical exploration and geologic hazards
23 assessment.For the Aeolus-to-Bridger/Anticline Line,the
24 geotechnical exploration program consisted of advancing
25 44 borings,collection of soil samples for laboratory
854 Vail,Di -25
Rocky Mountain Power
1 testing,lab testing and determination of soil
2 properties,and reporting for use in the foundation
3 design.The Company intends to advance an additional 44
4 borings to further inform the foundation design.During
5 the same period,the Company conducted surficial geology
6 and geologic hazard reconnaissance.Recommendations
7 regarding noted geologic hazards were published in
8 reports for all segments of the Aeolus-to-Bridger/
9 Anticline Line.The geological reports are included in
10 Exhibit No.16.The
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855 Vail,Di -25a
Rocky Mountain Power
1 work is also generally applicable to the balance of the
2 Transmission Projects and will be validated as such.
3 The geotechnical engineering studies concluded
4 that all tower sites were suitable for drilled pier
5 foundations as planned,as long as the recommended values
6 for soil engineering properties are used in the design
7 and consideration is given to potential excavation
8 difficulties during construction.
9 A geotechnical study consistent in scope and
10 technical approach to that described above and as
11 contained within Exhibit No.16 will be performed for the
12 230 kV Network Upgrades.
13 Shallow groundwater is not likely to pose a
14 significant constraint on the Transmission Projects,but
15 could complicate foundation drilling and construction.
16 Areas where annual or seasonal groundwater depths are
17 less than 10 feet below the ground surface are considered
18 high risk.Geologic hazard reconnaissance confirms high
19 ground water in only few isolated locations.
20 Operating mineral deposits are provided in
21 Exhibit No.17 and a topographical map showing the
22 substation locations and right-of way overlay is included
23 in Exhibit No.18.
24 Q.RP 112(4)requires information on how the
25 Transmission Projects will be financed.Where is that
856 Vail,Di -26
Rocky Mountain Power
1 information in the Company's Application?
2 A.The testimony of Cindy Crane explains how the
3 Company intends to fund the investment in the
4 Transmission Projects.
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1 Q.RP 112(4)also requires information on
2 construction timelines.Can you provide these timelines
3 and additional information on the status of the
4 Transmission Projects?
5 A.Yes.To meet the December 2020 deadline,the
6 Company expects to execute contracts for the upgrades to
7 access roads and the bridge to the Aeolus substation site
8 by September 2017 and construction on those components is
9 expected to begin in May 2018 for completion by November
10 2018.
11 The Company expects to provide a limited
12 notice-to-proceed for the Aeolus-to-Anticline line and
13 230 kV transmission lines by the end of 2018,so the
14 Company can acquire the necessary rights-of-way by March
15 31,2019.The final notice-to-proceed for the
16 transmission facilities is expected to be issued by April
17 1,2019,so construction can begin.
18 The Company expects the transmission facilities
19 to become commercially operational by October 31,2020.
20 A project critical-path schedule is attached to
21 my testimony as Exhibit No.13.
22 Q.Has the Company entered into a binding contract
23 for design and construction of the Transmission Projects?
24 A.No.The Company has engaged the services of an
25 owner's engineer to provide engineering and design
858 Vail,Di -27
Rocky Mountain Power
1 services for the Transmission Projects scope of work.The
2 final designs will be performed by the engineer,
3 procurement and construction ("EPC")contractor (s)
4 selected via competitive market solicitation.
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1 Q.Are there additional technical studies that areO2necessarybeforetheTransmissionProjectsarecompleted?
3 A.Yes.While many technical studies have been
4 completed to date,a number of technical studies will
5 need to be performed to assure that the completed
6 projects will meet all national standards for
7 engineering,reliability and system operations,
8 specifically:
9 o Substation and Line Design Studies;
10 o Static VAr Compensator Design Studies;
11 o Jim Bridger -Subsynchronous Resonance ("SSR")
12 Analysis Studies and SSR Mitigation Analysis;
13 o Dynamic Voltage Control Analysis;
14 o Remedial Action Scheme (Bridger/Aeolus)
15 Studies;
16 o FAC-013-2 Assessment of Transfer Capability for
17 the Near-Term Transmission Planning Horizon
18 Studies;and
19 o System Operating Limit Studies.
20 These technical studies will be completed in
21 phases as required to support the design during the
22 engineering phase of the Transmission Projects.All
23 studies will be completed by late 2018.Near-term
24 planning and operational studies will be completed in the
25 middle of 2020,in preparation for the Transmission
860 Vail,Di -28
Rocky Mountain Power
1 Projects being placed in service by October 31,2020.O 2 Q.Please describe how the Company plans to
3 address environmental issue associated with the
4 Transmission Projects.
5 A.The Company has conducted a thorough assessment
6 of the impacts of the Transmission Projects on the
7 surrounding environment and resources.Much of this
8 assessment occurred as part of the permitting process
9 required by National Environmental Policy Act ("NEPA")
10 because portions of the Transmission Projects will be
11 sited on federal
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1 land.For the 230 kV line section between Aeolus and
2 Standpipe substations,the route was analyzed for impacts
3 as an alternative under the Gateway South project.The
4 Company and Bureau of Land Management ("BLM")are
5 currently evaluating any requirements necessary to
6 complete the impacts assessment.
7 In addition to requirements developed via the
8 NEPA process,the Company will also ensure compliance
9 with the Company Avian Protection Plan and other Company
10 Standards.
11 Q.Please describe the NEPA process.
12 A.In December 2008,the Company filed a
13 right-of-way permit application with the BLM and the U.S.
14 Forest Service,which triggered the need for BLM to
15 prepare an Environmental Impact Statement ("EIS")in
16 accordance with the requirements of NEPA.The draft EIS
17 was released for public comment on July 29,2011,and the
18 Final EIS was published on April 26,2013.The Record of
19 Decision was released on November 14,2013.
20 The BLM used the following criteria to select
21 the authorized route:
22 o Allow for reasonable construction costs
associated with the preferred route;
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o Route on public land where practical;
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25
o Avoid cultural and natural resource areas;
862 Vail,Di -29
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1 o Avoid sensitive species habitat,including bald
2
eagle nests and big game winter range;
o Follow existing corridors or linear structures;
3
o Avoid Visual Resource Management Class II
4 areas;
5 o Avoid designated areas such as National
Monuments,Wilderness Study Areas,National
6 Landscape Conservation System areas and State
and local parks;and
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1 o Avoid BLM-identified preliminary priority
sage-grouse habitat and Wyoming core habitat
2 areas.
3 The assessment that supported BLM's EIS
4 analyzed the impact of construction,ongoing operation
5 and maintenance,and decommissioning and reclamation of
6 the Aeolus-to-Bridger/Anticline Line.The assessment
7 considered the cumulative effects of the proposed
8 Transmission Projects,together with past,present,and
9 reasonably foreseeable future actions,and addressed the
10 following:
11 o Cultural resources,such as prehistoric or
historic archaeological sites,districts,
12 buildings,historic trails,roads,and
landscapes;
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o Vegetation communities,including the potential
14 impact of invasive plant species due to the
construction process;
15
o Wetlands and riparian areas;
16
o Wildlife and fish,including big game,small
17 mammals,reptiles,amphibians,migratory birds
and raptors;
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o Special status species,including those listed
19 under the federal Endangered Species Act
("ESA"),those proposed for federal listing as
20 well as candidates under the ESA,BLM,or
Forest Service Sensitive species,Forest
21 Service Management Indicator Species,and State
Heritage Program plant species of concern;
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o Soils,include clearing,grubbing,and grading
23 along the rights-of way and at additional
temporary workspaces;trenching;backfilling;
24 excavating;and construction of permanent
structures,such as transmission line
25 structures,access and service roads,
864 Vail,Di -30
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1 co-generation sites,and substations;O 2 o Paleontological resources;
3 o Water resources;
4 o Agricultural resources;
5 o Air quality;and
6 o Noise.
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1 Based on that analysis,the BLM and cooperating
2 agencies concluded that for many resources,the effects
3 of the Transmission Projects,coupled with the effects of
4 other known projects,will not be substantial.To the
5 extent that resources may be impacted,the Company has
6 proposed reasonable mitigation efforts to minimize the
7 impact.
8 Q.What impact assessment studies have been
9 performed?
10 A.The studies related to the impact assessment
11 are included in BLM's Record and Decision.The studies
12 are voluminous and can be found at following websites:
13 o The Final EIS:
14 https://eplanning.blm.gov/epl-front-office/eplanning/docset view.do?projectId=65164&
15 currentPageId=92763&documentId=78833
16 o The Final EIS Appendices:
17 https://eplanning.blm.gov/epl-front-office/eplanning/docset view.do?projectId=65164&
18 currentPageId=92763&documentId=78834
19 The mitigation plans are also included in the
20 above links,and identified in the attached Exhibit No.
21 19.
22 Q.Please describe the Company's plan of
23 development related to the Transmission Projects.
24 A.Once the Transmission Projects are in service,
25 they will not directly produce any emissions into the
866 Vail,Di -31RockyMountainPower
1 environment.The Company is preparing the plan of
2 development,which will govern the construction phase of
3 the Aeolus-to-Bridger/Anticline Line and must be approved
4 by BLM.This plan will include specific requirements to
5 ensure full compliance with all applicable regulations
6 and requirements of the right-of-way permit granted by
7 BLM for siting the Aeolus-to-Bridger/Anticline Line on
8 federal lands.The
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867 Vail,Di -31a
Rocky Mountain Power
1 plan of development will also include best practices for
2 all aspects of environmental protection.The Company
3 anticipates that,at a minimum,the plan of development
4 for the construction phase will account for fugitive dust
5 control,storm water pollution prevention,spill
6 containment and counter measures,plant/wildlife
7 restrictions,and ground disturbance reclamation.The
8 Company anticipates that the protection measures it will
9 use for the Transmission Projects as shown in Exhibit No.
10 20 will be similar to those implemented on the Company's
11 Mona-to-Oquirrh and Sigurd-to-Red Butte transmission
12 projects,adjusted to meet the specifics of this project
13 as necessary.
14 Once the Transmission Projects are in service,
15 the Company will install three primary devices to protect
16 air,water,chemical,biological,and thermal qualities:
17 o Construction of retention basins at the
substation sites to control storm water runoff,
18 to manage erosion control and waterflows acrossadjacentpropertiesaswellasatthe
19 substation sites;
20 o Storm water control along the transmission line
access routes will be managed using ditches at
21 the verge of new access roads along with water
control and diversion techniques,such as the
22 use of water bars;and
23 o At the substation sites,an oil containment
plan will be incorporated into the final design
24 such that,in the event of a leak,the contents
of any oil-filled equipment would be contained
25 within the substation site and not leach into
868 Vail,Di -32
Rocky Mountain Power
1 the underlying soils.
2 Q.Please describe the effectiveness of the three
3 protective devices you describe above and the operational
4 conditions for which the Company designed and tested the
5 devices.
6 A.The devices all represent proven technology
7 employed at numerous substation and other facilities
8 across the United States.Water-retention designs will
9 comply with all relevant codes as well as the Clean Water
10 Act requirements where applicable.The Company has
11 successfully employed all of these techniques on recent
12 transmission
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869 Vail,Di -32a
Rocky Mountain Power
1 projects including Populus-to-Terminal,Mona-to-Oquirrh,
2 and Sigurd-to-Red Butte transmission projects.
3 Q.Please describe any potential safety hazards
4 related to the Transmission Projects.
5 A.The Company requires a high standard of safety
6 performance and planning by all of its employees and
7 contractors.During the construction phase,the primary
8 safety hazards will vary somewhat by stage of the
9 project,but will generally relate to:
10 o Heavy equipment operations;
11 o Open excavations;
12 o Slips,trips and falls;
13 o Crane operations;
14 o Working at height;
15 o Working around energized facilities;and
16 o Climatic conditions.
17 The Company will require all personnel working
18 on the Transmission Projects to perform safety training
19 specific to the Transmission Projects.The safety plan
20 will require appropriate safety markings,barriers and
21 other restriction devices to prevent worker or public
22 access to potentially unsafe conditions.
23 During operations,the main safety hazard will
24 be the energized facilities.Tower structures are
25 designed to provide electrical clearances to the ground
870 Vail,Di -33RockyMountainPower
1 and structures and prevent climbing without specialistO2equipment,so that the public cannot reach the conductor.
3 All substation energized facilities are
4 constructed so that the high-voltage equipment is placed
5 with sufficient clearances from the site security fence
6 to prevent
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Rocky Mountain Power
1 accidental contact with the energized equipment.All
2 substations will include security fencing,controlled
3 access devices,security monitoring to limit and manage
4 personnel gaining access to the site.
5 Q.Please describe the status of satisfying local,
6 state,tribal,or federal governmental agency
7 requirements.
8 A.The Company has obtained a federal right-of-way
9 permit from the BLM,which covers approximately half of
10 the 140 mile-length of the Aeolus-to-Anticline line.The
11 right-of-way grant was authorized concurrently with the
12 release of the Record of Decision,discussed above.The
13 BLM's decision provides the authorizations,with
14 stipulations,necessary for the Company to begin
15 construction on federally administered lands.
16 Stipulations in the right-of-way grant require
17 additional environmental surveys to be completed in order
18 to clear construction areas before receiving the notice
19 to proceed to construct on public land.The Company is
20 currently conducting surveys for cultural,
21 paleontological,biological and potential wetland
22 resources that will need to be protected and,if
23 adversely impacted,mitigated.The BLM and the U.S.Corp
24 of Engineers will issue final notices to proceed after
25 receipt and approval of survey reports,pre-construction
872 Vail,Di -34RockyMountainPower
1 notifications,and payment of any required mitigation
2 funds determined.
3 In addition,the right-of-way grant includes
4 the requirement to comply with several additional federal
5 agency required permits and approvals,which the Company
6 is currently in the process of completing,including
7 Section 106 Consultation under the National Historic
8 Preservation Act,Section 404 Clean Water Act Permit,and
9 Resource Protection Plans required by the BLM.
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873 Vail,Di -34a
Rocky Mountain Power
1 The Company is in the process of securing all
2 relevant federal,state,and local permits for the 230 kV
3 section between the Aeolus substation and the Standpipe
4 substation.The Company anticipates that this section
5 will be subject to the same or similar conditions
6 included in the Record of Decision,released November 12,
7 2013.
8 Q.What is the current status of the necessary
9 permits from local government entities?
10 A.The Company has or will receive the required
11 consents,franchises,and permits from all the local
12 governmental entities having jurisdiction over the
13 proposed route for the Transmission Projects.These will
14 include an application to the Wyoming Department of
15 Environmental Quality and the Wyoming Industrial Siting
16 Council for the issuance of a permit.The Company will
17 also obtain a conditional use permit from Carbon County
18 and a construction permit from Sweetwater County.
19 In addition to the conditional use permit,the
20 Company is in the process of obtaining the required
21 consents and permits from the State of Wyoming,subject
22 to completion of the final design of the transmission
23 line alignment.Additionally,the Company will obtain any
24 permits and approvals required from state agencies for
25 actual construction and operation of the Transmission
874 Vail,Di -35
Rocky Mountain Power
1 Projects in the ordinary course of development.TheseO2requiredconsentsandpermitsmayinclude,but may not be
3 limited to,stream alteration permits from the Wyoming
4 Game and Fish Department,highway encroachment permits
5 from the Wyoming Department of Transportation,storm
6 water permits from the Wyoming Department of
7 Environmental Quality Water Quality Division,
8 right-of-way grants from the Wyoming State Trust Lands
9 Administration,and approvals from the State Historic
10 Preservation Office of Wyoming.
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875 Vail,Di -35a
Rocky Mountain Power
1 Based on the current routing plan,these are
2 the only permits,franchises,and consents required for
3 the Transmission Projects.Should a routing change
4 resulting from the environmental approval process require
5 any additional local consents,franchises,or permits,
6 the Company will immediately seek such approval and
7 inform the Commission.
8 Exhibit No.21 provides additional details on
9 the required permits.
10 Q.Please describe the sage grouse habitat in the
11 vicinity of the Transmission Projects.
12 A.As part of the NEPA process,the Company's
13 assessment specifically addressed the potential impact of
14 the Aeolus-to-Bridger/Anticline Line on sage grouse
15 habitat.The studies related to sage grouse are included
16 in the Final EIS issued by BLM.In addition,the
17 mitigation plan associated with sage grouse is described
18 in Exhibit No.19.
19 The Company is also in the process of
20 developing a Greater Sage Grouse Avoidance,Minimization,
21 and Mitigation Plan to demonstrate compliance with BLM
22 and state policies designed to minimize impacts to sage
23 grouse and their habitat,and support the position that a
24 listing as threatened or endangered under the ESA is not
25 needed.
876 Vail,Di -36
Rocky Mountain Power
1 Q.Under RP 112 (5),has the Company provided cost
2 estimates for the Transmission Projects?
3 A.Yes.The estimated total cost for the
4 Transmission Projects is (redacted).The individual cost
5 components of this estimate are set forth in Confidential
6 Tables 1-2 above.
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Rocky Mountain Power
1 Q.RP 112(5)also requires information on the
2 Transmission Projects'effect on the Company's revenue
3 requirement.Please explain where that information is
4 located in the Company's Application.
5 A.Mr.Larsen and Mr.Link sponsor the Company's
6 revenue requirement analysis related to the Transmission
7 Projects.
8 RECOMMENDATION AND CONCLUSIONS
9 Q.Please summarize your recommendation to the
10 Commission.
11 A.I recommend that the Commission approve the
12 Company's Application.The Transmission Projects will
13 provide substantial benefits to its customers and are
14 prudent and in the public interest.Based on this
15 conclusion,I recommend that the Commission grant the
16 Company CPCNs for the Transmission Projects.
17 Q.Does this conclude your direct testimony?
18 A.Yes.
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878 Vail,Di -37
Rocky Mountain Power
1 Q.Are you the same Rick A.Vail 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 SUMMARY OF REBUTTAL TESTIMONY
6 Q.What is the purpose of your rebuttal testimony?
7 A.I support of the Company's application for
8 certificates of public convenience and necessity
9 ("CPCNs")and for binding ratemaking treatment,I update
10 the status of several aspects of the Aeolus-to-Bridger/
11 Anticline Line and 230 kV Network Upgrades ("Transmission
12 Projects"),and show the important progress the Company
13 has made on the Transmission Projects,as well as their
14 decreasing risk.I also respond to the direct testimony
15 of Monsanto Company ("Monsanto"),PacifiCorp Idaho
16 Industrial Customers ("PIIC"),and the Staff of the
17 Public Utilities Commission of Idaho ("Staff").
18 Q.Please summarize your rebuttal testimony.
19 A.I address the following key issues for the
20 Transmission Projects:
21 o An update of the status of:
22 o Expected design and cost;
23 o Engineering,Procurement,and Construction
24 ("EPC")contracts;
25 o Required permits at the federal,state,
879 Vail,Di-Reb -1
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1 and local level;and
2 o The required power system analyses and
3 easements.
4 o The necessity of these projects to reduce
5 line losses and derates along with
6 dispatching of Company-owned resources.
7 o Mitigation of risks to minimize costs and
8 project delays due to:
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880 Vail,Di-Reb -la
Rocky Mountain Power
1 o The permitting process and the Company's
2 plan for obtaining required permits prior
3 to construction;
4 o Obtaining the required easements;and
5 o Construction delays (EPC contracts and
6 mitigation for meeting construction
7 deadlines).
8 o Relevant Open Access Transmission Tariff
9 ("OATT")and Federal Energy Regulatory
10 Commission ("FERC")precedent confirming the
11 reasonableness of the Company's assumptions
12 regarding revenues from third-party customers.
13 o The Company's need for timely CPCNs to maintain
14 project timelines.
15 TRANSMISSION PROJECTS UPDATE
16 Q.Since the initial CPCN filing,has the Company
17 maintained the project schedule and cost estimates for
18 the Transmission Projects?
19 A.Yes.The Company has made significant progress
20 in the development of the Transmission Projects since its
21 initial filing.The Company is on track to meet its
22 development schedule at or below the costs estimated in
23 its filing.
24 Q.Please provide a status update on the design of
25 the Transmission Projects.
881 Vail,Di-Reb -2
Rocky Mountain Power
1 A.Currently,both the 500 kV transmission
2 facilities and 230 kV network upgrades are in the detail
3 design phase.For the 500 kV facilities,the major effort
4 is focused on two key elements:(1)micro-siting
5 structures;and (2)structure design.
6 Micro-siting structures involves confirming the
7 precise structure locations and associated access roads
8 to accommodate features such as pipelines,fiber optic
9 cables,and other utilities,along with micro-siting to
10 avoid sensitive biological or cultural features.
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882 Vail,Di-Reb -2a
Rocky Mountain Power
1 The structure design process focuses onO2selectingthetowerandfoundationdesignthatwill be
3 used.Before filing the CPCN application,the Company
4 decided it could use a new tower design that would
5 significantly reduce the structures weight and,
6 therefore,cost as compared to the tower design used in
7 other segments of the Energy Gateway project.The Company
8 is in the process of developing and testing the revised
9 structures and expects to complete this by summer 2018,
10 in line with the overall EPC schedule.The Company is
11 currently completing the initial design phase,the first
12 prototype has begun the fabrication process,and tower
13 testing is scheduled to begin mid-first-quarter 2018.
14 Development efforts to date have confirmed the baseline
15 assumptions included in the design and cost basis of the
16 CPCN filing.
17 In addition,the Company completed a
18 geotechnical program during the summer of 2017 to further
19 aid the EPC contractors in bid preparation and reduce the
20 risk assumptions associated with the foundation design.
21 The overall 500 kV transmission design package is on
22 track to be complete by April 2018.
23 Q.What is the status of the 500 kV substation
24 design work?
25 A.The 500 kV substation design work is on
883 Vail,Di-Reb -3
Rocky Mountain Power
1 schedule.The Company has focused recent efforts on
2 thoroughly analyzing the precise location and space
3 requirements for each new substation.This has led to a
4 reduction in the initial space requirements and allowed
5 for a balanced cut and fill design to reduce the cost of
6 importing high cost fill materials.At the Jim Bridger
7 substation,design optimization efforts will facilitate
8 construction of the new line termination bay while
9 minimizing disruptions to the existing facility.The
10 substation design necessary for competitive market EPC
11 bidding is anticipated to be completed by April 2018.
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884 Vail,Di-Reb -3a
Rocky Mountain Power
1 Q.What is the status of the 230 kV facilities?O 2 A.Design work for the 230 kV transmission
3 facilities is also ongoing.The Company has selected the
4 proposed line route,after considering field surveys for
5 biological and cultural constraints,as well as
6 incorporating landowner comments.Structure design will
7 be based upon the Company's standard design steel H
8 frames.The Company will begin design work for the 230 kV
9 substations in early 2018.All design work for the 230 kV
10 facilities will be completed by the fall of 2018,to
11 allow for the competitive market procurement process to
12 support a 2019 construction period.
13 Q.Is there any change in the projected costs of
14 the Transmission Projects?
15 A.No.The cost estimates included in the original
16 filing are the same.As discussed below,the construction
17 costs will be updated as a part of the January 16,2018
18 supplemental filing.
19 Q.What is the current status of the EPC contract
20 for the 500 kV line?
21 A.The Company is currently in a competitive
22 selection process for an EPC contractor for the 500 kV
23 line.Because the 500 kV line is approximately 85 percent
24 of the total costs of the Transmission Projects,the
25 selection of the EPC contractor will be a significant
885 Vail,Di-Reb -4RockyMountainPower
1 milestone in confirming final project costs.The Company
2 will have the preliminary results of this process by its
3 supplemental testimony January 16,2018,and will include
4 resulting cost updates at that time.
5 Q.Please provide more detail on the status of the
6 EPC contracts for the Transmission Projects.
7 A.The Company has engaged with eight transmission
8 line contractors to secure Master Service Agreement Terms
9 and Conditions that will apply to the Transmission
10 Projects.
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886 Vail,Di-Reb -4a
Rocky Mountain Power
1 The contractors represent some of the leading engineering
2 and construction companies in the country.Negotiations
3 are currently ongoing to finalize these terms and
4 conditions by January 2018.
5 Concurrent with these activities,the Company
6 issued a request for detailed technical information to
7 the same contractors.This request requires contractors
8 to provide detailed project plans,resource profiles,
9 schedules and cost data.The responses will be analyzed
10 to develop a shortlist of contractors,based on a
11 combination of cost and viability of the overall project
12 approach,for a final pricing event in the summer 2018.
13 Contractor responses were received December 11,2017.The
14 data within the responses will also be used to inform the
15 analysis being performed for the Wyoming Industrial
16 Siting Permit application.The 500 kV transmission line
17 EPC contracts remain on track to be in place by October
18 2018.
19 For the 500/345 kV substation scope of work,
20 the Company is currently preparing a Terms and Conditions
21 RFP that will be issued by early February 2018 to up to
22 six qualified contractors who will be responsible for
23 full EPC services for the 500/345kV substations.This RFP
24 will also request budgetary price information.The
25 Company intends to negotiate EPC contract terms and
887 Vail,Di-Reb -5
Rocky Mountain Power
1 conditions before final pricing to expedite final
2 contract negotiations in the fall of 2018.A final price
3 bid event will be issued to all six companies in the
4 summer of 2018.
5 For the 230 kV network upgrades,the Company
6 intends to competitively source both the transmission
7 line and substation construction via existing term "Line
8 Service Agreements"the Company holds with over one dozen
9 qualified contractors capable of working in Wyoming.The
10 Company may acquire major substation equipment as a
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888 Vail,Di-Reb -5a
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1 direct purchase via a competitive RFP to qualified
2 vendors.The 230 kV work is on schedule to be procured in
3 late 2018 with main construction anticipated during 2019.
4 Q.What is the status of the permits required for
5 construction of the Transmission Projects?
6 A.The Company has been working with various
7 agencies and stakeholders to obtain the final permits
8 necessary to construct the facilities and the Company's
9 permitting activities remain on schedule.A summary of
10 key items is presented below:
11 Section 106 Consultation,National Historic
12 Preservation Act:Field surveys were completed during the
13 summer of 2017.The final class III cultural report was
14 submitted to the BLM on December 15,2017.Amendments to
15 the Programmatic Agreement have been issued to
16 stakeholders,agreement is anticipated by December 31,
17 2017.Draft outlines for the Historic Properties
18 Treatment Plan have been issued to stakeholders for
19 comments,which are due December 15,2017.Final approval
20 by the Wyoming State Historic Preservation Office of the
21 Class III report and the Historic Properties Treatment
22 Plan is expected by mid-August 2018.
23 Plan of Development:Work continues in close
24 cooperation with the BLM.Initial updated draft sections
25 have been provided to the BLM,with comments received.
889 Vail,Di-Reb -6
Rocky Mountain Power
1 The Plan of Development is on schedule to be completed by
2 May 2018 to support the EPC procurement schedule.Final
3 Plan of Development mapping will be completed by the end
4 of 2018 after inclusion of updated data from the 2018
5 field survey season.
6 Clean Water Act Sections 401:Wyoming
7 Department of Environmental Quality ("WYDEQ")Water
8 Quality Division ("WQD")has categorically-certified the
9 majority of the 2017 USACE Nationwide Permits on
10 non-Class 1 waters in Wyoming
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890 Vail,Di-Reb -6a
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1 with the expectation that applicants must comply with the
2 permit's terms and conditions,including permit specific
3 401 Certification conditions for the certification to be
4 valid.These categorically-certified permits do not
5 require an individual 401 Certification by the WDEQ/WQD.
6 The Project requires that a section 404,nationwide
7 permit 12 be obtained.This will meet the requirements
8 under the State of Wyoming for Section 401 certification.
9 Section 404/NWP 12:The Project has completed
10 all wetland delineations to determine impacts.These
11 potential impacts are being reviewed for avoidance via
12 detail design reviews.The Company will submit its
13 pre-construction notification to certify the project does
14 not exceed greater than 0.1 acre of permanent impact at
15 any one delineated wetland area.This is on schedule for
16 approval in May 2018.
17 Wyoming Industrial Siting Permit:The Company
18 held an initial meeting with the WYDEQ with respect to
19 the Industrial Siting Permit and the WYDEQ determined the
20 jurisdictional determination first recorded in 2012 is
21 still valid.The Company is preparing an application for
22 submission by the end of June 2018.The 135 day review
23 period as described in the Wyoming Administrative Rules,
24 Chapter 35,will therefore conclude with a decision due
25 by mid-November 2018.
891 Vail,Di-Reb -7
Rocky Mountain Power
1 Carbon County Conditional Use Permit ("CUP"):
2 The Company held a preliminary meeting with Carbon County
3 to discuss the requirements of the CUP application.The
4 Company is preparing the application for a May 2018
5 submission with an August 2018 decision.
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1 Q.What is the status of the technical studies
2 that are necessary to support the Transmission Projects?
3 A.The Company performed numerous technical
4 studies that show the benefits and reliability
5 improvements resulting from the Transmission Projects.As
6 with any large-scale transmission project,the Company
7 continues to perform additional technical studies.
8 Exhibit No.30 to my rebuttal testimony provides a
9 detailed outline of the studies performed so far and a
10 description of the additional studies that will be
11 performed,along with the timing of the additional
12 studies.
13 In May 2017,the Company completed detailed
14 studies,including power flow and stability analysis,
15 evaluating a wide range of operating conditions.This
16 report,the Preliminary Aeolus West Transmission Path
17 Transfer Capability Assessment,is an exhibit to
18 Monsanto's testimony.
19 Preliminary NERC FAC-013-2 Transmission
20 Assessment studies are currently underway for the
21 Aeolus-to-Bridger/Anticline line and are expected to be
22 finalized in 2020.The first set of studies to be
23 included in this process has already been completed and
24 showed an increase of transfer capability of 750 MW from
25 east to west across Wyoming.Additional studies cannot be
893 Vail,Di-Reb -8
Rocky Mountain Power
1 formally initiated until specific new southeast WyomingO2windresourceshavebeenidentified.Technical analysis
3 shows the Aeolus-to-Bridger/Anticline line increases the
4 system's stiffness factor sufficiently to interconnect up
5 to 1,270 MW of new resources.All of the technical study
6 work completed to date continues to support the initial
7 assumptions for the Transmission Projects,the facilities
8 identified,and the benefits that the Transmission
9 Projects will provide.
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894 Vail,Di-Reb -8a
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1 Q.Monsanto witness Mr.James R.Dauphinais isO2criticalofthefacttheCompanyhasyettocomplete many
3 of the studies that are necessary for the Transmission
4 Projects.(Dauphinais Direct,page 7,lines 4-5.)How do
5 you respond to this criticism?
6 A.Mr.Dauphinais'testimony specifically focused
7 on the lack of power flow,dynamic stability,stiffness
8 factor analysis,Sub-Synchronous Resonance,and voltage
9 stability studies for the Transmission Projects.All
10 necessary transmission planning studies required by WECC,
11 with the exclusion of Sub-Synchronous Resonance studies
12 and stiffness factor analysis,were completed as part of
13 the Aeolus West path rating process,which was granted
14 Phase 3 status on January 5,2011.Sub-Synchronous
15 Resonance studies were completed in November 2017.
16 Stiffness factor analysis is on-going with PacifiCorp
17 utilizing an external consultant to perform Power System
18 Computer Aided Design ("PSCAD")analysis.
19 Q.Mr.Dauphinais is also critical of the
20 Company's reliance on a 2010 Western Electricity
21 Coordinating Council ("WECC")study he claims has not
22 been updated.(Dauphinais Direct,page 8,lines 8-10.)
23 How do you respond?
24 A.At the March 30,2010,Gateway West and Gateway
25 South combined project review meeting participants
895 vail,Di-Reb -9
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1 approved the Gateway Phase 2 Study Plan and agreed that
2 incremental limitations for transmission segments added
3 between states,will be addressed via SOL (System
4 Operating Limit)studies.This same process was
5 previously followed and successfully demonstrated by BPA
6 and Avista for the West of Hatwai Expansion project.In
7 addition to SOL studies,which will be completed before
8 the project goes into service,PacifiCorp will be
9 performing FAC-013-2 Transfer
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896 Vail,Di-Reb -9a
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1 Capability Assessment studies,which it will share with
2 other utilities and WECC.These studies are scheduled for
3 completion by October 2019,more than one year in advance
4 of the project in-service date.
5 Q.Mr.Dauphinais claims the Company's October
6 2017 Aeolus West Transmission Path Transfer Capability
7 Assessment Preliminary Study Report indicates that the
8 Company requires additional facilities that have not been
9 studied yet.(Dauphinais Direct,page 9,lines 5-13.)Is
10 this correct?
11 A.No.The need for dynamic voltage support at
12 Latham Substation and three different Remedial Action
13 Schemes ("RAS")have been studied based on anticipated
14 generation projects in the PacifiCorp Large Generation
15 Interconnection ("LGI")queue;however,the final design
16 of these facilities will not be formalized until the
17 Company obtains the 2017R results in early 2018.At that
18 time,the technical studies will be finalized and
19 specific technical requirements of the proposed
20 facilities defined.The technical study timelines support
21 the proposed in-service date of the project.
22 NECESSITY OF THE TRANSMISSION PROJECTS
23 Q.Mr.Dauphinais claims the proposed Transmission
24 Projects are not needed to serve customer load.
25 (Dauphinais Direct,page 5,line 3 -page 6,line 1).Do
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1 you agree?
2 A.No.The Transmission Projects will improve
3 system performance and reliability and directly serve
4 customers.Mr.Dauphinais focuses on the fact that the
5 Transmission Projects will be built only if the Wind
6 Projects are also built.But that is because the
7 Transmission Projects are economic to construct only if
8 the Wind Projects are also built.
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898 Vail,Di-Reb -10a
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1 Q.What is the current status of the Company's
2 eastern Wyoming transmission system?
3 A.The Company's eastern Wyoming transmission
4 system is severely restrained and experiences voltage
5 support issues.While the Company is in compliance with
6 all NERC/WECC reliability standards,the stiffness factor
7 (measurement of a transmission system's ability to
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8 control voltage within acceptable limits)in eastern
9 Wyoming is such that new resources cannot be connected to
10 the system,increasing the risk of voltage swings outside
11 acceptable limits in an outage condition.This system
12 condition also limits the ability to schedule outages for
13 segments of the transmission system to perform routine
14 maintenance.
15 Q.Do these general conditions apply specifically
16 to the area where the Transmission Projects will be
17 constructed?
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18 A.Yes.The same constraints and stiffness factor
19 limits present in eastern Wyoming generally are present
20 along the TOT 4A transmission path where the Transmission
21 Projects will be constructed.Because of the constraints
22 and the stiffness factor limit,new resources cannot be
23 connected behind the path (i.e.,east of the path).
24 Further,an outage of a TOT 4A transmission element
25 results in a path derate to prevent a thermal or voltage
899 Vail,Di-Reb -11
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1 system violation and maintain system reliability.
2 Existing generation must often be curtailed to operate
3 within derated path limits,which is a curtailment in
4 firm transmission rights used to serve customer load.
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900 Vail,Di-Reb -lla
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1 Q.PIIC witness Mr.Bradley G.Mullins claims the
2 Aeolus-to-Bridger/Anticline line may not be the best
3 solution for addressing transmission needs in the West.
4 (Mullins Direct,page 15,lines 13-14).How do you
5 respond?
6 A.Mr.Mullins'claim is without merit,as he
7 provides no substantive analytic support for his
8 contention.Instead,Mr.Mullins implies the
9 Aeolus-to-Bridger/Anticline line was developed outside of
10 the inter-regional transmission planning process required
11 by FERC's Order No.1000.Contrary to Mr.Mullins'
12 implication,the Aeolus-to-Bridger/Anticline line is an
13 integral component of the inter-regional transmission
14 plan developed by the Northern Tier Transmission Group in
15 accordance with FERC's Order No.1000.In fact,the
16 current transmission system master plan for Wyoming calls
17 for the construction of facilities associated with Energy
18 Gateway,specifically Energy Gateway West and Energy
19 Gateway South.The Aeolus-to-Bridger/Anticline line is a
20 subset of the Energy Gateway West project.
21 The Company has identified these projects in
22 long-term transmission plans to:(1)relieve congestion
23 and increase transmission capacity across Wyoming,
24 allowing interconnection and integration of new
25 generation resources and enabling more efficient dispatch
901 Vail,Di-Reb -12
Rocky Mountain Power
1 of and greater flexibility in managing existing
2 resources;(2)provide critical voltage support to the
3 transmission system;(3)improve system reliability;and
4 (4)reduce energy and capacity losses.Up until now,
5 these important benefits of the Transmission Projects
6 have been cost prohibitive.As a part of the Combined
7 Projects,however,customers can economically obtain the
8 much needed support and benefits the Transmission
9 Projects will bring to the Company's existing
10 transmission network.
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902 Vail,Di-Reb -12a
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1 Q.Mr.Mullins also claims the Company should
2 invest in transmission projects that improve reliability,
3 rather than projects that are driven by economics.
4 (Mullins Direct,page 15,lines 15-17).How do you
5 respond to this claim?
6 A.Mr.Mullins does not dispute the Company's
7 extensive evidence that the Aeolus-to-Bridger/Anticline
8 line will,in fact,improve reliability and relieve
9 existing congestion on the eastern Wyoming transmission
10 system.Thus,by his own standards,the Aeolus-to-
11 Bridger/Anticline line is the type of transmission
12 investment that should be pursued.
13 Q.Will the Transmission Projects also increase
14 system efficiency?
15 A.Yes.The addition of a transmission line
16 together with an existing line(s)or path will reduce the
17 impedance of the path,resulting in overall reduced
18 energy line losses.Line losses before and after
19 construction of the Transmission Projects were compared,
20 with the difference being the line savings attributed to
21 the Transmission Projects.Reduced line losses mean more
22 efficient delivery of energy and capacity at reduced
23 costs with or without the addition of new generation
24 resources providing additional operational flexibility of
25 existing resources.
903 Vail,Di-Reb -13
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1 Q.Have there been previous investments in
2 transmission facilities along the TOT 4A path?
3 A.Yes.Since the time that the TOT 4A
4 transmission path was initially defined,a significant
5 number of transmission additions and modifications have
6 been made to the Wyoming transmission system to increase
7 the capacity on this path,including the addition of new
8 transmission lines (Spence -Mustang,1991;Dave Johnston
9 -Casper Rebuild,2010;and Sheridan-Dry Fork -Hughes/
10 Carr Draw,2010-11),adding shunt capacitors for voltage
11 support,implementation of dynamic line ratings
12 (Platte-Miners
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1 230 kV line,2013)and addition of a synchronous
2 condenser (Standpipe,2016).
3 As significant new facilities were added,WECC
4 path rating studies have been performed to increase the
5 rating of the path.The last set of path rating studies
6 were completed April 17,2013,with the granting of Phase
7 3 status by the WECC planning coordination committee
8 ("PCC").These additions and subsequent path ratings
9 support the adding resources behind the path to the point
10 today where the stiffness factor and the path rating
11 cannot support additional resources without
12 infrastructure additions.Generation interconnection
13 studies have shown that new resources cannot be reliably
14 interconnected without the addition of transmission
15 infrastructure.
16 RISK MITIGATION OF TRANSMISSION PROJECTS
17 Q.Mr.Dauphinais identifies many risks associated
18 with development of the Transmission Projects,such as
19 cost over-runs,or construction delays,that may
20 adversely impact their economics.(Dauphinais Direct,
21 page 2,line 20 -page 3,line 7).Mr.Mullins and Staff
22 witness Mr.Richard Keller also express a concern over
23 the risk of cost overruns.(Mullins Direct,page 31,
24 lines 2-14;Keller Direct,page 13,lines 16-21).Please
25 describe the Company's experience mitigating these types
905 Vail,Di-Reb -14
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1 of transmission project risks.
2 A.In the past five years,the Company has
3 completed two significant and similar Energy Gateway
4 transmission projects:(1)the 100-mile 500/345 kV
5 Mona-to-Oquirrh transmission line;and (2)the 170-mile
6 345 kV Sigurd-to-Red Butte transmission line.Similar to
7 the Aeolus-to-Bridger/Anticline line,both projects
8 required a NEPA-compliant Environmental Impact Statement,
9 including a Record of Decision,Plan of Development,and
10 Right of Acquisition process.Using its expertise in
11 utility resource
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906 Vail,Di-Reb -14a
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1 development and project management,the Company delivered
2 both the Mona-to-Oquirrh and Sigurd-to-Red Butte
3 transmission lines within the cost estimates used in the
4 CPCN processes and on time.Table 1 below summarizes the
5 actual project performance relative to the CPCN filing
6 information:
7 TABLE1
cost
PRO!EG REF Date of Applicadon ($,000,0005)im5erivce :05T in-Serviœ
MonaOquirrh UTDodet09m5-54 Namemirr21,ÉS $WHÍD 5/3V2o13 5 304.00 SOU2eg
SigurdRed Butte UT Docket U-035-97 Sepleniberu,2DU $3mm 430/2015 &357.80 gŠGj2m510
11 The Transmission Projects have the same project
12 management team,and the Company developed the budget and
13 schedule in the same manner as these earlier projects.
14 The Company's past experience substantially mitigates
15 construction cost and schedule risk.
16 Q.How confident are you in the cost estimates for
17 the Transmission Projects?
18 A.The Company is confident that it will deliver
19 the Transmission Projects at or below the cost estimates
20 included in this filing,as updated in the supplemental
21 testimony.Since starting the Energy Gateway Program,
22 which includes the Aeolus-to-Bridger/Anticline line,the
23 Company has used a Facilities Definition Document to
24 clearly define and describe the required scope of the
25 project to all parties.The Facilities Definition
907 Vail,Di-Reb -15RockyMountainPower
1 Document is one of the foundations for the project
2 success described earlier in my testimony.This document
3 was updated prior to developing the schedule and budgets
4 that were included in the CPCN application.A clear
5 definition of the project scope from the beginning of the
6 project life-cycle brings an increased confidence in the
7 accuracy of forecasts.
8 In addition,as an overall strategy of
9 controlling contract cost and performance,the Company
10 will secure fixed-price,fixed-performance date contracts
11 that will
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908 Vail,Di-Reb -15a
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1 provide liquidated damages for late performance.The
2 Company also uses project management techniques to trend
3 and forecast performance,including earned value
4 analysis,which provides an early notification of
5 potential productivity concerns that can then be
6 addressed before becoming a major issue.In fact,the
7 Company anticipates executing contracts for the
8 Aeolus-to-Bridger/Anticline line (which is a substantial
9 portion of the overall Transmission Projects'cost)in
10 early 2018 that will effectively lock-in the cost for
11 that line.Mr.Mullins also claims that the Company's
12 estimated incremental O&M costs for the Transmission
13 Projects is unsupported and the actual O&M may be much
14 higher.The Company has a well-defined maintenance
15 program that includes line and substation inspections,
16 preventative maintenance and corrective maintenance.The
17 Company has extensive experience operating and
18 maintaining both transmission and distribution assets.
19 Based on the defined maintenance programs and the
20 Company's experience with similar assets,the O&M costs
21 assumed for this project are accurate.
22 Q.Mr.Mullins further claims the Company has a
23 history of under-estimating transmission resource costs
24 and cites the Populus-to-Terminal transmission line as an
25 example.(Mullins Direct,page 4,lines 10-15).Is Mr.
909 Vail,Di-Reb -16
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1 Mullins'characterization of the cost estimates for the
2 Populus-to-Terminal line correct?
3 A.No,Mr.Mullins'testimony on this point is
4 very misleading.Mr.Mullins testifies that the
5 Populus-to-Terminal line was originally estimated to cost
6 $78 million,but was actually constructed for $801
7 million,implying the Company's estimate was understated
8 by more than $700 million.In fact,when the Company
9 requested a CPCN from the Commission for the Populus-to-
10 Terminal line,its cost estimate was $750
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910 Vail,Di-Reb -16a
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1 million,which was within seven percent of the final
2 costs.See In the Matter of the Application of Rocky
3 Mountain Power For a Certificate of Public Convenience
4 and Necessity Authorizing Construction of the
5 Populus-to-Terminal 345 kV Transmission Line Project,
6 Case No.PAC-E-08-03,Order No.30657 at 2 (Oct.10,
7 2008).
8 Q.What is the basis for Mr.Mullins'claim that
9 the Populus-to-Terminal line was originally estimated to
10 cost $78 million?
11 A.Mr.Mullins appears to have relied on a 2006
12 estimate provided by the Company in one of its
13 commitments stemming from the merger with MidAmerican
14 Energy Holding Company.In the Matter of the Joint
15 Application of MidAmerican Energy Holdings Company (MEHC)
16 and PacifiCorp dba Utah Power &Light Company for an
17 Order Authorizing MEHC to Acquire PacifiCorp,Case No.
18 PAC-E-05-08,Order No.29998 at 6 (Mar.14,2006).Mr.
19 Mullins'testimony fails to note,however,that between
20 the estimate included in the merger commitment and the
21 actual construction of the Populus-to-Terminal line,
22 conditions changed.Most notably,the 2006 merger
23 commitment was a high-level estimate of the cost to
24 construct a 300 MW transmission line,while subsequent
25 developments indicated that a much larger resource was
911 Vail,Di-Reb -17
Rocky Mountain Power
1 required.Thus,the Populus-to-Terminal line provided 700
2 MW of immediate additional capacity and 1400 MW of
3 additional future capacity.Mr.Mullins'comparison of
4 the $78 million estimate in the merger commitment to the
5 actual costs of the Populus-to-Terminal line is
6 disingenuous and inapt.
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912 Vail,Di-Reb -17a
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1 Q.Staff witness Mr.Randy Lobb proposes a cap on
2 the construction costs for the Transmission Projects
3 based on the Company's estimates.(Lobb Direct,page 6,
4 lines 15-16).Would the Company accept this condition?
5 A.Yes,in part.As discussed by Company witness
6 Ms.Joelle R.Steward,consistent with the binding
7 ratemaking treatment law in Idaho,the Company agrees to
8 a soft cap based on the cost estimate included in the
9 Company's supplemental filing.If the actual costs are
10 greater than the final estimate,the Company agrees it
11 must demonstrate the prudence of the additional costs in
12 a subsequent ratemaking proceeding.
13 Q.Mr.Dauphinais specifically argues that the
14 lack of Wyoming Industrial Siting Permit and the lack of
15 a CUP from Carbon County may delay the Transmission
16 Projects.(Dauphinais Direct,page 10,lines 9-12).How
17 do you respond to this concern?
18 A.The Company understands that the permitting
19 process for transmission is complex,but it is already
20 well on its way to securing all required permits.In my
21 testimony regarding permit status,I note the Company is
22 currently preparing applications for all of the major
23 remaining permits.The permitting schedule sets forth
24 completing the process by the end of 2018.To mitigate
25 the risk of permitting delays,this schedule allows some
913 Vail,Di-Reb -18
Rocky Mountain Power
1 delay without adversely impacting the overall
2 construction schedule.
3 In addition,to further mitigate the risk of
4 potential delays,the Company is actively engaging with
5 stakeholders to inform them of the Transmission Projects
6 and the applicable permit application process.The
7 Company meets with the BLM on a regular basis to review
8 project status,planned or expected deliverables to the
9 BLM and cooperating agencies in relevant areas such as
10 Section 106 consultation,Plan of
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914 Vail,Di-Reb -18a
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1 Development work,and the like.Similarly,the Company
2 has met with the Wyoming Industrial Siting Commission to
3 review the application process and the Company will soon
4 engage with agencies supporting the Industrial Siting
5 Permit to inform those agencies of the project details.
6 Engaging with stakeholders increases the ability to
7 understand local needs,identify appropriate approaches
8 and potential mitigations to successfully complete the
9 permit and approvals process.
10 Q.What about the risk of delay associated with
11 obtaining rights-of-way for the Transmission Projects?
12 A.Although the Company does not intend to
13 complete acquisition of rights-of-way until early 2019,
14 it is confident this timing will not delay the
15 Transmission Projects.The Company has engaged landowners
16 on the projects since 2007 as part of its outreach for
17 the overall Energy Gateway West project.During that time
18 the Company learned a lot about the concerns of
19 landowners and has,where practical,addressed many of
20 them.
21 In summer 2017,the Company renewed discussions
22 with all landowners about the Transmission Projects.This
23 effort has identified,and continues to identify,
24 additional concerns and questions the Company is
25 committed to resolve to balance the needs of landowners
915 Vail,Di-Reb -19
Rocky Mountain Power
1 with the project and its schedule.This renewed
2 discussion will,through previous experience,resolve
3 many issues and lead to successful conclusion of
4 negotiations.Because any project will affect landowners
5 in different ways,the effort and time frame of
6 negotiations are individual and will vary from landowner
7 to landowner.When landowners are willing to actively
8 engage in the process,timely resolution is almost always
9 assured.
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916 Vail,Di-Reb -19a
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1 Q.How has the Company evaluated risks with the
2 construction schedule?
3 A.Project risks related to the construction
4 schedule fall broadly into three classifications:
5 (1)restricted access due to environmental constraints;
6 (2)weather restrictions;and (3)late commencement due
7 to late receipt of all permits.
8 To mitigate the potential impacts due to
9 environmental constraints,the Company considered
10 previous project history constructing in areas with
11 similar levels of constraints and built the overall
12 schedule based on this experience.From previous
13 practical experience and the ongoing agency engagements
14 described in my testimony,the Company understands that
15 mitigation techniques,such as supervised or monitored
16 access into environmentally restricted areas,is possible
17 through negotiation and cooperation between respective
18 parties.Additional mitigation plans,such as
19 re-sequencing of work or schedule compression,have also
20 been successfully employed on previous projects,with the
21 contractor assuming the risk of occurrence for such
22 items.
23 To mitigate the risk of constraints caused by
24 weather,the schedule is set to minimize construction
25 during the winter and perform additional work in the
917 Vail,Di-Reb -20
Rocky Mountain Power
1 summer.In 2009,the Company engaged with several
2 qualified and respected construction contractors to
3 analyze the feasibility of the construction program.This
4 informed the Company on the overall approach needed for
5 the project and has helped the Company develop the
6 project schedule.In addition,the Company is currently
7 negotiating contracts where the construction contractor
8 will assume the risk for weather delays and allow for
9 such delay within their schedule and the guaranteed
10 completion dates within the contract.
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918 Vail,Di-Reb -20a
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1 Q.What are the primary risks and mitigation
2 measures underway?
3 A.The primary risk in maintaining the
4 critical-path construction schedule for the Transmission
5 Projects is the on-going regulatory review and approval
6 processes currently underway.In particular,it is
7 critical that the Company obtain CPCNs from the WPSC for
8 the Transmission Projects,which are conditioned upon
9 acquisition of all necessary rights-of-way,with
10 sufficient time to meet this condition.The Company must
11 also obtain the outstanding siting permits by the end of
12 2018.If the Company does not receive conditional CPCNs
13 in early 2018,or siting permits by the end of 2018,it
14 must assess the viability of achieving a year-end 2020
15 online date before moving forward.To manage the risk of
16 obtaining timely regulatory reviews and approvals,the
17 Company will secure off-ramps in its EPC contracts,
18 allowing assurance of regulatory approvals before
19 significant capital commitments or outlays are made.
20 Q.Is the Company confident that it can manage the
21 construction schedule risk and deliver the Transmission
22 Projects by 2020?
243
Compa y
wiYesstrucmageandmanarge
he T m s
isk,the
25 Projects on a firm,date-certain,fixed-price,turnkey
919 Vail,Di-Reb -21
Rocky Mountain Power
1 contract basis.Construction contractors and equipment
2 suppliers will be held to key construction and delivery
3 milestones and development of compressed schedule
4 mitigation plans,if required.The Company will establish
5 construction contract completion dates and backstop them
6 with guarantees.
7 Q.Does the Company have experience building
8 similar types of projects that require completion by a
9 date certain?
10 A.Yes.The Company has managed multiple major
I
I11projectsthatrequiredtheworkbe
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920 Vail,Di-Reb -21a
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1 completed by a date certain,or similar circumstancesO2whereprojectcompletionwasrequiredtoallowaproject
3 to tie into an existing system within a short planned-
4 outage window or closely coordinated with delivery of
5 transmission system network upgrades.Examples of these
6 projects include:(a)Dunlap wind facility;(b)High
7 Plains wind facility;(c)McFadden Ridge I wind facility;
8 (d)Populus-to-Terminal 345 kV transmission line;(e)
9 Sigurd-to-Red Butte transmission line;(f)Mona-to-
10 Oquirrh transmission line;(g)Lake Side 2 combined cycle
11 natural gas facility;(h)Jim Bridger Unit 3 and Jim
12 Bridger Unit 4 selective catalytic reduction systems;(i)
13 Naughton Unit 1 and Naughton Unit 2 flue gas
14 desulfurization systems ("FDG");(j)Hunter Unit 1,
15 Hunter Unit 2,Huntington Unit 1,and Huntington Unit 2
16 pulse jet fabric filters ("PJFF");and (k)Wyodak PJFF,
17 (1)Dave Johnston Unit 3 and Dave Johnston Unit 4 PJFF
18 and FGD systems.
19 Q.If the Transmission Projects aren't fully
20 in-service by December 31,2020,can the new wind
21 projects still qualify for the production tax credit?
22 A.Yes.Assuming the Transmission Projects are not
23 completed by December 31,2020,but otherwise have
24 facilitated synchronization to the transmission grid and
25 commissioning of individual wind turbines in accordance
921 Vail,Di-Reb -22
Rocky Mountain Power
1 with Internal Revenue Service ("IRS")guidance,the
2 Company would treat a completed and functional wind
3 turbine as being placed in service regardless of any
4 transmission constraints affecting a wind project.In
5 Private Letter Ruling ("PLR")20033403,the IRS ruled
6 that if a wind turbine has all necessary operating
7 permits and licenses,has been synchronized to the power
8 grid,the critical tests for the components of the wind
9 turbine have been completed,the wind turbine has been
10 placed in the control of the taxpayer by the contractor
11 and the taxpayer
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922 Vail,Di-Reb -22aRockyMountainPower
1 has sold electricity that has been produced by the wind
2 turbine,then the wind turbine has been placed in
3 service.This is even if the wind project is not
4 producing transmission-level electricity due to a delay
5 in a transmission project and has not been deemed to be
6 under commercial operation by a regulatory commission.A
7 PLR may not be relied on as precedent by other taxpayers;
8 however,it is indicative of the IRS position on certain
9 matters.
10 ENERGY IMBALANCE MARKET COSTS
11 Q.Mr.Mullins claims the EIM will impose
12 additional costs on the Wind Projects because they will
13 be subject to uninstructed imbalance charges that were
14 not included in the Company's economic analysis.(Mullins
15 Direct,page 28,line 20 -29,line 1).Is this true?
16 A.No.There is no basis to assume that
17 uninstructed imbalance will result in a net cost and,in
18 fact,the expectation is that over time there will be no
19 net impact associated with uninstructed imbalance.
20 Q.What is uninstructed imbalance?
21 A.Uninstructed imbalance in the EIM is assessed
22 when a unit does not follow its scheduled output in the
23 five-minute market.For example,if the dispatch
24 operating target for five minutes was 50 MW and the unit
25 actually produced 55 MW,then there is an uninstructed
923 Vail,Di-Reb -23
Rocky Mountain Power
1 imbalance of 5 MW.In this example,the 5 MW would be
2 multiplied by the locational marginal price of the unit
3 to determine the uninstructed imbalance assessment.
4 Importantly,however,the assessment can be a charge or a
5 credit because the locational marginal price for a
6 particular unit can be positive or negative.All of the
7 Company's generating units,as well as loads,have
8 uninstructed imbalance.
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1 Mr.Mullins is wrong to claim that uninstructed imbalanceO2issomehowanegativeoutcomethatwillimposeadditional
3 costs.
4 Also,as described by Company witness Mr.Chad
5 A.Teply,the wind forecasts that are provided to the
6 Company's economic model are P50 forecasts,which assumed
7 a balanced outcome over periods of times,i.e.,there is
8 a 50 percent probability that wind generation will be
9 more than forecast and a 50 percent probability it will
10 be below forecast.To impute a negative pricing outcome
11 assumes that the times when the unit is under or over
12 performing is somehow biased towards periods in which the
13 dollar impact is less favorable,e.g.,always under
14 performs when prices are high or over performs when
15 prices are low (possibly negative).This would imply a
16 bias in the outcome,which is an unreasonable assumption
17 in a forecast for variable energy resources.
18 Finally,because the EIM is such a large,
19 liquid market with renewable resource diversity,it
20 further supports the assumption of a balanced price
21 outcome when a resource or load deviates from a forecast.
22 Q.Mr.Mullins also claims the EIM operates only
23 on the ability to transfer power on the firm rights of
24 the Company,and does not allow transfers to occur on
25 another utilities'transmission rights.(Mullins Direct,
925 Vail,Di-Reb -24
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1 page 28,lines 13-15).Is this true?
2 A.No.The opposite is true.The ability to use
3 available transmission capability across the Western
4 Interconnect of participating EIM entities and the
5 California Independent System Operator ("CAISO")is the
6 foundation of how benefits are realized in the EIM.
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1 THIRD-PARTY TRANSMISSION REVENUE
2 Q.Mr.Dauphinais also expressed a concern that
3 the Company's forecasted third-party transmission revenue
4 resulting from the Transmission Projects will not
5 materialize because the costs of the Transmission
6 Projects may not be included the Company's OATT rates.
7 (Dauphinais Direct,page 12,lines 17-19).How do you
8 respond to this concern?
9 A.Mr.Dauphinais'concern is unfounded.The
10 Transmission Projects are network transmission assets
11 under the Company's OATT because they will be integrated
12 into the Company's transmission network,available for
13 scheduling by all customers,and provide benefits to the
14 network,such as congestion relief,increased
15 transmission capacity and improved system reliability,
16 among others.Based on these characteristics,I
17 understand that FERC precedent supports rolling the costs
18 of these assets into the Company's transmission rates.
19 I also understand that FERC's longstanding open
20 access transmission policies state the cost of network
21 upgrades necessary to accommodate transmission service
22 should be rolled into transmission rates because these
23 types of upgrades are presumed to benefit all network
24 users.The Transmission Projects clearly provide network
25 benefits to all customers that use the transmission
927 Vail,Di-Reb -25
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1 system,including third-party transmission system users,
2 while also allowing additional generation to be
3 connected.
4 Q.Does Mr.Dauphinais recognize that FERC
5 precedent generally supports rolling the costs of network
6 transmission facilities into OATT rates?
7 A.Yes.(Dauphinais Direct,page 13,lines 16-17).
8 Mr.Dauphinais cites only one case where a utility was
9 unable to roll a transmission project into its FERC
10 formula rates.
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928 Vail,Di-Reb -25a
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1 Notably,the 1993 case cited by Mr.Dauphinais predatesO2twolandmarkFERCordersthatrevampedmajorfederal
3 transmission policies and that still define the federal
4 landscape we operate in today.First,FERC's 1994
5 transmission pricing policy order essentially marked the
6 beginning of the presumption that any network
7 transmission facility benefits all network users and,
8 thus,the cost of any network facilities should be rolled
9 into transmission rate base and shared among all network
10 users rather than directly allocated to the customer
11 "causing"the need for the new facility.Inquiry
12 Concerning the Commission's Pricing Policy for
13 Transmission Services Provided by Public Utilities Under
14 the Federal Power Act,59 Fed.Reg.55,031 (Nov.3,
15 1994),FERC Stats.&Regs.¶31,005 46 (1994),order on
16 reconsideration,71 FERC ¶61,195 (1995).
17 Second,in 1996,FERC established open access
18 transmission policies,including the pro forma OATT.
19 Promoting Wholesale Competition Through Open Access
20 Non-discriminatory Transmission Services by Public
21 Utilities;Recovery of Stranded Costs by Public Utilities
22 and Transmitting Utilities,Order No.888,61 Fed.Reg.
23 21,540 (May 10,1996),FERC Stats.&Regs.¶31,036
24 (1996).
25 Q.Has the Company ever had FERC reject a request
929 Vail,Di-Reb -26
Rocky Mountain Power
1 to roll the costs of a transmission project into its OATT
2 rates?
3 A.No.
4 Q..How will the costs of the Transmission Projects
5 flow into the Company's transmission rates,and who will
6 pay these rates?
7 A.The Company's current transmission formula rate
8 (included in PacifiCorp's OATT)was approved by FERC in
9 Docket No.ER11-3643.PacifiCorp's transmission formula
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930 Vail,Di-Reb -26a
Rocky Mountain Power
1 rate is updated annually with the transmission revenue
2 requirement ("ATRR")that represents the annual total
3 cost of providing firm transmission service over the test
4 year.The ATRR calculation incorporates a return on rate
5 base,income taxes,expenses,and certain revenue
6 credits,among other specific elements and adjustments.
7 Transmission assets,including new transmission capital,
8 are included in the ATRR,weighted by months in service.
9 The ATRR is converted into a rate by dividing ATRR by
10 firm transmission demand.All third-party revenues for
11 transmission service (along with third-party revenues for
12 ancillary services)are included as revenue credits in
13 the calculation of rates in each of PacifiCorp's state
14 retail jurisdictions.
15 Q.Mr.Mullins also claims the Company "simply
16 assumed that 12 percent of the new investment"in the
17 Transmission Projects would be funded by OATT customers.
18 (Mullins Direct,page 30,lines 3-6).Is this true?
19 A.No.As I explained above,FERC has approved the
20 Company's current formula rate that will include the ATTR
21 of the Transmission Projects once they are in-service,
22 and the Company has gone through the annual update.The
23 12 percent figure represents the current level of ATRR
24 funded by OATT customers.
O 25 Q.Does this conclude your rebuttal testimony?
A.Yes.
931 Vail,Di-Reb -27
Rocky Mountain Power
1 Q.Are you the same Rick A.Vail who previouslyO2provideddirectandrebuttaltestimonyinthiscaseon
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.Based on the results of the 2017R Request for
10 Proposals ("RFP"),I update the status of the
11 Aeolus-to-Bridger/Anticline line1 and network upgrades
12 (collectively,the "Transmission Projects")that support
13 the Company's decision to construct or procure four new
14 wind resources ("Wind Projects")(collectively,the
15 "Combined Projects").I explain the important progress
16 the Company has made on the Transmission Projects,as
17 well as their decreasing risk.
18 Q.Please summarize your testimony.
19 A.I address the following key issues for the
20 Transmission Projects:
21 o An update on the status of:
22 o Expected design and cost for the Transmission
23 Projects based on the outcome of the 2017R
24 RFP.
25 o Engineering,Procurement,and Construction
932 Vail,Di-Supp -1
Rocky Mountain Power
1 ("EPC")contracts,and required easements.
2 o Technical analysis demonstrating that the
3 Company's Aeolus-to-Bridger/Anticline line
4 will enable interconnection of up to 1,270 MW
5 of additional resources and increase transfer
6 capability by 750 MW from east to west across
7 Wyoming.
8 /
9
10 /
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15
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17
18
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24
25 1 As defined in my direct testimony at page 2,lines 4-12.
933 Vail,Di-Supp -la
Rocky Mountain Power
1 o The need for the Aeolus-to-Bridger/AnticlineO2line,and its integral role in regional
3 transmission planning.
4 UPDATE ON THE TRANSMISSION PROJECTS
5 Q.Since the rebuttal filing,has the Company
6 maintained the project schedule and cost estimates for
7 the Aeolus-to-Bridger/Anticline line?
8 A.Yes.The Company has made significant progress
9 and is on track to meet its development schedule at or
10 below the costs estimated in its direct filing.
11 Q.Did the results of the 2017R RFP affect the
12 costs or design of the Aeolus-to-Bridger/Anticline line?
13 A.No.The results of the 2017R RFP did not affect
14 the estimated costs or the design of the Aeolus-to-
15 Bridger/Anticline line.The Company is currently in a
16 competitive selection process for an EPC contractor for
17 the line and the preliminary results of this process
18 confirm the cost estimates included in the initial
19 filing.As I noted in my rebuttal testimony,the
20 Aeolus-to-Bridger/Anticline line is approximately 85
21 percent of the total costs of the Transmission Projects,
22 and therefore the execution of EPC contracts will be a
23 significant milestone in confirming final project costs.
24 Q.What is the current status of the EPC contract?
25 A.Negotiations are currently ongoing to finalize
934 Vail,Di-Supp -2
Rocky Mountain Power
1 the terms and conditions,and the Company expects to
2 complete these negotiations in January 2018.The EPC
3 contracts for the Aeolus-to-Bridger/Anticline line remain
4 on track to be in place by October 2018.
5 Q.Have the network upgrades described in your
6 testimony changed because of the final shortlist Wind
7 Projects from the 2017R RFP?
8 A.Yes,there are changes to the network upgrades
9 resulting from the Wind Projects chosen
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935 Vail,Di-Supp -2a
Rocky Mountain Power
1 for the final shortlist for the 2017R RFP.The Wind
2 Projects are four facilities in Wyoming totaling
3 approximately 1,170 MW-McFadden Ridge II,TB Flats I and
4 II,Cedar Springs,and Uinta.
5 Q.Please describe the updated network upgrades
6 required to interconnect the Wind Projects.
7 A.The 230 kV network upgrades for the McFadden
8 Ridge II and TB Flats I and II projects that were
9 identified in my direct testimony are still necessary to
10 interconnect these Wind Projects because they were
11 selected for the 2017R RFP final shortlist.2 In
12 addition,the McFadden Ridge II project will require a
13 new three-breaker 230-kV point-of-interconnection
14 ring-bus substation on the High Plains to Foote Creek
15 230-kV line,roughly two miles southwest of High Plains
16 substation,as shown in Exhibit 36.There are also
17 additional network upgrades required for the other
18 projects that were selected through the 2017R RFP.
19 First,to interconnect the Cedar Springs
20 project,the Company must install two 230-kV (3000
21 ampere)breakers and two line positions with associated
22 switches at Windstar substation.The Company must also
23 install high-speed relaying to switch off the shunt
24 capacitor banks at the Riverton 230 kV bus,which are
25 required for high-voltage conditions,and rebuild
936 Vail,Di-Supp -3RockyMountainPower
1 approximately 56 miles of the Dave-Johnston-Amasa-
2 Difficulty-Shirley Basin 230-kV line with 2-1272 bundled
3 conductor.
4 Second,to interconnect the Uinta project,the
5 Company must construct a new three-breaker 138-kV
6 point-of-interconnection ring-bus substation southwest of
7 the
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14
15
16
17
18
19
20
21
22
23 2 Exhibit Nos.4,and 10 through 21).The Ekola project that was also
included as a benchmark resource in the initial filing did not
24 require network upgrades to interconnect,and therefore all network
upgrades discussed in my direct testimony were related to the
25 McFadden Ridge II and TB Flats I and II projects.
937 Vail,Di-Supp -3a
Rocky Mountain Power
1 Whitney Canyon Tap (near structure 116),with associated
2 switches and line terminations.The Company must also
3 re-conductor approximately 13.7 miles of the Q0715 -
4 Railroad 138 kV line with 1-1272 ACSR/phase (line has
5 1-795 ACSR/phase),and modify the existing Naughton
6 remedial action scheme ("RAS")to allow redundant
7 communication to the project.
8 Exhibit No.36 details the specifics of these
9 additional network upgrades.
10 Q.What are the updated costs for the network
11 upgrades?
12 A.Confidential Table 1 saamarizes the updated
13 costs for the network upgrades:
14 Confidential Table 1
15 Network Upgrades
16 ITEM VALUE
Transmission Line
17 Substation
Engineering
18 Right-of-WayAcquisition
PM/Environmental/Support
In-directs
20
TOTAL
21
22 Q.Have these costs been included in the updated
23 economic analysis included in Company witness Mr.Rick T.
24 Link's testimony?
25 A.Yes.
938 Vail,Di-Supp -4
Rocky Mountain Power
1 Q.Why did the network upgrade costs increase by
2 approximately (redacted)million compared to the
3 Company's initial estimate?
4 A.The selection of the Cedar Springs and Uinta
5 projects to the 2017R RFP shortlist required additional
6 network upgrade costs that were not included in the
7 original estimate.Notably,however,although the network
8 upgrade costs increased relative to
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939 Vail,Di-Supp -4a
Rocky Mountain Power
1 the initial filing,the overall costs of the Combined
2 Projects remains roughly unchanged even though customers
3 are now receiving substantially more capacity for the
4 same overall project cost of approximately $2 billion,as
5 discussed further by Mr.Link in his supplemental direct
6 testimony.
7 Q.Will these additional network upgrades delay
8 the completion of the Transmission Projects?
9 A.No.The types of additional upgrades needed are
10 fairly routine projects that the Company performs in the
11 ordinary course of business,and they can be completed
12 well before the end of 2020.Thus,the status of the
13 Transmission Project design work I described in my
14 rebuttal testimony remains unchanged.
15 Q.Have you included the information required by
16 Idaho Code §§61-526 and Rule 112 of the Idaho Public
17 Utilities Commission for the new facilities described
18 above?
19 A.Yes.Exhibit No.36 submitted with this
20 supplemental direct testimony along with the exhibits
21 that were submitted with my direct testimony include the
22 relevant information required for the Commission to grant
23 a CPCN for the additional network upgrades.
24 Q.What is the current status of the EPC contracts
25 for the network upgrades?
940 Vail,Di-Supp -5
Rocky Mountain Power
1 A.The additional network upgrades have not
2 materially changed the Company's timeline or process for
3 finalizing the EPC contracts.The Company still intends
4 to competitively source both the transmission line and
5 substation construction via existing term "Line Service
6 Agreements"the Company holds with over one dozen
7 qualified contractors capable of working in Wyoming.
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941 Vail,Di-Supp -5a
Rocky Mountain Power
1 Q.What is the status of the technical studiesO2thatarenecessarytosupporttheTransmissionProjects?
3 A.Now that the Wind Projects have been identified
4 through the 2017R RFP,the Company has begun additional
5 studies and technical analysis.I expect these studies
6 and analyses to confirm that the Aeolus-to-Bridger/
7 Anticline line will increase the system's stiffness
8 factor sufficiently to enable interconnection of up to
9 1,270 MW of additional resources and increase transfer
10 capability by 750 MW from east to west across Wyoming.
11 Q.What is the status of the Company's acquisition
12 of rights-of-way necessary for the Transmission Projects?
13 A.The Company has contacted all landowners where
14 easements for access or transmission rights-of-way (or
15 both)are required.To date,24 offers of options for
16 rights-of-way have been issued to landowners.Four
17 landowners have accepted and three additional landowners
18 have provided counteroffers.All remaining offers for the
19 500 kV project will be issued by January 31,2018.The
20 acquisition of rights-of-way remains on track to support
21 the planned construction start date of April 1,2019.
22 Q.Does the Aeolus-to-Bridger/Anticline line
23 remain a necessary project that is in the public interest
24 even if the Wind Projects are not developed?
25 A.Yes.There is an independent need for the
942 Vail,Di-Supp -6
Rocky Mountain Power
1 Aeolus-to-Bridger/Anticline line,even if the new WindO2Projectsarenotconstructedbecauseitwillimprove
3 system performance and reliability and directly serve
4 customers.Even if the Wind Projects are not approved,
5 the Company's and region's long-term transmission plans
6 still call for the construction of the Aeolus-to-Bridger/
7 Anticline line by 2024.Thus,the Company will need to
8 construct this transmission line in the near future.The
9 question is whether it is built in
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943 Vail,Di-Supp -6a
Rocky Mountain Power
1 2020 when PTC-eligible wind can offset the costs andO2producenetbenefitsforcustomers,or in 2024 at full
3 cost to customers.
4 Q.Does this conclude your supplemental direct
5 testimony?
6 A.Yes.
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944 Vail,Di-Supp -7
Rocky Mountain Power
1 Q.Are you the same Rick A.Vail who previouslyO2providedtestimonyinthiscaseonbehalfofPacifiCorp
3 dba Rocky Mountain Power (the "Company")?
4 A.Yes.
5 PURPOSE AND SUMMARY OF SECOND SUPPLEMENTAL DIRECT
TESTIMONY
6
7 Q.What is the purpose of your second supplemental
8 direct testimony in this proceeding?
9 A.My testimony provides an update on the network
10 upgrade costs associated with the TB Flats I and II,
11 Cedar Springs,and Uinta projects,which are three of the
12 four new wind resources ("Wind Projects")included on the
13 updated final shortlist of the 2017R Request for
14 Proposals ("RFP").My testimony also contains the
15 information required under the voluntary request for
16 approval of a resource decision to construct the
17 Aeolus-to-Bridger/Anticline line and network upgrades
18 ("Transmission Projects").
19 Q.Please summarize your testimony.
20 A.Since filing supplemental direct testimony on
21 January 16,2018,the Company's transmission function
22 finalized a broader open access transmission tariff
23 ("OATT")restudy process,which included producing system
24 impact restudy ("SISs")reports for the following three
25 Wind Projects:TB Flats I and II,Cedar Springs,and
945 Vail,Di-2nd Supp -1
Rocky Mountain Power
1 Uinta.Based on the completed SISs,the network upgrade
2 costs have increased to (redacted).In addition,the
3 Company's updated studies indicate that with the
4 construction of the Aeolus-to-Bridger/Anticline
5 transmission line,the Company can interconnect 1,510 MW
6 of new wind capacity behind the transmission constraint
7 in southeastern Wyoming.Thus,the Company has confirmed
8 that there is sufficient stiffness factor and transfer
9 capability to interconnect the three Wind Projects
10 located in southeast
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946 Vail,Di-2nd Supp -la
Rocky Mountain Power
1 Wyoming (i.e.,TB Flats I and II,Cedar Springs,and
2 Ekola Flats),as well as the fourth Wind Project located
3 in western Wyoming (i.e.,Uinta).
4 UPDATE ON NETWORK UPGRADE COSTS
5 Q.Why has the Company updated the network upgrade
6 costs associated with the Wind Projects?
7 A.The Company's transmission function updated the
8 interconnection network upgrade costs associated with
9 three of the four Wind Projects as part of a broader OATT
10 restudy process.More specifically,after the Company
11 announced its plan to construct the Energy Gateway
12 Aeolus-to-Bridger/Anticline D.2 segment to come online by
13 2020,the Company's transmission function initiated an
14 interconnection restudy process to ensure its
15 interconnection studies reflected the most current
16 long-term transmission plan assumptions.In accordance
17 with its OATT,the Company's transmission function
18 performed restudies in serial queue order to determine
19 whether the acceleration of Energy Gateway segment D.2
20 would impact the cost or timing of interconnection of
21 projects that had not yet executed interconnection
22 agreements and that had previous studies depending on
23 Energy Gateway West in its entirety.The Company's
24 transmission function posted the SIS reports to OASIS on
25 January 29,2018,as well as certain updated reports on
947 Vail,Di-2nd Supp -2
Rocky Mountain Power
1 February 9,2018,after the Company filed its January 16,O 2 2018,supplemental direct testimony.Three of the four
3 Wind Projects (TB Flats I and II,Cedar Springs,and
4 Uinta)were among the interconnection projects to receive
5 restudies.
6 Q.Did the Company restudy the McFadden Ridge II
7 project's interconnection?
8 A.No.Because of its position in the queue,the
9 McFadden Ridge II project had not yet
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948 Vail,Di-2nd Supp -2a
Rocky Mountain Power
1 received even an initial SIS;therefore,it was notO2includedintheprojectsthatwererestudied.McFadden
3 Ridge II's queue position and location in the constrained
4 area of PacifiCorp's transmission system in eastern
5 Wyoming indicate that its future SIS will require the
6 construction of additional Energy Gateway segments beyond
7 just the D.2 segment to allow the project to
8 interconnect,which Mr.Link explains contributed to its
9 removal from the final shortlist.
10 Q.How does McFadden Ridge II's queue position and
11 location indicate its future SIS will require
12 construction of additional Energy Gateway segments?
13 A.PacifiCorp transmission can never guarantee the
14 result of a future SIS because of the many factors that
15 can affect it (e.g.,changes to the queue,as I discussed
16 above).Here,however,there is a specific point in the
17 interconnection queue where projects located in the
18 constrained area of PacifiCorp's eastern Wyoming
19 transmission system will require more than just the D.2
20 segment to interconnect,and that point in the queue is
21 before McFadden Ridge II's queue position.More
22 specifically,the restudy reports incorporating the
23 updated assumption regarding the staging of Energy
24 Gateway West showed that interconnection projects located
25 in eastern Wyoming with an interconnection-queue position
949 Vail,Di-2nd Supp -3
Rocky Mountain Power
1 greater than Q0712 trigger the need for Energy Gateway
2 South,which is not planned to be placed in service by
3 the end of 2020.All other bids originally selected to
4 the final shortlist can secure interconnection either
5 because they hold an interconnection queue position that
6 does not require Energy Gateway South (Ekola Flats,TB
7 Flats I and II,and Cedar Springs);or because their
8 project location is not in the constrained area of the
9 Company's eastern Wyoming transmission system (Uinta).
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950 Vail,Di-2nd Supp -3a
Rocky Mountain Power
1 Q.Why can Uinta interconnect with just the D.2
2 segment even though it has an interconnection-queue
3 position higher than Q0712?
4 A.Uinta is located in western Wyoming where it
5 (and other projects in the same area)can secure
6 interconnection without triggering additional Energy
7 Gateway segments.
8 Q.Why did the Company not restudy the
9 interconnection for the Ekola Flats project?
10 A.Ekola Flats executed a Large Generator
11 Interconnection Agreement ("LGIA")in November 2017 and
12 therefore did not require restudy.
13 Q.Why didn't the Company complete these
14 interconnection studies earlier so they could be analyzed
15 earlier in the 2017R RFP process?
16 A.The Company's transmission function did not
17 perform the restudies in conjunction with the 2017R RFP
18 process.Rather,as noted above,the Company's
19 transmission function followed its OATT process to
20 perform a broader restudy of the interconnection queue to
21 assess whether and to what extent the cost or timing of
22 certain interconnection projects was impacted by the
23 Company's change to its long-term transmission plan,
24 i.e.,the staging of the Energy Gateway West project.
25 In addition,and as discussed by Mr.Link,at
951 Vail,Di-2nd Supp -4
Rocky Mountain Power
1 the request of the Utah independent evaluator,the 2017RO2RFPdidnotrequirethatbiddershaveacompletedSIS
3 when bids were submitted.This allowed bidders to
4 participate in the 2017R RFP regardless of their position
5 in the interconnection queue--a queue that can change
6 over time as generator-interconnection customers change
7 project details,request commercial operation date
8 extensions or suspension,or withdraw from the queue
9 altogether.As a result,while the restudies were
10 performed independent of the 2017R RFP process,
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952 Vail,Di-2nd Supp -4a
Rocky Mountain Power
1 performing restudies to reflect an updated long-termO2transmissionplanassumptionclose-in-time to the
3 selection of the final shortlist allowed the Company's
4 transmission function to incorporate the most current
5 queue-based assumptions into restudies as well.
6 Q.Based on the SISs,what are the updated costs
7 for the network upgrades?
8 A.Confidential Table 1 summarizes the updated
9 costs for the network upgrades:
10 CONFIDENTIAL TABLE 1
11 230kV &138kV Network Upgrades
ITEM VALUE
12 Transmission Line (redacted)
Substation (redacted)
O 13 Engineering (redacted)Right of Way Acquisition (redacted)
14 PM/Environmental/Support (redacted)
Indirects (redacted)
15
TOTAL (redacted)
16
17 In addition,Exhibit No.48 provides greater
18 detail on the network upgrades required for each of the
19 Wind Projects and the SIS for each Wind Project is
20 included in Exhibit Nos.49 through 52.
21 Q.How do the updated network upgrade costs
22 compare to the estimate included in your supplemental
23 direct testimony of January 16,2018?
24 A.Network upgrade costs have increased by
25 approximately (redacted).This increase is due primarily
953 Vail,Di-2nd Supp -5RockyMountainPower
1 to the fact that the completed SISs indicate additionalO2facilitiesarerequiredtointerconnectsomeofthe Wind
3 Projects.
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954 Vail,Di-2nd Supp -5a
Rocky Mountain Power
1 Q.How have the network upgrades changed sinceO2thoseidentifiedinyoursupplementaldirecttestimony of
3 January 16,2018?
4 A.The Cedar Springs project no longer requires
5 the rebuild of a 56-mile portion of the Dave
6 Johnston-Amasa-Difficulty-Shirley Basin 230-kV line.The
7 rebuild can be deferred because another interconnection
8 project (Q0409)will not be online by 2020.The Cedar
9 Springs project will require a rebuild of the Standpipe-
10 Freezeout-Aeolus 230 kV line with a larger conductor,
11 approximately 15 miles,and a rebuild of the existing
12 Aeolus-Shirley Basin #1 line,approximately 16 miles.
13 Both of these upgrades were identified as network
14 upgrades in previous testimony.
15 In addition,the Uinta project no longer
16 requires the reconductoring of approximately 13.7 miles
17 of the Q0715-Railroad 138-kV line because the most recent
18 line ratings,which are continually upgraded as new
19 information is available,does not indicate exceedance of
20 the emergency rating on the line.The Uinta project
21 will,however,need to eliminate the credible N-2 outage
22 of the Ben Lomond-Birch Creek and Ben Lomond-Naughton 230
23 kV transmission lines,which share common structures for
24 approximately eight miles as they exit Ben Lomond
25 substation.This will require the construction of a 230
955 Vail,Di-2nd Supp -6
Rocky Mountain Power
1 kV single circuit transmission line beginning
2 approximately one mile outside of Ben Lomond substation
3 and continuing to structure 525 for the Ben
4 Lomond-Naughton #1 line.This line segment will replace
5 the current Ben Lomond-Naughton #1 circuit,which resides
6 on the north side of the 7-mile-long lattice tower double
7 circuit with the Ben Lomond-Birch Creek 230 kV
8 transmission line.The facilities identified for TB Flats
9 I and II remain the same.
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956 Vail,Di-2nd Supp -6a
Rocky Mountain Power
1 Q.Has the Company performed any additionalO2technicalstudiessincethefilingofsupplemental direct
3 testimony on January 16,2018?
4 A.Yes.The Company's updated studies indicate
5 that it can interconnect 1,510 MW of incremental wind
6 generation behind the TOT4A/TOT4B constraint.With the
7 addition of the Ekola Flats project to the final
8 shortlist,the Wind Projects will utilize 1,150 MW of the
9 incremental capacity,which will leave 360 MW for other
10 projects,including a 240 MW qualifying facility ("QF")
11 that has an executed interconnection agreement that does
12 not require the construction of Energy Gateway West and
13 South to accommodate the QF's interconnection.
14 Q.In your supplemental direct testimony,you
15 testified that the Company was in the process of testing
16 a new tower design for the Transmission Projects (Vail
17 Rebuttal,page 2 lines 16-23 and page 3 lines 1-23.Is
18 that process ongoing?
19 A.Yes,although the results of that testing will
20 not impact the decision on the tower design.As described
21 in my rebuttal testimony,the Company will use the new
22 tower.The tower testing will verify the tower design
23 and will not impact the cost of the project.
24 Q.Have you provided additional information that
25 describes the proposed resource decision?
957 Vail,Di-2nd Supp -7
Rocky Mountain Power
1 A.Yes.My supplemental direct and secondO2supplementaldirecttestimonyprovideanupdated
3 description of the network upgrades required to
4 interconnect the Wind Projects.Exhibit Nos.36,37 and
5 48 through 52 provide additional descriptions of the
6 network upgrade facilities.Because the Aeolus-to-
7 Bridger/Anticline transmission line has remained the same
8 throughout this proceeding,the information included in
9 my direct testimony fully describes that component of the
10 Transmission Projects.
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958 Vail,Di-2nd Supp -7a
Rocky Mountain Power
1 Examples of pro-forma contracts are attached as ExhibitO2No.53.The Company has not executed the final contracts
3 for the Transmission Projects.
4 Q.Does this conclude your second supplemental
5 direct testimony?
6 A.Yes.
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959 Vail,Di-2nd Supp -8
Rocky Mountain Power
1 Q.Are you the same Rick A.Vail who previouslyO2providedtestimonyinthiscaseonbehalfofRocky
3 Mountain Power ("Company"),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")to construct the Aeolus-to-Bridger/Anticline
11 transmission line and the network upgrades ("Transmission
12 Projects")needed to construct or acquire the Ekola
13 Flats,TB Flats I and II,Cedar Springs,and Uinta
14 projects,which are the four new wind resources ("Wind
15 Projects")included on the final shortlist for the 2017R
16 Request for Proposals ("RFP").Specifically,my testimony
17 responds to the April 11,2018,testimony filed by Mr.
18 James R.Dauphinais,on behalf of Monsanto,and Mr.
19 Bradley G.Mullins,on behalf of PacifiCorp Idaho
20 Industrial Customers ("PIIC").
21 Q.Please summarize your testimony.
22 A.First,many of the Transmission Projects risks
23 have decreased over the course of this case.Project
24 costs are now more certain,and final contracting and
25 construction is on-schedule;the Company has made
960 Vail,Supp-Reb -1
Rocky Mountain Power
1 substantial progress scoping,developing,and preparing
2 the projects to submit the next round of permit
3 applications necessary for construction and operation;
4 and the ongoing study process continues to affirm that
5 the Transmission Projects will deliver the expected
6 benefits.Based on its extensive experience developing
7 comparable transmission resources,the Company is
8 confident that it can deliver the Transmission Projects
9 on-time and at the cost estimates included in my
10 testimony.
11 Second,the Company did not mismanage its
12 generator interconnection queue or attempt to use its
13 generator interconnection queue to bias the outcome of
14 the 2017R RFP,as certain parties assert.The Company's
15 treatment of all projects in its generator
16 interconnection queue,whether bidders or not,was
17 consistent with the terms and
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24
25
961 Vail,Supp-Reb -la
Rocky Mountain Power
1 conditions of its Open Access Transmission TariffO2("OATT").
3 Third,the Company's estimated third-party
4 transmission revenues included in the economic analysis
5 are reasonable and consistent with the ratemaking
6 methodologies employed by the Federal Energy Regulatory
7 Commission ("FERC").
8 TRANSMISSION PROJECT RISK
9 Q.Mr.Dauphinais claims that the Transmission
10 Projects risks have "quite possibly"increased since he
11 filed direct testimony on December 18,2017.(Dauphinais,
12 Supp.Direct,page 5,lines 1-15.)Do you agree?
13 A.No.Relying on the additional network upgrades
14 identified after the final shortlist was established,Mr.
15 Dauphinais claims "as a general principle,the more
16 expensive and complex a project is,the greater the risks
17 involved."(Dauphinais,Supp.Direct,page 5,lines
18 12-15.)But his testimony ignores several relevant facts
19 that indicate decreasing risk.
20 First,the Company confirmed through a
21 competitive market solicitation that the cost estimate
22 for the Aeolus-to-Bridger/Anticline transmission line and
23 associated substations is valid.Because the cost of the
24 Aeolus-to-Bridger/Anticline line is approximately 85
25 percent of the total cost of the Transmission Projects,
962 Vail,Supp-Reb -2
Rocky Mountain Power
1 cost certainty for that piece decreases the cost risk forO2theTransmissionProjectsasawhole.
3 Second,since December 18,2017,the Company
4 completed all the interconnection restudies required for
5 the Wind Projects.Although the restudies indicate the
6 need for additional network upgrades,there is now
7 greater certainty-and therefore less risk-associated with
8 the required facilities and their costs.The
9 interconnection restudies also confirm that the network
10 upgrades are fairly routine projects that the Company
11 regularly performs in the ordinary course of business.
12 Third,the Company is steadily progressing
13 through the process to acquire necessary easements and
14 rights-of-way in parallel with the regulatory-approvals
15 process and,based on the progress to date,remains on
16 track to secure the necessary easements
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24
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963 Vail,Supp-Reb -2a
Rocky Mountain Power
1 and rights-of-way to support the construction schedule.O 2 Fourth,the Company performed additional
3 transmission studies that confirm that the construction
4 of the Transmission Projects will allow the
5 interconnection of all of the Wind Projects.Indeed,as
6 of today,the Company has completed nearly all of the
7 okay transmission studies that will occur,with the
8 exception of the Western Electricity Coordinating Council
9 ("WECC")studies that are required to occur in the season
10 before the line becomes operational.
11 Fifth,the Company has made significant
12 progress towards obtaining its remaining permits and
13 authorizations including the following:
14 o The Company received notice to proceed from the
15 Bureau of Land Management ("BLM")for 30 percent of
16 the Plan of Development appendices required for
17 construction.One additional group (Group 2)of
18 appendices have been through BLM review and are
19 awaiting final approval letter from BLM.The final
20 group of appendices (remaining 20 percent)will be
21 submitted for review and approval on schedule after
22 construction contractor selection and subsequent
23 input to the remaining appendices.
24 o The Company submitted the Class III Cultural report
25 to the BLM.This requirement is on track for
964 Vail,Supp-Reb -3
Rocky Mountain Power
1 completion in accordance with the project schedule.
2 o The Company received confirmation of the Aquatic
3 Resources Inventory from the U.S.Army Corps of
4 Engineers regarding acquisition of the required
5 wetlands permits.This significant progress,in
6 accordance with the project schedule,mitigates most
7 of the project permitting risk.
8 Mr.Dauphinais's simplistic assessment that the
9 project risk increased just because additional network
10 upgrades are needed ignores the substantial progress that
11 has occurred over the last several months and the fact
12 that the Company has been managing
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20
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965 Vail,Supp-Reb -3a
Rocky Mountain Power
1 and mitigating project risk from the beginning of this
2 case.When examined holistically,the costs and benefits
3 of the Transmission Projects are now more certain and the
4 development risks continue to decrease.
5 TRANSMISSION LINE NEED
6 Q.Mr.Dauphinais testifies that "for the first
7 time,"the Company claims "that there is a need for the
8 Aeolus-to-Bridger/Anticline line,even if the new Wind
9 Projects are not constructed,because it will improve
10 system performance and reliability and directly service
11 customers,"and that this "eleventh hour"claim should be
12 given no weight.(Dauphinais Supp.Direct,page 2,lines
13 17-22.)Is this a fair characterization of your
14 testimony?
15 A.No.Mr.Dauphinais's testimony ignores the fact
16 that the Company's direct and rebuttal testimonies
17 described extensively why there is a need for the
18 Aeolus-to-Bridger/Anticline transmission line with or
19 without the Wind Projects.In my direct testimony,I
20 explained that the Aeolus-to-Bridger/Anticline line is
21 necessary to relieve existing congestion on the system,
22 (Vail Direct,page 4,lines 2-5)and that without the new
23 transmission line the Company's ability to deliver
24 resources to load will remain constrained.(Vail Direct,
25 page 22,lines 20-21.)I further described how the North
966 Vail,Supp-Reb -4
Rocky Mountain Power
1 American Electric Reliability Corporation's and WECC'sO2standardsandcriteriainfluencedtheneedforthe
3 Aeolus-to-Bridger/Anticline line.(Vail Direct,page 4,
4 line 20-23.)The Company made it clear that the
5 Aeolus-to-Bridger/Anticline line has been an integral
6 component of the long-term transmission plan for the
7 region long before the Wind Projects were contemplated.
8 (Vail Direct,page 4,lines 14-23.)
9 I then reiterated these points in my rebuttal
10 testimony,responding explicitly to the argument that
11 there was no need for the Aeolus-to-Bridger/Anticline
12 line.(Vail Rebuttal,page 10,line 15 to page 14,line
13 9.)I testified that there is a need for the Aeolus-to-
14 Bridger/Anticline line independent of the Wind Projects
15 because the line will:(1)relieve congestion and
16 increase transmission capacity across Wyoming,allowing
17 interconnection
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24
25
967 Vail,Supp-Reb -4a
Rocky Mountain Power
1 of new generation resources and enabling more efficientO2andflexibledispatchandmanagementofexisting
3 resources;(2)provide critical voltage support to the
4 transmission system;(3)improve system reliability;and
5 (4)reduce energy and capacity losses.(Vail Rebuttal,
6 page 12,lines 1-22.)As further explained in my
7 supplemental direct testimony,the Aeolus-to-Bridger/
8 Anticline line and the Wind Projects are mutually
9 dependent on one another because the Wind Projects affect
10 the timing of the construction of the line,but not the
11 need.(Vail Direct Supplemental,page 6,line 16 to page
12 7,line 2.)Mr.Dauphinais ignores my testimony entirely
13 and,in doing so,mischaracterizes the record on this
14 point.
15 Q.Mr.Dauphinais also argues that the fact the
16 Aeolus-to-Bridger/Anticline line is identified in
17 long-term transmission plans does not mean that it will
18 "ultimately be needed."(Dauphinais Supp.Direct,page
19 10,lines 17-20.)How do you respond to this claim?
20 A.I disagree.While it is true that long-term
21 transmission plans evolve as circumstances change over
22 time,they remain the most important tool the Company has
23 for determining the need for transmission resources,
24 particularly because of the long lead time required for
25 permitting and construction of major transmission
968 Vail,Supp-Reb -5
Rocky Mountain Power
1 facilities.Mr.Dauphinais's casual dismissal of
2 transmission planning processes is contrary to
3 well-established requirements from both this Commission
4 and FERC,both of which require robust long-term planning
5 for transmission resources.
6 Q.Has the proposed timeline for construction of
7 Segment D of the Energy Gateway Project (which includes
8 the Aeolus-to-Bridger/Anticline line)changed as
9 dramatically as Mr.Dauphinais suggests?(Dauphinais
10 Supp.Direct,page 11,lines 1-13.)
11 A.No.In the 2015 Integrated Resource Plan
12 ("IRP"),filed on March 31,2015,Segment D was scheduled
13 to be in-service by 2024.This timing was the same in the
14 2015 IRP Update,filed on March 31,2016.In the 2017
15 IRP,the only change related to Segment D
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969 Vail,Supp-Reb -5a
Rocky Mountain Power
1 involved the accelerated construction of Segment D.2 (theO2Aeolus-to-Bridge/Anticline line)to take advantage of
3 production tax credits by enabling the interconnection of
4 additional wind resources.
5 Q.Are there any other regional transmission plans
6 that also indicate a need for the Aeolus-to-Bridge/
7 Anticline line exists?
8 A.Yes.The Aeolus-to-Bridger/Anticline line is
9 included in the most recent Regional Transmission Plan
10 prepared by the Northern Tier Transmission Group
11 ("NTTG"),which was published January 9,2018.
12 Q.Who is the NTTG?
13 A.The NTTG is a regional planning forum that
14 fulfills the transmission planning requirements of FERC
15 Order 1000.NTTG members include regional utilities,
16 consumer groups,and regulators.The Idaho Public
17 Utilities Commission is a member of NTTG.
18 Q.Why did the NTTG include the Aeolus-to-
19 Bridger/Anticline line in its most recent Regional
20 Transmission Plan?
21 A.NTTG concluded that the "NTTG area would be
22 reliably served in the year 2026 only by including"
23 several proposed transmission projects,including the
24 Aeolus-to-Bridger Anticline line.While the NTTG plan is
25 not intended to replace or supplant the Company's more
970 Vail,Supp-Reb -6RockyMountainPower
1 detailed integrated resource planning,the fact that the
2 Aeolus-to-Bridger/Anticline line is included in the
3 regional plan as a necessary resource provides additional
4 support for its construction.
5 INTERCONNECTION QUEUE
6 Q.Mr.Mullins claims that the Company excluded
7 some least costs projects from the 2017R RFP because of
8 the project's interconnection queue position.(Mullins
9 Supp.Direct,page 9,line 15 to page 10,line 4.)How do
10 you respond?
11 A.As required by FERC and PacifiCorp's OATT,
12 PacifiCorp adheres to a sequential queue process to
13 evaluate generator interconnection applications.More
14 specifically,under the OATT,to properly identify a
15 generator's interconnection requirements and determine
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23
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25
971 Vail,Supp-Reb -6a
Rocky Mountain Power
1 cost responsibility for system improvements in an area
2 with multiple proposed generator interconnections,each
3 project must be evaluated at full output,in sequential
4 order,and with the assumption that projects that are
5 higher in the interconnection queue and projects with
6 executed interconnection agreements are in-service.This
7 is critical in identifying the proper amperage and fault
8 duty required for circuit breakers,circuit switches,
9 etc.,as well as amperage requirements for substation bus
10 work and transmission lines.To evaluate a project in
11 isolation and out of sequential queue order would not
12 only be inconsistent with OATT requirements,but would
13 also result in deficient facility requirements and expose
14 the Company and its retail customers to considerable
15 costs for infrastructure upgrades that are required to
16 operate in a safe and reliable manner.
17 In restudying the interconnection queue with
18 the revised assumption that segment D.2 would be in
19 service by the end of 2020,the Company determined that
20 projects through queue position 0712 could reliably
21 interconnect with the construction of segment D.2 and
22 without the need to construct other elements of the
23 long-term transmission plan.Beginning with the system
24 impact study for queue position 0713,there is a need to
25 construct additional elements of the long-term
972 Vail,Supp-Reb -7
Rocky Mountain Power
1 transmission plan to allow reliable interconnection of
2 additional projects.
3 For example,the Q0713 system impact study
4 identified multiple 230 kilovolt ("kV")line overloads
5 for loss of the 500 kV elements,even after employing the
6 proposed Aeolus West generation dropping scheme.Other
7 significant improvements were identified as well.The
8 Q0713 project therefore triggers the need for substantial
9 mitigation in east Wyoming to interconnect.The study
10 determined that a new line from Aeolus to Clover,which
11 is part of the Company's long-term transmission plan for
12 this area,is necessary to mitigate the 500 kV outages.
13 Because these major system improvements cannot be
14 in-service by the 2020 timeframe identified in the RFP,
15 Q0713 could not meet the basic criteria to be included in
16 the final shortlist.
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25
973 Vail,Supp-Reb -7aRockyMountainPower
1 Given the sequential nature of interconnection
2 studies,all projects lower than Q0713 in the
3 interconnection queue that are located in the same
4 constrained area as Q0713 would require at least the
5 Aeolus to Clover line and,like Q0713,could not be
6 in-service by 2020.
7 Finally,as discussed by Mr.Rick T.Link,both
8 independent evaluators that oversaw the 2017R RFP process
9 agreed with the Company's assessment of the viability of
10 projects located lower in the interconnection queue than
11 Q0712.
12 Q.Mr.Mullins claims that the Company never
13 disclosed its "position with respect to the
14 interconnection queue"until January 31,2018.(Mullins
15 Supp.Direct,page 10,lines 5-10.)Is this true?
16 A.No.Mr.Mullins implies that the Company's
17 treatment of the interconnection queue was somehow novel
18 or a change from prior practice and therefore the Company
19 should have provided earlier notice as part of the 2017R
20 RFP.But there was nothing unusual about how the Company
21 treated its interconnection queue or performed the
22 restudies necessary to identify interconnection network
23 upgrades.As described above,the Company's treatment of
24 the queue was consistent with long-standing FERC
25 precedent and the clear terms of its OATT.
974 Vail,Supp-Reb -8
Rocky Mountain Power
1 Q.Mr.Mullins further claims that he "was underO2theimpressionthatallWindRFPbidswouldbescored or
3 evaluated on the same basis,with the Company being able
4 to then either equalize or mitigating the bidding
5 advantage otherwise available to a bidder with a higher
6 queue position."(Mullins Supp.Direct,page 13,lines
7 4-14.)Is there any basis for Mr.Mullins's "impression"?
8 A.No.Mr.Mullins does not describe the basis for
9 his impression,but,to be clear,the Company cannot
10 "equalize or mitigate"the fact that some projects are
11 higher in the interconnection queue than others.Such
12 preferential treatment is prohibited by the terms of the
13 Company's OATT.
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20
21
22
23
24
25
975 Vail,Supp-Reb -8aRockyMountainPower
1 Q.Mr.Dauphinais claims the Revised System Impact
2 Study and Final Facilities Study for the Boswell Wind
3 Projects show that the Company never really examined
4 whether Boswell could be interconnected with elements of
5 the Gateway West alone without Gateway South.(Dauphinais
6 Supp.Direct,page 9,lines 3-6.)How do you respond?
7 A.The Boswell Springs I-IV projects require
8 additional transmission facilities beyond the currently
9 proposed Aeolus-to-Bridger expansion to be completed in
10 2020.Completion of Energy Gateway South and the
11 Aeolus-to-Populus portion of the Energy Gateway West
12 expansion project will be required prior to
13 interconnecting the Boswell Springs I-IV projects.
14 Interconnection of the Boswell Springs I-IV projects
15 prior to completion of the listed incremental
16 transmission facilities would create system emergency
17 conditions.These transmission projects,which represent
18 several billion dollars of new capital,are not planned
19 to be in service until 2024.These costs were not
20 included in the analysis;however,the listed facilities
21 are required to be in-service prior to Boswell Springs
22 I-IV project interconnection to maintain system
23 reliability.
24 Q.Mr.Dauphinais testimony states:"Nothing in
25 Mr.Vail's supplemental and second supplemental direct
976 Vail,Supp-Reb -9
Rocky Mountain Power
1 testimony on behalf of RMP would lead me to change my
2 conclusions regarding the specific risks associated with
3 RMP's proposed Transmission Projects in this proceeding."
4 (Dauphinais Supp.Direct,page 2,lines 5-7).How do you
5 respond to his assertions?
6 A.As stated above,the Company has made
7 substantial progress in validating the project cost
8 elements of the project.With receipt of conditional
9 CPCNs in Wyoming,and progress in remaining permits and
10 also negotiations with landowners to obtain
11 rights-of-way,the risks to the project have declined
12 significantly in recent months.
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977 Vail,Supp-Reb -9a
Rocky Mountain Power
1 Q.If the Commission approves the CombinedO2Projects,Mr.Mullins recommends that the Commission
3 impose a condition to prohibit PacifiCorp from "recovery
4 of any costs associated with ongoing maintenance and
5 capital replacement the Transmission Projects,since
6 those costs were not considered in the benefits study...."
7 (Mullins Supp.Direct,page 5 lines 1-5.)How do you
8 respond?
9 A.The premise of Mr.Mullins's proposed condition
10 is incorrect-there are ongoing maintenance costs for the
11 transmission assets accounted for in the economic
12 analysis.The Company has a number of preventative and
13 corrective maintenance programs to extend the life of
14 transmission assets.The new transmission assets will be
15 maintained and as appropriate,the Company should be
16 allowed to recover the associated costs.The Company
17 currently operates and maintains 16,500 miles of
18 transmission and over 1,000 substations.The addition of
19 the transmission projects will not materially impact the
20 overall capital maintenance budget for the system.The
21 Company focuses on identifying efficiencies and
22 prioritizes spend within the capital maintenance program
23 and does not expect an increase to overall system costs
24 associated with the new transmission projects.
2 5 OATT REVENUES
978 Vail,Supp-Reb -10
Rocky Mountain Power
1 Q.Mr.Mullins again questions the Company's
2 assumption that the Company will recover 12 percent of
3 the revenue requirement of the Transmission Projects
4 through its OATT rates.(Mullins Supp.Direct,pages
5 28-30.)How do you respond?
6 A.In accordance with FERC policy,the actual
7 costs of the transmission projects will flow into the
8 annual update of PacifiCorp's FERC formula rate once the
9 projects are in service.Mr.Mullins continues to focus
10 on only the economics of the Transmission Projects and
11 ignores the system-wide benefits provided to all
12 transmission customers.As described above,the
13 Aeolus-to-Bridger/Anticline line will:(1)relieve
14 congestion and increase transmission capacity across
15 Wyoming,allowing interconnection and integration of new
16 generation resources and enabling more efficient dispatch
17 of and greater
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979 Vail,Supp-Reb -10a
Rocky Mountain Power
1 flexibility in managing existing resources;(2)provide
2 critical voltage support to the transmission system;(3)
3 improve system reliability;and (4)reduce energy and
4 capacity losses.
5 Q.Mr.Mullins claims,"Mr.Vail's description of
6 PacifiCorp's formula rate overlooks the way that costs
7 get allocated between point to point and network
8 integration transmission customers."(Mullins Supp.
9 Direct,page 28,lines 4-5.)Do you agree with Mr.
10 Mullins's argument?
11 A.No.Mr.Mullins's argument misunderstands how
12 transmission rates are calculated.Mr.Mullins's argument
13 assumes that the construction of the Wind Projects will
14 increase the load served by network resources and
15 therefore reduce the loads served by front office
16 transactions that rely on point-to-point transmission.He
17 then speculates that this would increase PacifiCorp's
18 network service load but the Company would still have to
19 pay for the same amount of point-to-point transmission
20 service used to deliver front office transactions.
21 Q.Is this a valid assumption?
22 A.No.Transmission costs are based on customers'
23 relative share of load at the time of the transmission
24 system peak plus long-term point-to-point capacity.
25 Network transmission capacity is measured monthly at time
980 Vail,Supp-Reb -11
Rocky Mountain Power
1 of system peak.Therefore,over time loads typically grow
2 or shrink depending on many factors,including such items
3 as population change,business mix,and the effects of
4 weather.The addition of generation capacity by itself
5 does not change a customer's load share of the
6 transmission costs.PacifiCorp continually monitors and
7 adjusts its transmission requirements,as do all other
8 third-party customers.PacifiCorp's relative share of
9 transmission costs are dependent on its load growth
10 relative to third parties.Historically,allocation of
11 PacifiCorp's use of transmission has been around 12
12 percent.Recent trends indicate that the Company's
13 percent might be shrinking and the amount allocated to
14 third parties increasing.Adding generation capacity is
15 not expected to impact this trend.As a result,
16 PacifiCorp's share of
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981 Vail,Supp-Reb -lla
Rocky Mountain Power
1 additional transmission costs would not be expected toO2increaserelativetothirdpartiesbasedonjust
3 constructing additional generation and transmission
4 assets.
5 Q.Mr.Mullins claims that the cost of the
i
6 Transmission Projects maybe directly assigned to
7 PacifiCorp.(Mullins Supp.Direct,page 28,line 20 to
8 page 29,line 2.)Is this a material risk?
9 A.No.Once again,Mr.Mullins appears to
10 misunderstand how the Company's OATT formula rates are
11 calculated.As mentioned above,PacifiCorp's transmission
12 costs are recovered through a formula rate mechanism
13 approved by FERC,so the risk of these costs being
14 directly assigned is extremely low given how transmission
15 costs are incorporated into the formula rate.There is no
16 precedent for directly assigning transmission resource
17 costs to the Company.
18 Q.Mr.Mullins states that the Wind Projects will
19 cause the Company's load to increase by about 450
20 megawatts per month,which will increase the Company's
21 relative share of transmission costs.(Mullins Supp.
22 Direct,page 29,lines 9-15.)Is this correct?
23 A.No.As noted above,the addition of generation
24 resources does not necessarily mean that the Company will
25 increase its share of the transmission usage.Mr.
982 Vail,Supp-Reb -12
Rocky Mountain Power
1 Mullins's own testimony undermines his argument when he
2 claims that PacifiCorp's peak loads are forecasted to be
3 down approximately 14 percent by 2026.(see Mullins Supp.
4 Direct,page 35,line 20 to page 36 line 2.)As
5 previously described,transmission costs are allocated by
6 demand during the transmission system peak.Therefore,if
7 peak loads are decreasing,as Mr.Mullins claims,then
8 the Company's share of transmission costs will also
9 decrease.Mr.Mullins cannot simultaneously argue that
10 the new Wind Projects will increase transmission costs
11 paid by retail customers while also arguing that
12 decreasing load will decrease transmission costs paid by
13 retail customers.The Company estimated the third-party
14 transmission revenue based on historical data that
15 accounts for the many factors that impact the Company's
16 share of transmission costs.Mr.Mullins's attempt to
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983 Vail,Supp-Reb -12a
Rocky Mountain Power
1 isolate the impact of individual changes in transmission
2 usage,without also accounting for offsetting changes,
3 undermines the credibility of his conclusions.
4 Q.Does this conclude your supplemental rebuttal
5 testimony?
6 A.Yes.
7
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984 Vail,Supp-Reb -13
Rocky Mountain Power
1 (The following proceedings were had in
2 open hearing.)
3 MR.LOWNEY:And Mr.Vail is available for
4 cross-examination.
5 COMMISSIONER ANDERSON:Mr.Budge.
6 MR.BUDGE:Thank you.
7
8 CROSS-EXAMINATION
9
10 BY MR.BUDGE:
11 Q Good afternoon.
12 A Good afternoon.
13 Q Just a couple of minor questions,if I
14 may.Is my understanding correct that the Company won't
15 undertake to construct the projects until all of the
16 regulatory approvals have been obtained?
17 A I guess you'd have to define all the
18 regulatory approvals.I mean,what we're trying to do is
19 get the Wyoming CPCN and,obviously,the other CPCNs in
20 these states when you have different conditional use
21 permits in a county,but yes,I mean,our intent is to
22 not actually execute the contracts,start construction of
23 the transmission line until we have the regulatory
24 approvals we've outlined in our testimony.
25 Q Okay;so if the commissions approve it,
CSB REPORTING 985 VAIL (X)
208.890.5198 Rocky Mountain Power
1 that would be one of them and are there also someO2environmentalpermittingrequirementsthatarenecessary
3 before the project can commence?
4 A There are and,again,kind of spread
5 throughout my testimony,I think we've identified,you
6 know,what the remaining environmental permitting
7 requirements are along with any of the county permits.
8 The other kind of big one is just the Wyoming Siting,
9 Industrial Siting,Council permit as well,so we've tried
10 to outline and provide those in the testimony.
11 Q Okay;so it's environmental permitting,
12 regulatory approval,whatever siting requirements be on a
13 county land use basis,I suppose,and I suppose all of
14 the easements in place as well?
15 A That's correct.
16 Q So once all of those things are in place,
17 then the Company would undertake to proceed with
18 construction of the project?
19 A So the big key and,again,I'll just kind
20 of clarify there,the big key will be obtaining all the
21 right of ways and getting the final CPCN out of the State
22 of Wyoming so that we actually have the permission in the
23 State of Wyoming to build a project in their state.
24 Q So what percent of the right of ways do
25 you have in place at this time,approximately?
CSB REPORTING 986 VAIL (X)
208.890.5198 Rocky Mountain Power
1 A I honestly don't know that off the top ofO2myhead.From a transmission line perspective,I believe
3 about 49 percent of it is federal lands.Obviously,
4 we've been in the federal permitting process for,boy,
5 nine years,going on ten years,so we have that piece of
6 it certainly locked up.I think you heard mentioned,
7 we've definitely come to some agreements with some of the
8 larger private landowners in the State of Wyoming.I
9 know we're still working through the details of that
10 right of way,so from a percentage,I don't have that off
11 the top of my head,but we are making significant
12 progress,and I would just note,I think as Cindy just
13 mentioned,because we've been able to have some of those
14 conversations with the landowners,we feel like we're
15 still right on schedule,which would be typical for a
16 140-mile long transmission line build.
17 Q So these various things that you need to
18 have in place before you proceed,do you feel that you're
19 on schedule to the point that it's reasonably likely that
20 you could get the project built and on-line by year-end
21 2020?
22 A Yes,we do.
23 MR.BUDGE:That's all I had.Thank
24 you.
25 COMMISSIONER ANDERSON:Thank you,Mr.
CSB REPORTING 987 VAIL (X)
208.890.5198 Rocky Mountain Power
1 Budge.Mr.Williams.O 2 MR.WILLIAMS:Mr.Chairman,thank you.
3
4 CROSS-EXAMINATION
5
6 BY MR.WILLIAMS:
7 Q Good afternoon,Mr.Vail.On page 1 of
8 your supplemental rebuttal testimony,if could turn to
9 that,and on line 21 you make the statement that the
10 Company is confident that it can deliver the transmission
11 projects on time and at the cost estimates included in
12 your testimony,and this is simply a reaffirmation of
13 your rebuttal testimony at page 15,again expressing your
14 confidence that the Company will deliver the projects at
15 or below cost estimates and in fact,you give a couple of
16 examples of how the Company has done so on transmission
17 investments,so my question is given the level of
18 confidence that you have on that,I assume that if the
19 Commission granted you a certificate with a hard cap at
20 the cost estimates that the Company would proceed;would
21 that be --would the Company proceed,I guess,if hard
22 caps were established?
23 A I don't believe that's been the Company's
24 position.I think as we've talked about on the
25 stipulation,that's still an area where --
CSB REPORTING 988 VAIL (X)
208.890.5198 Rocky Mountain Power
1 Q Let me rephrase my question.You statedO2greatconfidenceinyourabilitiestobuildatorbelow
3 estimates.Assume you get a certificate with a hard cap
4 at your cost estimates,would the Company proceed?
5 A I don't know if I'm the one to answer that
6 to be honest with you.I don't know what the policy
7 would be.Again,it would depend on what the hard cap
8 is,but we have not agreed,the Company has not agreed,
9 to a hard cap.
10 Q You're not understanding my question.
11 A I'm sorry.
12 Q My question is if the Commission granted
13 you a certificate with a condition that the hard cap was
14 at your cost estimates,would the Company build?
15 A Again,I wouldn't --I'd probably defer
16 that question to Ms.Crane as the CEO of Rocky Mountain
17 Power.
18 Q And if she asked you for your
19 recommendation,what would your recommendation be?
20 A Yeah,I think we've talked a little bit
21 about some of the different challenges you have when you
22 build a long-term transmission project.Certainly,I
23 feel like we are at a point from a permitting
24 perspective,from a contracting perspective,from a bid
25 perspective,and even from a design perspective that our
CSB REPORTING 989 VAIL (X)
208.890.5198 Rocky Mountain Power
1 estimates are in line.We've been able to go out to theO2marketandgetbidsbackthatarematchingourcurrent
3 estimates.I would just like to,again,point out from a
4 hard cap perspective,when you get out into building the
5 actual transmission line and you do come across different
6 conditions out in the field,things can happen.
7 Certainly,our contracts that we put in place and the
8 controls that we put in place to monitor any issues that
9 come up during construction,I feel like we have very
10 good controls around that,but,you know,there are
11 things that can happen on a large scale project,so I'm
12 not sure how else to answer that question.
13 Q I'm trying to determine with your answer,
14 it seemed to be both a cup half full and cup half empty
15 type of answer,is that a confident answer or not a
16 confident answer?
17 A Again,I'd reiterate,it's a confident
18 answer.The only thing I would say is that in my mind,
19 when you put a hard cap on a project and yet additional
20 incremental prudent costs happen when you get out in the
21 field and you need to do that to be able to finish the
22 project,if those costs are prudent and it wasn't from
23 some kind of mismanagement or fault on the Company's
24 perspective,in my mind,that should not be an automatic
25 disallowance in a rate environment.
CSB REPORTING 990 VAIL (X)
208.890.5198 Rocky Mountain Power
1 Q But that's not my question.Let's say 60
2 days from now you get the order that says you can do it,
3 but you're hard capped at the costs and Cindy Crane calls
4 you into the office and says do we go or no go,what do
5 you think?
6 A Again,that's a hypothetical.
7 Q It is.
8 A You know,my input on that based on where
9 we're at today is I would want to understand what that
10 hard cap was.Is it just on the transmission project.
11 Are there any other conditions that have been placed on
12 it,so,again,not easy to answer just because there can
13 be a lot different circumstances to it.
14 Q Okay,if you would turn to page 6 of your
15 supplemental rebuttal testimony and here you start
16 discussing the OATT requirements and the selections and
17 it goes on for several pages,but in essence,then,at
18 page 8,you get to --well,a couple of things.First of
19 all,let me ask this:So projects that were below the
20 queue 0713 mark would be what I would describe as in the
21 money.Do you understand what I mean by that?
22 A I do not.
23 Q Okay;so if you have a transmission queue
24 interconnection that is 713 or below,you don't get hit
25 with additional transmission system upgrade costs,but if
CSB REPORTING 991 VAIL (X)
208.890.5198 Rocky Mountain Power
1 your queue position was above that,then now you're going
2 to have priced into your bid or in your case you couldn't
3 accept those bids that were above that transmission queue
4 position;correct?
5 A So I would just clarify when you're
6 talking up and down in the queue,so 713 in my mind is a
7 higher number than,say,the one that is before that,
8 which is 712,so I mean,to clarify,once you get to 713,
9 anyone further down the queue does have additional
10 transmission segments that would need to be placed in
11 service for them to be able to physically interconnect to
12 the transmission system.
13 Q Right;so in my words,those are out of
14 the money and the ones above that are in the money?
15 A I just wanted to clarify that we were
16 saying the same thing.
17 Q Do you know the queue positions for the
18 three Company-owned wind projects that were,my words,in
19 the money?
20 A I'm sure I have them in here.I would
21 just be careful with that,so those queue numbers,the
22 original interconnection requests were actually not made
23 by the Company.They were made by a different customer
24 that held that queue position.
25 Q But that's not my question.My question
CSB REPORTING 992 VAIL (X)
208.890.5198 Rocky Mountain Power
1 is simply where were they?Were they above or below thatO2713dividingline?
3 A They have a higher position in the
4 queue.
5 Q Which I think means a lower number.
6 A Lower number,higher position,yes,you're
7 right.
8 Q Okay,we're talking the same,so when did
9 the Company --I appreciate that you didn't make those
10 queue applications,someone else did,but the Company
11 stepped into those projects or acquired the rights to
12 those projects,do you know when the Company made those
13 acquisitions or at least letters of intent or whatever
14 established your vested interest in those three queue
15 positions?
16 A I personally do not know that timing.
17 That would be a question to ask Mr.Teply.
18 Q Would you accept,subject to check,that
19 those --the Company acquired the rights in those three
20 projects in the spring of 2017?
21 A Again,subject to whatever confirmation
22 you can get from Mr.Teply,it sounds about accurate.
23 Q Let's assume,subject to check,that those
24 were,and do you also know when the Company issued its
25 notice,published its first notice,to the world that it
CSB REPORTING 993 VAIL (X)
208.890.5198 Rocky Mountain Power
1 was going to start a 2017 RFP?
2 A I do not know the exact date of that.You
3 would have to ask Mr.Link.That's his area of
4 responsibility.
5 Q Well,would you accept,subject to check,
6 that the notice in Utah came out also in the spring of
7 2017 and the actual notice then followed on September
8 27th,2017?
9 A Okay.
10 Q So do you find it odd that the Company
11 acquired queue positions for projects that were below
12 this cut line,if you will,roughly within 90 days of
13 when the Company is going out for an RFP?
14 A No,I don't.
15 Q You don't find that interesting?
16 A I don't.
17 Q When the Company went out to acquire
18 rights in wind projects as opposed to submit its own
19 queue positions to itself or to the transmission segment
20 of the Company,was evaluation of queue positions a
21 factor when the Company moved to acquire wind projects?
22 Did they assign any value?Did they evaluate queue
23 positions and then assign any value to queue positions?
24 A Again,that's a question I think you would
25 have to ask Mr.Teply.Let's just be clear,from a
CSB REPORTING 994 VAIL (X)
208.890.5198 Rocky Mountain Power
1 transmission standpoint,right,I manage the generator
2 interconnection queue and so as those requests come in,
3 obviously,it's my job to manage that queue per our open
4 access transmission tariff.
5 Q But Mr.Link,I mean,you have four pages
6 of testimony starting at page 6 about the interconnection
7 queue and how that works.
8 A Right,and I am certainly responsible for
9 that queue.You're asking about assigning some kind of
10 importance based on queue positions,so maybe I'm not
11 understanding your question.
12 Q No,I'm trying to talk to you about queue
13 positions and how important they were in the selection
14 process and you keep --you have a lot of testimony on
15 this,yet you keep deflecting to Mr.Teply.I guess I
16 don't understand.I thought you --
17 MR.LOWNEY:Objection.This witness is
18 not the witness that ran the RFP process.That was Mr.
19 Link.This witness is not the witness who managed the
20 Company's benchmark projects that were submitted into the
21 RFP.That was Mr.Teply.I think what Mr.Vail has
22 explained is that he's on the transmission side of the
23 Company.He manages the interconnection queue as those
24 requests come in from people like Mr.Teply or other
25 bidders in the RFP process,so I think to the extent
CSB REPORTING 995 VAIL (X)
208.890.5198 Rocky Mountain Power
1 there's questions about the interconnection queue as it's
2 managed from the transmission side of the Company,Mr.
3 Vail is ready to answer those questions.
4 If there's questions about how that
5 transmission queue affected the price scoring in the RFP
6 process,that would be Mr.Link.To the extent he's
7 asking about how the benchmark resources that were bid
8 into the RFP were impacted by the interconnection queue
9 positions,that would be Mr.Teply.
10 MR.WILLIAMS:Well,then we'll proceed
11 with Mr.Teply.'
12 Q BY MR.WILLIAMS:If you could turn to
13 page 8 of your testimony and on this page,especially
14 towards the bottom,you take issue with Mr.Mullins'
15 testimony regarding the fairness of the RFP bid
16 evaluations.Apparently that's not your area of
17 expertise,but nonetheless,you take issue with that and
18 you state at line 24,"to be clear,the Company cannot
19 'equalize or mitigate'the fact that some projects are
20 higher in the interconnection queue than others.Such
21 preferential treatment is prohibited by the terms of the
22 Company's OATT."
23 Now,Mr.Vail,my impression is that
24 you're somebody that is supposed to stay apprised of
25 regional transmission issues for the Company.Is that
CSB REPORTING 996 VAIL (X)
208.890.5198 Rocky Mountain Power
1 someone else or is that your area of expertise?
2 A That would be my area.
3 Q Okay,and are you familiar with Portland
4 General Electric's Cascade Crossing transmission line
5 situation where PGE was facing a similar RFP situation
6 and instead of letting bidders with earlier queue
7 positions gain a competitive RFP advantage that PGE
8 instead applied to FERC and was granted a waiver of its
9 OATT requirement to sequentially evaluate
10 interconnection?
11 A Again,just to be very clear there,to do
12 a sequential evaluation,yes.
13 Q So I'd like to hand you what's been marked
14 as Exhibit 308,which I will describe for the record as
15 FERC Order Granting Request for Limited Waiver to
16 Portland General Electric in Docket No.ER12-1293-000.
17 (Mr.Mullins distributing documents.)
18 (PIIC Exhibit No.308 was marked for
19 identification.)
20 THE WITNESS:I will state,obviously,I
21 haven't read this order myself and I'm not a lawyer,
22 but --
23 Q BY MR.WILLIAMS:And I won't ask any
24 legal questions.Now,if you could turn to page 3 of
25 this order,this FERC order --I apologize,page 4 of the
CSB REPORTING 997 VAIL (X)
208.890.5198 Rocky Mountain Power
1 FERC order and it's --well,my page number footing on
2 the exhibit didn't show up,but for the FERC order,it's
3 page 4.At the very bottom,paragraph 11,I'm going to
4 read this to you.It says,"Portland General states that
5 while the 'first-come,first-served'approach of Order
6 No.2003 made sense at the time it was issued,such
7 approach may have inadvertently led developers to reserve
8 space in interconnection queues for projects that were
9 not commercially viable.Portland General adds that in
10 Order No.890,the Commission observed that coordinated
11 studies could be more beneficial to transmission planning
12 than individual studies performed iteratively,"and then
13 finally,as I've underlined a section down in paragraph
14 12,"First,all customers in the Cascade Crossing queue
15 will have the benefit of a general study while they wait
16 to learn if their proposals have been selected";so my
17 question to you is did your Company ever consider the
18 same strategy as PGE did to seek an OATT waiver in order
19 to "equalize and mitigate"the bias that transmission
20 queuing otherwise brings to competitive bidding
21 situations?
22 A So let's talk about this on two different
23 levels,so did we consider it?You know,if you look at
24 the way our Aeolus transfer path capability assessment
25 was performed,in essence,it is a queue study.It is a
CSB REPORTING 998 VAIL (X)
208.890.5198 Rocky Mountain Power
1 cluster study similar to what FERC granted PGE the
2 ability to do here,and so what we've done is we've taken
3 projects that you need to account for being in service.
4 A number of these projects could --kind of the first
5 question is could they meet the commercial operation
6 date,so trying to get them in service in 2020.
7 Electrically,they're electrically in the
8 same area,so if you look at it,it really is almost a
9 cluster study and so we have a transfer capability
10 assessment that we did that is in that geographic area
11 with those different resources,and then we have
12 interconnection studies that were performed individually
13 on each of the projects,so I would submit in a sense,
14 you know,we have done,in essence,a cluster study
15 primarily to determine how much generation could be
16 interconnected behind a constraint and then how much
17 transfer capability we would be able to get across that
18 constraint.
19 At the end of the day,though,we still
20 have to honor the serial nature of our generation and
21 interconnection queue,so even if we study it as a
22 cluster,we have to allow for space based on queue
23 position and queue order,and I don't see a way from a
24 FERC perspective that PacifiCorp can get around that.
25 That is stated right in our open access transmission
CSB REPORTING 999 VAIL (X)
208.890.5198 Rocky Mountain Power
1 tariff.
2 Q So Mr.Vail,I thought I asked you a
3 simple question is did you ever consider the same
4 strategy of seeking an OATT waiver in order to do a
5 comprehensive transmission study and I take it from that
6 long answer the conclusion is no?
7 A Again,not what I said,so what I said is
8 I feel like we did a comprehensive transmission study.
9 We followed our open access transmission tariff,and I'd
10 just also note that seeking a waiver from FERC is
11 certainly not,you know,write them a letter and get an
12 answer back in a two-week process.Our experience in
13 getting a waiver from FERC has been a nine-to 12-month
14 process,which involves public input,public comment
15 until you finally get an answer back from FERC.
16 With the timelines that we've been on in
17 this project and,again,the fact at the end of the day
18 FERC is going to come back and still tell you,you have
19 to meet the serial nature of your queue,I feel like in a
20 sense,we have met the majority of what they allowed PGE
21 to do here and,again,did we discuss it,yes.Did we
22 want to go and seek that waiver,no,we did not.It
23 would not have changed the answer that we came back with.
24 Q But you did have time to identify projects
25 that had a lower queue rating and moved to acquire those;
CSB REPORTING 1000 VAIL (X)
208.890.5198 Rocky Mountain Power
1 is that not correct?O 2 MR.LOWNEY:Objection.This witness did
3 not testify to that.He deferred that question to Mr.
4 Teply.
5 MR.WILLIAMS:My apologies.I withdraw
6 that question.No further questions.
7 COMMISSIONER ANDERSON:Thank you,Mr.
8 Williams.Mr.Olsen.
9 MR.OLSEN:No questions.
10 COMMISSIONER ANDERSON:Staff.
11
12 CROSS-EXAMINATION
13
14 BY MR.KARPEN:
15 Q Good afternoon,Mr.Vail.
16 A Good afternoon.
17 Q I'm correct in noting that the Staff and
18 the Company have stipulated that this project should go
19 ahead in all regards with the exception of the imposition
20 of a hard cap;is that your understanding?
21 A That's correct.
22 Q And you understand that Staff's position
23 with regard to a hard cap --actually,let me rephrase
24 that.Is it your understanding that Staff's position
25 with regard to a hard cap is due to the risk of cost
CSB REPORTING 1001 VAIL (X)
208.890.5198 Rocky Mountain Power
1 overrun,potential cost overrun?
2 A Yes.
3 Q You had mentioned to Mr.Williams that
4 you're confident that the Company will deliver its
5 transmission projects,which is the portion that you're
6 responsible for,at or below cost;is that right?
7 A That's correct.
8 Q In your direct rebuttal on page 14,you
9 respond to Staff witness Mr.Keller who has expressed
10 concern over those cost overruns and construction delays,
11 and you note that in the past five years,the Company has
12 completed two significant and similar Energy Gateway
13 transmission projects.You compare them in regards to
14 requiring a NEPA-compliant environmental impact
15 statement,record of decision,plan of development,right
16 of way acquisition,and you talk that they came in on
17 time;is that accurate?
18 A Yes.
19 Q Over those same past five years,has the
20 Company completed any other transmission projects greater
21 than 20 miles in length?
22 A Yeah,there's probably a couple of
23 segments out there that have been greater than 20 miles.
24 I don't know them off the top of my head.
25 Q Are you aware of any projects that have
CSB REPORTING 1002 VAIL (X)
208.890.5198 Rocky Mountain Power
1 exceeded the construction budget or failed to meet that
2 initial construction schedule?
3 A Boy,again,off the top of my head,we
4 have had some delays on our Wallua to McNary project.
5 Primarily,they have been permitting delays.I don't
6 know exactly how many years we've had to push that out,
7 but from the Wallua to McNary project,we certainly
8 hadn't had all of the federal permitting activities as
9 far along as we have with this project,but I do believe
10 Wallua to McNary has been pushed out.
11 Q What if I said Vantage to Pomona Heights
12 project?
13 A Vantage to Pomona is another transmission
14 project that has been delayed.
15 Q That's been about a year behind;is that
16 right?
17 A That's correct.
18 Q And then maybe the Red Butte No.2 line?
19 A No,the Red Butte No.2 line,I believe,
20 was built on time and under budget.
21 Q Now,if I said to you that in PacifiCorp's
22 transmission system plan that it released November 15th,
23 2011,that it reported to various commissions that the
24 status of that project was that it should have been
25 completed by June of 2014 and its actual completion date
CSB REPORTING 1003 VAIL (X)
208.890.5198 Rocky Mountain Power
1 was June of 2015,would you believe that?
2 A Yeah,I would.I guess,again,you'd kind
3 of have to ask and I would have to go back and research
4 it to understand one of the reasons for that project
5 being pushed out.If you're referring to the Sigurd to
6 Red Butte project,I know one of the main drivers behind
7 that was to alleviate a transmission planning TPL 004-1
8 violation,and so if the load growth didn't happen as
9 quickly and materialize in the summer of 2013,then you
10 would have had the opportunity to push the date of that
11 project out another year and,again,subject to check,I
12 believe that that is actually what happened.It was a
13 decision to delay it for one year not due to construction
14 issues or permitting issues.It was a business decision
15 based on the need and timing of the project.
16 Q But needless to say,there are several
17 transmission projects the Company has undertaken that
18 have not met their proposed schedule;is that accurate to
19 say?
20 A I would just clarify,and I am not trying
21 to not answer the question,have transmission projects
22 missed their time frame,yes,they have,but,again,I
23 think it's important to understand why those delays have
24 happened.
25 Q Sure;so potentially permitting issues,
CSB REPORTING 1004 VAIL ()C
208.890.5198 Rocky Mountain Power
1 right of way issues,clearance from various commissions,
2 just various scheduling --
3 A Or actual business decisions due the
4 timing of load or contractor resources and availability
5 on the market to be able to get those resources,so there
6 are certainly reasons,some within the Company's control,
7 actual business decisions,some of them that aren't.
8 Q Now,when you talk about actual business
9 decisions,are there any tools that the Company has in
10 its toolbox that could hurry up a construction project,
11 say we need to have this segment done in the next month,
12 let's authorize unlimited overtime,have the workers go
13 work around the clock,something of that nature?
14 A I've never seen an issuance like that
15 other than a true emergency situation to keep the lights
16 on,so,you know,again,I'm not the one responsible for
17 the contract crews or even our own Company crews,but
18 other than keeping the lights on,I don't know of a
19 situation where we've,you know,thrown money at it.
20 That is not the way we do business.
21 Q So let's say that,hypothetically
22 speaking,we're at a certain point where there needs to
23 be a segment of this project that needs to be completed
24 in order for the Company to be able to fully qualify for
25 its PTC benefits and I'm assuming,and correct me if I'm
CSB REPORTING 1005 VAIL (X)
208.890.5198 Rocky Mountain Power
1 wrong,the Company might do a similar calculus and say we
2 can pay this much overtime or we can just delay the
3 project for a month or two and finish it in March,it
4 will be fine,would it be accurate to say the Company
5 might do that calculation?
6 A I mean,one,you're asking me to
7 speculate,but two,I just --
8 Q Just hypothetically.
9 A I would just like to be very clear,
10 though,that the EPC contracts we put in place have both
11 a price and performance piece to those,and we monitor
12 those all along.Plan A,no question,is not to get to
13 the last minute and try to have,you know,a bunch of
14 people scramble around to try to meet some in-service
15 date.We are very careful with our contracts.We're
16 very careful about who bids our contracts and,you know,
17 again,we try to put as many controls and manage that
i
18 contract throughout the life of the project as we
19 possibly can,so hypothetically,if,you know,I don't
20 know,a volcano blew up in Wyoming,since there's one
21 blowing up in Hawaii,I guess you would have to come back
22 and make some kinds of decisions,but,again,the Company
23 wouldn't arbitrarily blow the budget of this project
24 without coming back to our commissions and say this is a
25 significant material change.This is an emergency-type
CSB REPORTING 1006 VAIL (X)
208.890.5198 Rocky Mountain Power
1 situation,and then I think the evaluation would have to
2 be made at that point.I don't see that the Company
3 would make that unilaterally on its own.
4 MR.KARPEN:Thank you,Mr.Vail.That's
5 all I have.
6 THE WITNESS:Thank you.
7 COMMISSIONER ANDERSON:Thank you,Mr.
8 Karpen.Any questions?Redirect?
9 MR.LOWNEY:No redirect.
10 COMMISSIONER ANDERSON:Thank you very
11 much.
12 COMMISSIONER RAPER:Thank you.
13 (The witness left the stand.)
14 COMMISSIONER ANDERSON:You may call your
15 next witness.
16 MS.McDOWELL:Before we do that,I'd ask
17 whether our witness Cindy Crane could be excused at this
18 point.She has a plane she needs to catch to get to
19 another meeting and I guess if the issue is just whether
20 anybody would need to re-call her,we could have her
21 available by telephone at another time.
22 COMMISSIONER ANDERSON:Which witness?
23 MS.McDOWELL:Cindy Crane.
24 COMMISSIONER ANDERSON:Cindy Crane.Is
25 there any objection?
CSB REPORTING 1007 VAIL (X)
208.890.5198 Rocky Mountain Power
1 MR.WILLIAMS:No objection.
2 MR.OLSEN:No objection.
3 COMMISSIONER ANDERSON:No objection,so
4 be it.
5 MS.McDOWELL:Thank you.
6 COMMISSIONER KJELLANDER:And no
7 telephone.
8 MS.McDOWELL:No telephone,okay,so it
9 sounds like nobody needs to talk to her.
10 COMMISSIONER KJELLANDER:Fair enough,but
11 let's don't even bring up telephones,okay?
12 MS.McDOWELL:I will never do it again,I
13 promise.
14 COMMISSIONER ANDERSON:So she's excused.
15 MS.McDOWELL:Thank you.
16 COMMISSIONER ANDERSON:Thank you for
17 that.You may call your next witness.
18 MR.LOWNEY:The Company calls Chad Teply.
19
20
21
22
23
24
25
CSB REPORTING 1008 COLLOQUY
208.890.5198
1 CHAD A.TEPLY,
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 MR.LOWNEY:
9 Q Mr.Teply,could you please state and
10 spell your name for the record?
11 A Sure.My name is Chad Teply,C-h-a-d
12 T-e-p-1-y.
13 Q And how are you employed,Mr.Teply?
14 A I'm employed by Rocky Mountain Power as
15 their senior vice president of strategy and
16 development.
17 Q And in that capacity,did you file direct
18 testimony in this case in June of 2017?
19 A I did.
20 Q And did you also file rebuttal testimony,
21 supplemental direct testimony,second supplemental direct
22 testimony,and supplemental rebuttal testimony?
23 A I did.
24 Q And do you have any additions or
25 corrections to that testimony today?
CSB REPORTING 1009 TEPLY (Di)
208.890.5198 Rocky Mountain Power
1 A I do not.
2 Q And if I were to ask you the questions
3 that are set forth in that prefiled testimony,would your
4 answers be the same?
5 A Yes,they would.
6 MR.LOWNEY:Commissioner Anderson,I
7 would move that the prefiled testimony and exhibits of
8 Mr.Teply be spread upon the record as if read.
9 COMMISSIONER ANDERSON:Without objection,
10 we will spread Mr.Teply's testimony across the record
11 and the exhibits.
12 (Rocky Mountain Power's exhibits sponsored
13 by Mr.Chad Teply were admitted into evidence.)
14 (The following prefiled direct,rebuttal,
15 supplemental direct,second supplemental direct,and
16 supplemental rebuttal testimonies of Mr.Chad Teply are
17 spread upon the record.)
18
19
20
21
22
23
24
25
CSB REPORTING 1010 TEPLY (Di)
208.890.5198 Rocky Mountain Power
1 Q.Please state your name,business address,and
2 present position.
3 A.My name is Chad A.Teply.My business address
4 is 1407 West North Temple,Suite 310,Salt Lake City,
5 Utah 84116.My position is Vice President of Strategy and
6 Development for Rocky Mountain Power ("Company"),a
7 division of PacifiCorp.
8 QUALIFICATIONS
9 Q.Briefly describe your education and business
10 experience.
11 A.I have a Bachelor of Science Degree in
12 Mechanical Engineering from South Dakota State
13 University.I joined MidAmerican Energy Company (a
14 Berkshire Hathaway Energy affiliate company)in November
15 1999,and held positions of increasing responsibility
16 within the generation organization,including serving as
17 project manager for a new 780 megawatt ("MW")
18 supercritical coal-fueled generation resource placed in
19 service in 2007.In April 2008,I moved to Northern
20 Natural Gas Company (a Berkshire Hathaway Energy
21 affiliate company)as Senior Director of Engineering.I
22 joined PacifiCorp in February 2009.In my current role as
23 Vice President of Strategy and Development,my
24 responsibilities encompass strategic planning,regulatory
25 support,stakeholder engagement,development and
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1 execution of major generation resource additions,major
2 environmental compliance projects,and major transmission
3 projects.
4 PURPOSE AND SUMMARY OF TESTIMONY
5 Q.What is the purpose of your testimony?
6 A.I am testifying in support of the Company's
7 Application for Certificates of Public Convenience and
8 Necessity and Binding Ratemaking Treatment for Wind and
9 Transmission Facilities ("Application").The Company's
10 2017 Integrated Resource
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1 Plan ("2017 IRP")preferred portfolio identified a
2 time-limited opportunity to procure approximately 1,100
3 MW of cost-effective wind facilities and construct
4 transmission facilities to relieve existing congestion
5 and allow interconnection of those new wind facilities,
6 while providing all-in customer savings.To capture the
7 substantial customer benefits resulting from this
8 time-limited opportunity,the Company filed the
9 Application,including request for certificates of public
10 convenience and necessity ("CPCNs")for the construction
11 or acquisition of approximately 860 megawatts ("MW")of
12 new wind facilities ("Wind Projects").1 The Company has
13 secured development and implementation rights for the
14 Wind Projects,which consist of four individual wind
15 facilities located in the state of Wyoming.The Wind
16 Projects rely upon the construction of the Aeolus-to-
17 Bridger/Anticline transmission line and other associated
18 network upgrades (collectively,the "Transmission
19 Projects"),which will relieve existing congestion and
20 allow interconnection of the Wind Projects.2 In turn,
21 the benefits generated by the Wind Projects-zero-fuel-
22 cost generation that lowers net power costs and ten years
23 of federal productions tax credits ("PTCs"),support
24 cost-
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10 1 None of the four wind facilities are qualifying facilities under
the Public Utility Regulatory Policies Act.See 18 C.F.R.§292.204
11 (defining criteria for qualifying facilities).
2 As more specifically described in the testimony of Mr.Rick A.
12 Vail,the Transmission Projects include:(1)a new 140-mile,500
kilovolt (kV)transmission line segment and associated infrastructure
O 13 running from the new Aeolus substation near Medicine Bow,Wyoming,to
the new Anticline substation located near the existing Jim Bridger
14 substation,which includes construction of the new Aeolus and
Anticline substations;(2)a new five-mile 345 kV transmission line
15 that will extend from the proposed Anticline substation to the
existing Jim Bridger substation,which includes modifications at the
16 existing Jim Bridger substation to allow termination of the new 345kV
line;(3)installation of a voltage control device at the Latham
17 substation (items 1 through 3 collectively referred to as the
"Aeolus-to-Bridger/Anticline line");(4)a new 16-mile,230 kV
18 transmission line running from the Company's existing Shirley Basin
substation to the proposed Aeolus substation,which requires
19 modifications to the Shirley Basin substation and interconnection
facilities in the new Aeolus substation to accommodate the new line;
20 (5)reconstruction of four miles of an existing 230 kV transmission
line between the proposed Aeolus substation and the Freezeout
21 substation,which requires modifications to the Freezeout substation
and interconnection facilities in the new Aeolus substation to
22 accommodate the rebuilt line;and (6)reconstruction of 14 miles of
an existing 230 kV transmission line between the Freezeout substation
23 and the Standpipe substation,which requires modifications to the
Freezeout and Standpipe substations to accommodate the rebuilt line
24 (items 4 through 6 collectively referred to as the "230 kV Network
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Upgrades").
1014 Teply,Di -2a
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1 effective development of the Transmission Projects.
2 Together,the Wind Projects and the Transmission Projects
3 provide significant savings to customers over the lives
4 of the resources.
5 The Company is now conducting a competitive
6 market renewables request for proposals ("2017R RFP").
7 Upon conclusion of the 2017R RFP,the Company will
8 confirm the specific wind facilities that it plans to
9 construct or acquire.In the Application,the Company
10 provides detailed information on four wind facilities to
11 meet the CPCN requirements established by the Idaho
12 Public Utilities Commission ("Commission").The Company
13 is submitting these four wind facilities as benchmark
14 resources in the 2017R RFP and proxy resources in the
15 Application,pending the final results of the 2017R RFP.
16 My testimony and exhibits provide the information
17 required by Rule 112 of the Commission's Rules of
18 Procedure ("RP"),related to the application for CPCNs
19 for the Wind Projects.
20 Q.Please summarize your testimony.
21 A.My testimony demonstrates that the Company's
22 proposals to construct or acquire approximately 860 MW of
23 new Wind Projects and construct the Transmission Project
24 (collectively "Combined Projects"or "Projects")is in
25 the public interest and in the best interest of
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1 customers.Together,the Projects provide substantial
2 customer benefits as long as both achieve commercial
3 operation by the end of 2020.My testimony explains how
4 the Company intends to further develop and procure the
5 Wind Projects and why it is necessary to submit the Wind
6 Projects as "proxy"facilities at this time while the
7 Company conducts the 2017R RFP in parallel with this CPCN
8 proceeding.
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1 Q.Why is the Company pursuing the Wind Projects?
2 A.As further described in the testimonies of Ms.
3 Cindy A.Crane and Mr.Rick T.Link,the Company is
4 pursuing the acquisition and development of the Combined
5 Projects to deliver a time-sensitive opportunity for
6 customers that is identified in the Company's 2017 IRP
7 preferred portfolio (i.e.,addition of approximately
8 1,100 MW of new wind resources and the associated new
9 transmission infrastructure by 2020).The Company has
10 executed the necessary agreements and engaged in the
11 appropriate development activities to ensure that viable
12 Wind Projects to support the Transmission Projects are
13 available and positioned to ensure competitive market
14 engagement,and have directly controllable implementation
15 plans.The Wind Projects support both this CPCN
16 proceeding and the Company's parallel path 2017R RFP
17 process.
18 GENERAL DESCRIPTION OF THE WIND PROJECTS
I
19 Q.Please describe the Wind Projects.
20 A.The Wind Projects information incorporated into
21 the Company's Application is intended to allow the
22 Commission to review the need,economic analyses,and
23 customer benefit of the Wind Projects while the Company's
24 2017R RFP is pending.The Wind Projects include three
25 nominal 250 MW facilities in Wyoming (referred to as
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1 Ekola Flats,TB Flats I,and TB Flats II)that a
2 third-party is currently developing.Each facility will
3 consist of the commensurate number of 2.0 MW to 4.2 MW
4 wind turbine generators to achieve up to a nominal 250 MW
5 nameplate capacity,an electrical collection system,a
6 34.5 kV to 230 kV collector substation,230 kV breakers,
7 a 230 kV tie-line between the wind project and the point
8 of interconnection substation,meteorological towers,
9 access roads,an operations and maintenance ("O&M")
10 building
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1 and required communication and control facilities (e.g.,
2 metering,hardware,software,and associated
3 communication circuits and other equipment).
4 The Wind Projects also include a fourth nominal
5 110 MW wind facility (McFadden Ridge II),which the
6 Company is currently developing on a Company-controlled
7 site in Wyoming.McFadden Ridge II is expected to consist
8 of approximately forty-four 2.3 MW to 2.5 MW wind turbine
9 generators and similar project infrastructure as those
10 described for the 250 MW facilities.
11 The Wind Projects incorporated into the
12 Application total 860 MW nominally,and represent
13 facilities for which the Company has secured the rights
14 to carry forward through development.The Company will
15 submit the Wind Projects into the 2017R RFP as benchmark
16 proposals,and will construct these facilities if they
17 are the winning bids in the 2017R RFP.
18 The proposed Wind Projects are estimated to
19 cost approximately (redacted).
20 Q.Why does the Company's Application seek a CPCN
21 for only 860 MW of wind facilities,when the 2017 IRP
22 identified a resource opportunity of approximately 1,100
23 MW of wind facilities?
24 A.The Company is seeking CPCNs for only those
25 facilities for which it has development and
1019 Teply,Di -5RockyMountainPower
1 implementation rights.
2 Q.Does the Company's economic analysis supporting
3 the CPCNs for the Transmission Projects include
4 approximately 1,100 MW of new wind facilities?
5 A.Yes.As the testimony of Mr.Link explains,the
6 Company's economic analysis includes certain known
7 qualifying facilities ("QFs")now in development that are
8 located in the Aeolus area,hold preferential
9 interconnection queue positions,have executed power
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1 purchase agreements contracts,and are reasonably
2 expected to be in service by year-end 2021.When these
3 QFs are considered in conjunction with the nominal 860 MW
4 of secured development opportunities,the total
5 generating capacity equate to the 1,180 MW of new wind
6 facilities analyzed in support of this Application.
7 Q.Please describe the time-sensitive nature of
8 the Combined Projects.
9 A.The time-sensitive nature of the Combined
10 Projects is primarily driven by the pending phase-out of
11 the federal PTC for new wind resources.In Internal
12 Revenue Code ("IRC")section 45,the U.S.Internal
13 Revenue Service ("IRS")provides for a PTC at the 2017
14 full rate of 2.4 cents per kilowatt hour of electrical
15 energy production by a wind facility.The PTC is
16 available for a 10-year period that begins when the
17 facility is placed in service.The Protecting Americans
18 from Tax Hikes Act of 2015 ("the PATH Act")extended the
19 availability of the PTC for wind facilities under
20 construction before January 1,2020.The PATH Act
21 extension,however,also provides for a phase-out of the
22 PTC.Wind facilities that began construction before
23 January 1,2017,will realize the full PTC credit,which
24 is the case for the Wind Projects.If a wind facility
25 begins construction in 2017,the PTC is reduced by 20
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1 percent.The PTC is reduced by 40 percent if construction
2 begins in 2018,and by 60 percent if construction begins
3 in 2019.The PTC is not available for wind facilities
4 that begin construction after December 31,2019.
5 To receive the "safe-harbor"PTCs,the
6 facilities must be placed into commercial operation by
7 the end of the fourth calendar year following the year in
8 which construction began (the "start-of-construction"
9 standard)or otherwise meet specific IRS requirements for
10 demonstrating the "continuity requirement"throughout the
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1 implementation timeline.To mitigate the risk of
2 interpretation of IRS's "continuity requirement,"the
3 Wind Projects (or other wind facilities selected in the
4 2017R RFP that rely on (i)the Transmission Projects and
5 (ii)also began construction prior to January 1,2017)
6 must be reviewed,approved,implemented,and placed in
7 service by year-end 2020 in accordance with the
8 "start-of-construction"standard and meeting the
9 "safe-harbor"with respect to the "continuity
10 requirement"to be eligible for the full PTC.The
11 Company's CPCN Application is designed to meet this
12 schedule and provide customers the full economic benefit
13 of the Combined Projects.
14 Q.Do the Wind Projects meet the IRS's "start of
15 construction"criteria?
16 A.Yes.To meet the "start of construction"
17 definition for tax purposes,the Company has acquired,or
18 has the rights to,sufficient and adequate wind turbine
19 generator equipment and other facility-specific
20 components for the Wind Projects purchased before
21 December 31,2016.These transactions satisfy the "safe
22 harbor"requirements under the PTC guidance issued by the
23 U.S.Internal Revenue Service.
24 Q.How does the Company plan to procure the Wind
25 Projects,or other new wind facilities?
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Rocky Mountain Power
1 A.As discussed in the testimony of Mr.Link,
2 concurrent with the CPCN proceeding,the 2017R RFP will
3 be issued to the competitive market requesting up to
4 1,270 MW of wind facilities to align with the new
5 resource interconnections enabled by the Aeolus-to-
6 Bridger/Anticline facilities and to facilitate assessment
7 of a wider range of market responses.The Company will
8 submit the Wind Projects as Company benchmark proposals
9 in the 2017R RFP in October 2017.The Company anticipates
10 that the 2017R RFP final shortlist of bids will be
11 determined by mid-January 2018.
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1 The Company will supplement its CPCN filing at
2 that time to incorporate the results of the 2017R RFP.
3 Depending on the outcome,the results will:(1)confirm
4 the selection of winning Wind Projects and validate their
5 benefits;(2)identify winning wind facilities that are
6 in addition to the Wind Projects and request a CPCN for
7 those projects;or (3)identify winning wind facilities
8 that have been selected instead of one of the Wind
9 Projects and request a CPCN for those facilities.In any
10 scenario,this will result in final wind facility
11 decisions that are assessed as equal to or better than
12 the Wind Projects in the CPCN Application.
13 Q.Why is the Company providing facility-specific
14 information for the Wind Projects in the CPCN Application
15 and also planning a supplemental filing in the CPCN
16 docket to incorporate the results of the 2017R RFP?
17 A.The Company's request for a CPCN for the
18 Projects is driven by the time-sensitivity and scale of
19 the filing.If the Company waited until the anticipated
20 conclusion of the 2017R RFP process in early 2018 to
21 begin the CPCN review process,the Company would not
22 receive the requested Transmission CPCN and could not
23 complete the Transmission Projects by year-end 2020.The
24 critical path schedules of the Transmission Projects are
25 the driving components of the CPCN procedural schedule,
1025 Teply,Di -8
Rocky Mountain Power
1 and the Company needs a CPCN by March 30,2018,to
2 maintain the development schedule.Critical path schedule
3 activities for the Transmission Projects are further
4 described in the testimony of Mr.Rick Vail.
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1 Q.On a stand-alone basis,would the Company's
2 ability to construct the Wind Projects by year-end 2020
3 be in jeopardy if the Company was prevented from
4 submitting a CPCN Application until after completion of
5 the 2017R RFP?
6 A.No.On a stand-alone basis,the critical path
7 schedule for the Wind Projects could accommodate a CPCN
8 process that follows the 2017R RFP.As noted before,
9 however,the economics of the Wind Projects are only
10 viable with the Transmission Projects,and vice versa;
11 the Transmission Projects are the critical path.
12 Q.How did the Company develop the Wind Projects?
13 A.The Company investigated the transmission
14 interconnection queue in the area of the Transmission
15 Projects and engaged a third-party wind facility
16 developer to identify facilities that held preferred
17 interconnection queue positions,are commercially viable,
18 and reasonably likely to achieve commercial operation by
19 the end of 2020.The Wind Projects have undergone
20 preliminary vetting for interconnection status,
21 permitting,constructability,wind resource performance,
22 and equipment supply.
23 Q.Does the Company anticipate that it will
24 develop additional information for the Wind Projects
25 presented in the CPCN Application?
1027 Teply,Di -9
Rocky Mountain Power
1 A.Yes.The Company will continue to work on the
2 Wind Projects to ensure that the Company makes the most
3 competitive benchmark proposals available to customers.
4 The Company will supplement its CPCN filing as necessary.
5 Q.Does the Company's proposed procedural process
6 allow the Company to support its CPCN filing with
7 market-based information?
8 A.Yes.The Company will demonstrate the economic
9 benefits of the Combined Projects with all available
10 competitive market-based information.The concurrent
11 development
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1028 Teply,Di -9a
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1 of the Wind Projects and the 2017R RFP process will
2 enable the Company to validate the reasonableness of the
3 winning facilities based on current market information.
4 Q.Does the Company's submittal of benchmark
5 resources in the 2017R RFP preclude other competitive
6 market proposals from being selected for implementation?
7 A.No.The Company has assessed and identified
8 only a portion of the competitive market wind facilities
9 that are reasonably assumed to be viable from an
10 interconnection,permitting,construction,performance,
11 and implementation perspective.The Company expects
12 robust competitive market response to the 2017R RFP,and
13 selection of any facility that is successful in that
14 process.
15 Q.Has the Company filed applications with the
16 Wyoming Industrial Siting Council for the Wind Projects?
17 A.No.The Company intends to submit applications
18 to the Wyoming Industrial Siting Council ("ISC")for any
19 Company benchmarks selected as successful bids in the
20 2017R RFP following completion of that process.The
21 Company expects that the ISC review process and hearings
22 will proceed through October 2018.The ISC is required to
23 hold a hearing within ninety days of application per
24 W.S.§35-12-109.
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1029 Teply,Di -10
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1 DEVELOPMENT OF WIND PROJECTS
2 Q.Has the Company performed preliminary
3 evaluations of the wind potential at each Wind Project
4 site?
5 A.Yes.Studies completed by the Company indicate
6 that the each of the Wind Project sites are suitable for
7 a wind facility.The Ekola Flats and TB Flats I and II
8 sites are adjacent to the Company's existing Dunlap and
9 Seven Mile Hill wind projects.The McFadden
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1030 Teply,Di -10a
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1 Ridge II facility is an expansion of the Company's High
2 Plains/McFadden Ridge wind facility.Wind data collected
3 from existing operations and the area of the Wind
4 Projects indicate that these sites have favorable wind
5 regimes suitable for high performance wind resources.
6 Q.Has the Company determined who will be
7 responsible for construction of the Wind Projects?
8 A.No.The Company has not currently identified
9 who will be responsible for constructing the Wind
10 Projects.The Company will issue a competitive
11 procurement request for proposals to obtain firm fixed
12 pricing to engineer,procure,construct and commission
13 each wind facility.The Company will do this as part of
14 its development process for the benchmark proposals.
15 Q.Has the Company determined who will supply the
16 wind turbine generators for the Wind Projects?
17 A.Not entirely.As discussed above,the Company
18 has acquired or has rights to acquire "safe harbor"wind
19 turbine generator equipment and other project-specific
20 components,which it proposes to use at the Wind Projects
21 as required to meet the "start of construction"criteria
22 established by the Internal Revenue Service.The Company
23 intends to secure rights to procure "follow on"wind
24 turbine generator equipment through a competitive
25 procurement request for proposals.As with the Company
1031 Teply,Di -11
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1 benchmark contractor solicitation process,this effort
2 will be performed as part of the development process for
3 the benchmark proposals.
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1 Q.Will the Company seek confidential treatment of
2 specific information regarding the Wind Projects,
3 including cost,performance,technical and commercial
4 information?
5 A.Yes.The Wind Projects represent only a portion
6 of the wind resources that the Company expects to
7 investigate for possible acquisition and/or development
8 in response to the 2017R RFP.Information specific to the
9 Wind Projects includes pricing and performance data from
10 wind turbine generator equipment suppliers and
11 third-party project developers that is commercially
12 sensitive and is considered proprietary and highly
13 confidential.As such,project-specific cost,
14 performance,technical and commercial information,and
15 other data,must be maintained as proprietary and highly
16 confidential information.This is in the best interest of
17 customers because potential counterparties may use such
18 information to the disadvantage of customers in the
19 bi-lateral proposals and negotiations for other wind
20 resource assets,sites,equipment,services (i.e.,
21 construction,operation,or maintenance services)or in
22 competitive request for proposals processes.
23 Q.How did the Company generate the cost
24 information for construction,operation,and maintenance
25 of the individual wind facilities through their useful
1033 Teply,Di -12
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1 life?
2 A.The Company prepared its capital cost estimates
3 for the Wind Projects using information from a variety of
4 sources.The Company obtained wind turbine costs from a
5 competitive procurement process that was held in 2016 to
6 procure the Company's "safe harbor"wind turbine
7 generator equipment.
8 Development costs reflect negotiated fees with
9 the third-party project developer for Ekola Flats and TB
10 Flats I and II.The Company developed the balance of
11 plant
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1 engineering,procurement,construction,and commissioning
2 costs using a cost model similar to that used to develop
3 supply side resource capital costs for the 2017 IRP.
4 The Company took the transmission
5 interconnection costs from the respective wind facility's
6 transmission studies.Internal project management and
7 permitting costs were estimated based upon the Company's
8 experience with construction of past wind facilities and
9 other recent generation resource additions.
10 The Company applied contingencies in various
11 cost categories to account for project uncertainties
12 given the current stage of development of the Wind
13 Projects.O&M cost estimates were developed based upon
14 the Company's experience with wind resource O&M budgets
15 and third-party contracts for the Company's existing wind
16 facilities.Ongoing capital costs were estimated based
17 upon the Company's experience and indicative costs
18 provided by wind turbine generator suppliers for critical
19 capital components.
20 Q.Does the Company have any incentive to inflate
21 the costs of the Wind Projects incorporated into the CPCN
22 Application?
23 A.No.As discussed earlier in my testimony,and
24 in the testimony of Mr.Link,the purpose of the
25 Company's CPCN Application is to demonstrate the overall
1035 Teply,Di -13
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1 customer benefit of the Combined Projects,and to further
2 substantiate that benefit with the results of the 2017R
3 RFP.With the inherent competitive market comparison to
4 the RFP bids underlying the process,there is no
5 incentive or way for the Company to inflate the costs,
6 with recognition of the need for certain contingencies
7 due to the current state of development of the Wind
8 Projects.
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1 Q.Will the Wind Projects'wind turbine generators
2 or associated infrastructure be built in Wyoming's
3 Greater Sage Grouse Core area?
4 A.No.The Wind Projects'wind turbine generators
5 and associated infrastructure,including the associated
6 230 kV interconnection tie-lines,will not be located
7 within the current boundaries of Wyoming's Greater Sage
8 Grouse Core area.
9 Q.Will the Company collaborate with the Wyoming
10 Game and Fish Department,the U.S.Fish and Wildlife
11 Service,and other environmental agencies in developing
12 and implementing the Wind Projects?
13 A.Yes.The Company has already initiated
14 discussions with the Wyoming Game and Fish Department and
15 the U.S.Fish and Wildlife Service regarding developing
16 and implementing the Wind Projects.The Company,or in
17 some instances the third-party developer,has begun
18 pre-construction usage surveys for various avian,bat,
19 and wildlife species utilizing recommendations from
20 applicable state and federal guideline documents,
21 including the 2012 Land Based Wind Energy Guidelines.The
22 Company will coordinate with county,state,and federal
23 agencies that have jurisdiction over development,
24 permitting,and operations to ensure appropriate
25 environmental and safety measures are implemented
1037 Teply,Di -14
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1 throughout the life of the Wind Projects.The Company is
2 committed to establishing development and implementation
3 schedules and protocols that recognize potential
4 environmental impacts and strive to mitigate them.
5 Q.How will potential visual and lighting impacts
6 from the Wind Projects be addressed?
7 A.Wyoming state and county permitting regulations
8 contain requirements that recognize and address potential
9 visual and lighting impacts.The Company will incorporate
10 those
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1 applicable measures into the siting,construction,and
2 operations of the Wind Projects as part of the permitting
3 process.Such measures may include:down shielded
4 lighting on project infrastructure,Federal Aviation
5 Administration approved/recommended turbine lighting
6 protocols,active aviation light management,and use of
7 approved turbine paint color schemes.
8 Q.What is the expected operational life of the
9 Wind Projects?
10 A.The anticipated operational life of the Wind
11 Projects has been assessed at 30 years for the purposes
12 of this CPCN Application,which aligns with the Company's
13 currently approved depreciable life for wind resources.
14 The operational life may be reviewed and extended based
15 on advances in turbine technologies and/or improvements
16 in maintenance processes through the course of the
17 Company's regular depreciation studies and filings.
18 Q.Will the Wind Projects be decommissioned or
19 repowered at the end of their operational life?
20 A.The Company may dismantle and reclaim the Wind
21 Projects at the end of their operational life based upon
22 operating permit requirements.Typically,county and
23 state agencies identify the decommissioning requirements
24 during the permitting process,including expected
25 reclamation efforts and overall decommissioning costs and
1039 Teply,Di -15
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1 security requirements.The Company may also consider
2 replacing or upgrading the existing infrastructure at the
3 end of the operational life if conditions (i.e.,
4 economics,permitting,customer load needs,etc.)are
5 conducive to reinvestment in the Wind Projects.
6 Q.When will construction of the Wind Projects
7 begin and end?
8 A.As described in detail in the exhibits attached
9 to my testimony,site construction of the
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1 Wind Projects will begin as soon as the fourth quarter of
2 2019.The Company will not begin construction,however,
3 until it has received all of the necessary regulatory
4 approvals and applicable permits and authorizations from
5 other local,state,Indian or federal governmental
6 agencies that have jurisdiction over the construction or
7 operation of the Wind Projects,including approval from
8 the ISC and conclusion of the 2017R RFP to ensure that
9 the projects ultimately selected are in the best interest
10 of customers.The Company anticipates that substantial
11 completion,under normal construction circumstances,
12 weather conditions,labor availability and materials
13 delivery,will be achieved by November 15,2020.
14 Q.Please explain why the Wind Projects are
15 required for the public convenience and necessity.
16 A.As explained by Mr.Link,the Company's 2017
17 IRP shows that the Wind Projects are a reasonable means
18 of meeting present and future public convenience and
19 necessity.In this Application,the Company demonstrates
20 that the Wind Projects are in the public interest
21 because:(1)they will become an essential element of the
22 Company's diversified resource portfolio that is needed
23 to serve customers;(2)the facilities are desirable due
24 to location-specific attributes;and (3)the Wind
25 Projects will benefit customers as a whole.
1041 Teply,Di -16
Rocky Mountain Power
1 REQUIREMENTS OF RP 112
2 Q.Please summarize how the Company's Application
3 meets the requirements for a CPCN application.
4 A.RP 112 describes what must be included in an
5 application for a CPCN.As such,I have incorporated
6 exhibits to my testimony that include the required
7 information for the
8 /
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1042 Teply,Di -16a
Rocky Mountain Power
1 Wind Projects.
2 Q.Please describe your exhibits for the nominal
3 250 MW Ekola Flats facility that are responsive to RP
4 112.
5 A.The required information for the nominal 250 MW
6 Ekola Flats facility is included in Confidential Exhibit
7 No.1 to my testimony.Confidential Exhibit No.1
8 Subparts are identified as follows:
9 o Highly Confidential Exhibit No.1-1-Wind
10 Turbine Generator ("WTG")Site Layout
11 o Highly Confidential Exhibit No.1-2-WTG Scope
12 of Supply Example
13 o Confidential Exhibit No.1-3-Balance of Plant
14 Scope of Work Template
15 o Confidential Exhibit No.1-4-Capital Costs
16 Detail
17 o Confidential Exhibit No.1-5-Incremental
18 Operational and Maintenance and Ongoing Capital
19 Costs Detail
20 o Confidential Exhibit No.1-6-Indicative Project
21 Execution Schedule
22 o Highly Confidential Exhibit No.1-7-Preliminary
23 Project Map
24 o Confidential Exhibit No.1-8-Geotechnical
25 Report
1043 Teply,Di -17
Rocky Mountain Power
1 o Confidential Exhibit No.1-9-Preliminary
2 Topographical Map
3 o Confidential Exhibit No.1-10-Preliminary
4 Scenic Byways,Recreational Areas,National
5 Parks,and State Parks Review
6 o Highly Confidential Exhibit No.1-11-
7 Preliminary Cultural and Paleontological
8 Resources Review
9 o Confidential Exhibit No.1-12-Preliminary
10 Wildlife and Plant Species of Potential Concern
11 Review
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1044 Teply,Di -17a
Rocky Mountain Power
1 o Confidential Exhibit No.1-13-Preliminary
2 Aviation and Airspace Review
3 o Confidential Exhibit No.1-14-Interconnection
4 Facilities Study
5 o Confidential Exhibit No.1-15-Preliminary
6 Local,State,Federal,and Tribal Requirements
7 Review
8 Q.Please describe the exhibits to your testimony
9 for the nominal 250 MW TB Flats I wind facility and the
10 nominal 250 MW TB Flats II wind facility that are
11 responsive to RP 112.
12 A.The required information for the nominal 250 MW
13 TB Flats I wind facility and the nominal 250 MW TB Flats
14 II wind facility is included in Confidential Exhibit No.
15 2 to my testimony.Confidential Exhibit No.2 Subparts
16 2-1 through 2-16 are provided with the similar reference
17 material designations as the Exhibit No.1 Subparts
18 listed above.The required information for these two
19 facilities is incorporated into one set of exhibits due
20 to the contiguous development and adjacent locations of
21 the facilities.
22 Q.Please describe the exhibits for the nominal
23 110 MW McFadden Ridge II wind facility that are
24 responsive to RP 112.
25 A.The required information for the nominal 110 MW
1045 Teply,Di -18
Rocky Mountain Power
1 McFadden Ridge II wind facility is included inO2ConfidentialExhibitNo.3 to my testimony.Confidential
3 Exhibit No.3 Subparts 3-1 through 3-17 are provided with
4 similar reference material designations as the Exhibit
5 No.1 and Exhibit No.2 Subparts listed above.
6 Q.Do you propose to file supplemental testimony
7 and exhibits upon completion of the 2017R RFP?
8 A.Yes.The Company anticipates that the 2017R RFP
9 final shortlist will be determined by mid-January 2018.I
10 will file supplemental testimony and exhibits as soon as
11 the results
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1046 Teply,Di -18a
Rocky Mountain Power
1 of the 2017R RFP are final and the winning bids are
2 known.In any scenario,the winning bids will result in
3 final wind facility decisions that are as beneficial to
4 customers or better than the Wind Projects described in
5 my testimony and in the CPCN.
6 CONCLUSION AND RECOMMENDATION
7 Q.Please summarize your recommendation to the
8 Commission.
9 A.I recommend that the Commission determine that
10 the Wind Projects,or the alternative or additional wind
11 facilities that result from the 2017R RFP,are in the
12 public interest.Based on this conclusion,I recommend
13 that the Commission grant the Company the CPCNs for the
14 Wind Projects,or alternatives that result from the 2017R
15 RFP,at the conclusion of these proceedings.
16 Q.Does this complete your direct testimony?
17 A.Yes.
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1047 Teply,Di -19RockyMountainPower
1 Q.Are you the same Chad A.Teply 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 SUMMARY OF REBUTTAL TESTIMONY
6 Q.What is the purpose of your rebuttal testimony
7 in this proceeding?
8 A.My rebuttal testimony supports the Company's
9 application for certificates of public convenience and
10 necessity ("CPCNs")and binding ratemaking treatment
11 ("Application")for the Company's proposal to construct
12 or procure 860 megawatts ("MW")of new wind resources
13 ("Wind Projects")and construct the Aeolus-to-Bridger
14 /Anticline line and 230 kV Network Upgrades
15 ("Transmission Projects")(collectively,the "Combined
16 Projects").I summarize the current status of the
17 Combined Projects,including the proxy benchmark wind
18 facilities in the Company's 2017 Request for Proposals
19 ("2017R RFP"),the results of which will be included in
20 the Company's supplemental testimony on January 16,2018.
21 I also respond to the testimony of the Staff of
22 the Idaho Public Utilities Commission ("IPUC),Monsanto
23 Company ("Monsanto"),and the Idaho Irrigation Pumpers
24 Association,Inc.("IIPA").
25 Q.What are the key issues you address in your
1048 Teply,Di-Reb -1
Rocky Mountain Power
1 rebuttal testimony?
2 A.I address the following key issues:
3 1.The development of the proxy benchmark Wind
4 Projects is on schedule,so if the projects are
5 selected to the final shortlist in the 2017R
6 RFP,the Company is positioned to timely
7 deliver them and implement risk mitigation
8 measures to address the risks identified in the
9 parties'testimony.These risk mitigation
10 measures
11 /
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1049 Teply,Di-Reb -la
Rocky Mountain Power
1 advance the public interest in support of the
2 Application.
3 2.The implementation schedules for the Combined
4 Projects continue to provide reasonable
5 timelines to assess project risks,incorporate
6 the assessments into decision-making,and allow
7 for changes in project direction in response to
8 changing circumstances (i.e.,off-ramps).
9 Q.Please summarize your testimony.
10 A.The Company recognizes the unique circumstances
11 presented by the Application,given that final project
12 information and economics for the Combined Projects will
13 not be known until January 2018.This schedule is driven
14 by the time-sensitivity of the resource opportunity.The
15 Company has addressed these circumstances with a project
16 schedule that permits the Company to comprehensively
17 assess and confirm the economic benefits of the Combined
18 Projects as development progresses,and mitigate many of
19 the risks inherent in projects of this scope.
20 The Company has extensive experience
21 successfully developing comparable projects,with
22 substantial customer benefits.The Company has every
23 reason to believe the Combined Projects will be similarly
24 beneficial to customers.If changing circumstances
25 adversely impact the economics of the Combined Projects,
1050 Teply,Di-Reb -2
Rocky Mountain Power
1 however,the Company has prudently established a process
2 that will allow off-ramps.The Company also recognizes
3 the value of stakeholder engagement before committing to
4 major expenditures.The Company will therefore provide
5 updated costs,analysis,and project information in its
6 January 16,2018 supplemental filing,and will continue
7 to identify and mitigate risks in the Combined Projects.
8 /
9
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1051 Teply,Di-Reb -2a
Rocky Mountain Power
1 COMBINED PROJECTS UPDATE
2 Q.Is the Company still on schedule to supplement
3 its original Application in January 2018 with a filing
4 incorporating updated and detailed economic analysis,
5 updated wind and transmission project information,and
6 discussing the Company's Project implementation plans?
7 A.Yes.The regulatory review process for the
8 Combined Projects is ongoing and the Company is currently
9 finalizing its shortlist for the 2017R RFP,as described
10 in Company witness Mr.Rick T.Link's rebuttal testimony.
11 In addition,the Company continues to refine and update
12 its economic assessments and development of the Wind
13 Projects as required to support the January 2018
14 supplemental filing and the overall project schedule.The
15 January 2018 filing will include information pertaining
16 to the final shortlist projects selected through the
17 2017R RFP,including information related to project
18 configurations,project participants,equipment supply,
19 and permitting status.
20 Q.Please provide an updated timeline of key
21 decision-points,regulatory outcomes,and project
22 development activities.
23 A.The following timeline provides an overview of
24 the key events that have already occurred,and the
O 25 anticipated events that will occur as the resource
procurement and development efforts continue.
1052 Teply,Di-Reb -3
Rocky Mountain Power
1 Energy Vision 2020 New Wind and Transmission Timeline
2
Apr,4,2017-PacifiCorp 2017 Integrated
3 Resource Plan ("IRP")filing
4
5 Jun.30,2017-Idaho CPCN filing
6 Jun.30,2017-Wyoming CPCN filing
7 Jun.30,2017-Utah Resource Decision filing
8
9 2017 Sept.27,2017-PacifiCorp 2017R RFP issued to
market
10
11
Nov.17,2017-PacifiCorp 2017R RFP initial
12 shortlist determination
O 13 Nov.22,2017-PacifiCorp 2017R RFP initial
shortlist price updates
14
15
Dec.11,2017-Oregon Commission action on 2017
16 IRP action items
17 Dec.2017-U.S.Tax Code legislation passes(anticipated)
18
19
20
Jan.8,2018-PacifiCorp 2017R RFP final
21 shortlist determination
22 Jan.16,2018-Idaho CPCN supplemental filing
23 Jan.16,2018-Wyoming CPCN supplemental filing
24 2018 Jan.16,2018-Utah Resource Decision
25
supplemental filing
1053 Teply,Di-Reb -4
Rocky Mountain Power
1 Feb.22-28-Wyoming CPCN public hearing
2
3 Mar.6-9,2018-Utah Resource Decision publichearing
4
Mar.9,2018-Wyoming legislative session ends
5 (budget session)
6 Mar.12-15,2018-Idaho CPCN public hearing
7
8 Apr.6,2018-Idaho CPCN Commission Order
9 Apr.6,2018-Utah Resource Decision Commission
Order
10
Apr.30,2018-Wyoming CPCN Commission Order
11 (conditioned upon rights-of-way ("ROW")acquisition)
12
O 13
May 1,2018-Begin Transmission Projects ROW
14 acquisition
15 May 31,2018-Wind Projects BOP EPC Contract
Limited Notice to Proceed ("LNTP")(benchmarks)
16
17
Jun.30,2018-USFWS Eagle Take Permit
18 first-year data collection complete
19
20 Nov.30,2018-Transmission Projects EPC
Contract LNTP (500 kV)
21
22
Dec.31,2018-Wyoming Industrial Siting Council
23 permit received,New Wind (benchmarks)
24 Dec.31,2018-Wyoming Industrial Siting Council
25
permit received,Transmission
1054 Teply,Di-Reb -5
Rocky Mountain Power
2 Jan.1,2019-Complete Transmission Projects ROWacquisition(anticipated completion)
3
Jan.1,2019-Wyoming CPCN issued (transmission
4 ROW acquired)
5 Jan.1,2019-Wind Projects Development TransferAgreementclosing(benchmarks)
6
7
Mar.15,2019-Wyoming legislative session ends
8 (full session;approximate date)
9
10 2019 Apr.1,2019-Transmission EPC Contract Full
Notice to Proceed ("FNTP")(500 kV)
11
Apr.1,2019-Wind Projects BOP EPC Contract
12 FNTP (benchmarks)
O 13 Apr.1,2019-Wind Projects Turbine Supply
Agreement release (benchmarks)
14
15
Jun.30,2019 -USFWS Eagle Take Permit
16 second-year data collection complete
17
18 Sept.30,2019-Submit voluntary USFWS Eagle
Take Permit application
19
20
21 2020 Mar.15,2020-Wyoming legislative session ends(budget session;approximate date)
22 /
23 /
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1055 Teply,Di-Reb -6RockyMountainPower
2 Dec.31,2020-Receive voluntary Eagle Take
Permit (if issued by USFWS)
3
Dec.31,2020-New Wind and Transmission
4 Projects in-service.
5
6
7 Q.Is the Company currently on track to meet this
8 development schedule and complete the Combined Projects
9 by the end of 2020?
10 A.Yes.
11 Q.Does the timeline above provide off-ramps to
12 allow the Company to revise,or potentially terminate,
13 development efforts in response to changes in federal
14 income tax policy,project permitting,or other risks
15 associated with the Combined Projects?
16 A.Yes.In particular,the Company anticipates
17 that changes to the federal corporate income tax code
18 that are being finalized by the U.S.Congress will be
19 reasonably clear by year-end 2017,and will be
20 incorporated into the January 2018 supplemental filing.
21 If tax reform is delayed such that it cannot be accounted
22 for in the supplemental testimony,it is still likely
23 that the outcome of tax reform will be known before the
24 Company commits to the Combined Projects by a full notice
25 to proceed to major contracts.Thus,the risk associated
1056 Teply,Di-Reb -7RockyMountainPower
1 with changes in federal tax rates should be resolved
2 before the Company moves forward with the Combined
3 Projects.
4 To provide that risk mitigation,the timeline
5 for development and implementation of the Combined
6 Projects contemplates offering limited notices to proceed
7 ("LNTP")to key engineering,procurement,and
8 construction ("EPC")contractors associated with the
9 projects only after receipt of the CPCNs.The LNTP
10 /
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1057 Teply,Di-Reb -7a
Rocky Mountain Power
1 will facilitate EPC contractor support of the Wyoming
2 Industrial Siting Council permit review and hearing
3 process,as well as initiation of certain engineering and
4 pre-procurement activities.The LNTP concept incorporated
5 into these key contracts will limit cost commitments
6 while allowing critical parallel path project development
7 activities and approvals to progress.
8 The project timeline also incorporates
9 off-ramps to ensure that the transmission rights-of-way
10 ("ROW")acquisition effort is complete and the final
11 CPCNs are obtained before release of full notice to
12 proceed ("FNTP")to EPC contractors for the Combined
13 Projects.Under the terms of the major EPC contracts for
14 the Combined Projects that will be awarded by the
15 Company,FNTP allows the EPC contractors to proceed with
16 their major equipment purchases,site mobilization,and
17 subcontract awards that also entail the associated cost
18 commitments for those activities.Recognizing that a
19 successful and timely ROW acquisition process is
20 fundamental to the overall success of the project,
21 negotiation of the FNTP terms described above with major
22 EPC contractors provides another layer of risk mitigation
23 that the Company has incorporated into its planning.
24 RISK OF COMBINED PROJECTS
25 Q.IPUC witness Mr.Richard Keller notes that the
1058 Teply,Di-Reb -8
Rocky Mountain Power
1 Wind Projects must be operational by the end of 2020 to
2 receive full PTC benefits.(Keller Direct,page 9,lines
3 19-23.)How does the Company plan to ensure successful
4 and on-schedule delivery of the Combined Projects?
5 A.The Company relies on several strategies to
6 ensure successful mitigation of the types of project
7 implementation risks that could delay the Combined
8 Projects beyond 2020.
9 /
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1059 Teply,Di-Reb -8a
Rocky Mountain Power
1 The Company has used these same strategies in the recent
2 past to successfully deliver very similar wind and
3 transmission projects as those under review in this
4 docket.
5 Perhaps most importantly,the Company has built
6 its regulatory procedural schedules and project
7 implementation timeline to allow sufficient time to
8 acquire the ROW necessary for the Aeolus-to-Bridger/
9 Anticline transmission line.The ability to acquire
10 necessary ROW will be known before release of the FNTP to
11 major EPC contractors for the Combined Projects.
12 Moreover,if there is a delay in acquiring the necessary
13 ROW for the Transmission Projects,the Company will
14 reassess how to adjust the projects'remaining critical
15 path schedules to successfully deliver customers the
16 benefits of the Combined Projects.
17 Q.Has the Company already begun negotiating the
18 EPC contracts for the Combined Projects?
19 A.Yes.The Company has solicited competitive
20 market proposals and is actively negotiating EPC contract
21 terms,conditions,and pricing for the Wind Projects,and
22 is engaged in similar efforts for the Aeolus-to-Bridger/
23 Anticline transmission line,as more fully described in
24 the rebuttal testimony of Company witness Mr.Rick A.
25 Vail.These efforts are underway not only to ensure the
1060 Teply,Di-Reb -9RockyMountainPower
1 ability to execute agreements in a timely and efficient
2 manner following project regulatory approvals and receipt
3 of critical permits,but also to review each potential
4 EPC contractor's ability to secure and deliver labor and
5 materials throughout their proposed construction
6 schedules.This review considers the number and scope of
7 concurrent projects that potential EPC contractors have
8 demonstrated an ability to deliver historically,and
9 their approach to booking future projects and managing
10 that business growth in times of significant
11 /
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1061 Teply,Di-Reb -9a
Rocky Mountain Power
1 market opportunity.Because the Company has engaged its
2 EPC contractors early,timely selection of EPC
3 contractors and timely approval of a CPCN for the
4 projects will allow labor and materials from the selected
5 EPC contractors to be committed and secured to the
6 Company's projects before other market participants that
7 engage in such discussions later in 2018 and 2019.
8 Q.Has the Company taken a similar approach to
9 engage the major wind turbine supplier market?
10 A.Yes.The Company has also solicited competitive
11 market proposals and is actively negotiating wind turbine
12 supply contract terms,conditions,and pricing for the
13 Wind Projects.These efforts are underway not only to
14 ensure the ability to execute agreements in a timely and
15 efficient manner following project regulatory approvals
16 and receipt of critical permits,but also to secure
17 manufacturing and delivery queue positions and schedules
18 in support of the Wind Projects.
19 Q.How will the Company manage weather-related
20 construction delay risk?
21 A.The Company is actively negotiating project
22 schedules and commercial terms with its shortlisted EPC
23 contractors to address the potential for wind days,
24 extreme weather,wildlife winter range seasonal
25 construction restrictions,and other potential
1062 Teply,Di-Reb -10
Rocky Mountain Power
1 weather-related risks.For example,the Company has
2 shifted construction activities such as installation of
3 turbine foundations and collector systems from 2020 to
4 2019 in the proposed construction schedules to mitigate
5 weather related construction risk in 2020.The Company's
6 economic analysis supporting the Combined Projects
7 incorporates these EPC contract provisions.
8 /
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1063 Teply,Di-Reb -10a
Rocky Mountain Power
1 Q.Are customers bearing all of the risks
2 associated with the Combined Projects?
3 A.No.Until the Commission reviews a resource
4 acquisition for prudence,the Company bears all
5 acquisition risks.The Company anticipates that the
6 prudence of its implementation of the Combined Projects
7 will undergo rigorous review in Idaho,and in all the
8 other states where the Company provides retail service.
9 In addition,as described by Mr.Link,the risks
10 associated with the Combined Projects are no different
11 than those associated with any other utility resource
12 acquisition.
13 PROPOSED CONDITIONS FOR APPROVAL
14 Q.Does the Company accept any of the conditions
15 that Monsanto Witness Mr.Nicholas L.Phillips recommends
16 to address the risks he associates with the Combined
17 Projects?(Phillips Direct,page 4,lines 12 to page 5,
18 line 2.)
19 A.No.Mr.Phillips recommends that the Commission
20 impose several conditions related to the Combined
21 Projects'cost and performance that he argues increase
22 the likelihood of customer benefits.Mr.Phillips'
23 proposed conditions are completely unprecedented,and
24 none of them have ever been applied to the Company's past
25 resource acquisitions.Mr.Phillips has presented no
1064 Teply,Di-Reb -11
Rocky Mountain Power
1 basis to upend the traditional regulatory compact.
2 Q.What is the basis for Mr.Phillips'proposed
3 conditions?
4 A.Fundamentally,Mr.Phillips'conditions presume
5 the traditional regulatory compact does not apply to the
6 Combined Projects because of a perceived lack of resource
7 need and his assessment of key risks.(Phillips Direct,
8 page 2,lines 4-5.)Contrary to Mr.Phillips'claims,
9 however,the Combined Projects meet both near-term and
10 long-term resource needs and the risks presented by the
11 Combined Projects do not differ from other utility
12 investments.The fact the Company is taking advantage of
13 a time-limited
14 /
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1065 Teply,Di-Reb -lla
Rocky Mountain Power
1 opportunity presented by the expiring PTCs does not mean
2 the Combined Projects exist outside of the traditional
3 regulatory framework for review and approval of CPCNs.
4 Mr.Link and Ms.Steward address the concepts
5 of resource need and the traditional regulatory compact
6 as it applies to Mr.Phillips'arguments.My testimony
7 focuses on Mr.Phillips'assessment of key risks related
8 to project costs,performance,and schedule delays.
9 Q.Do you have any general comments on Mr.
10 Phillips'conditions?
11 A.Yes.It is important to note that Mr.Phillips
12 recommends the Commission impose specifically quantified
13 conditions around Wind Project cost and performance
14 assumptions that the Company will update in its January
15 2018 supplemental filing based on the results of the
16 2017R RFP.The outcome of the Company's 2017R RFP is
17 likely to change the cost and performance information,
18 and potentially even the underlying commercial structures
19 for the Wind Projects (e.g.,benchmark EPC,market build
20 transfer,or market power purchase).Thus,even if it
21 were reasonable to impose conditions similar to Mr.
22 Phillips'proposal,no basis exists to impose the
23 specific cost and performance metrics included in his
24 testimony.
25 Q.Mr.Phillips proposes a cap on the capital
1066 Teply,Di-Reb -12
Rocky Mountain Power
1 costs of the Combined Projects.(Phillips Direct,page 4,
2 lines 18-21.)Does the Company appreciate the importance
3 of the capital costs of the Combined Projects to the
4 overall benefit delivered to customers?
5 A.Absolutely.The Company is keenly focused on
6 delivering risk-adjusted,least-cost outcomes when
7 securing competitive market EPC costs,terms,and
8 conditions for the Combined Projects.In fact,the
9 Company's negotiated contracts are intended to
10 /
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1067 Teply,Di-Reb -12a
Rocky Mountain Power
1 mitigate risks related to cost,schedule,labor,andO2contractorperformance.The Company recognizes that the
3 parties participating in this docket are also keenly
4 focused on those important risk-mitigation efforts;
5 however,it is premature to attempt to identify or
6 dispute specific capital cost overrun assessments or
7 caps.While the (redacted)million value referenced in
8 Mr.Phillips'testimony reflects the proxy value
9 incorporated into the Company's Application to represent
10 the 860 MW of new Wind Projects,that estimate was
11 further refined for final submission in the 2017R RFP.
12 The Company's January 2018 supplemental filing will
13 reflect updated cost estimates for the Wind Projects,if
14 they are selected for the final shortlist.
15 Q.Does the level of risk or uncertainty of the
16 capital cost estimates for the Combined Projects differ
17 from the risks and uncertainty inherent in all resource
18 acquisitions?
19 A.No.The approach taken by the Company to
20 estimate costs and then engage the competitive market
21 during the Combined Projects'development schedules,as
22 described in my testimony above,demonstrates a
23 reasonable and prudent approach to provide additional
24 certainty and mitigate capital cost risk.
25 /
1068 Teply,Di-Reb -13
Rocky Mountain Power
1 Q.Mr.Phillips recommends the imputation of an
2 estimated capacity factor for the life of the Wind
3 Projects.(Phillips Direct,page 4,lines 25-28.)IPA
4 witness Mr.Anthony J.Yankel also argues that a
5 relatively small decrease in the forecasted generation
6 from the Wind Projects will largely eliminate the
7 customer benefits.(Yankel Direct page 20,lines 3-12.)
8 Does the Company appreciate the importance of project
9 capacity factors when assessing project life-cycle cost
10 of energy and benefit projections for customers?
11 A.Absolutely.But it is unreasonable and
12 unprecedented to impute an assumed capacity factor for
13 the life of these inherently variable resources.The
14 Commission has never imposed such a condition on any of
15 the Company's previous wind projects.Notably,Mr.Keller
16 agrees that the Company's forecasted generation is
17 reasonable.(Keller Direct,page 10,lines 8-12.)
18 Moreover,as described above,it is premature
19 at this point to identify or dispute any project-specific
20 capacity factor assessments.The outcome of the Company's
21 2017R RFP is likely to change the capacity factor
22 information associated with final shortlisted wind
23 projects.The (redacted)percent value referenced in Mr.
24 Phillips'testimony reflects the proxy value incorporated
25 in the Company's Application to represent the Wind
1069 Teply,Di-Reb -14
Rocky Mountain Power
1 Projects at the time of the filing.However,wind
2 projects are ultimately judged by their levelized cost of
3 energy ("LCOE"),and capacity factor is only one
4 component of the LCOE.Installation and operation costs
5 of wind turbines available in the competitive market also
6 contribute to the LCOE.As a result of competitive
7 bidding,wind turbines with significantly lower capital
8 costs,as well as lower projected capacity factors,can
9 be found to offer a lower LCOE assessment than higher
10 cost wind turbines
11 /
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1070 Teply,Di-Reb -14a
Rocky Mountain Power
1 with higher capacity factors.Creating a capacity factor
2 threshold in isolation can lead to the unintended outcome
3 of eliminating projects with lower LCOE assessment and
4 negatively impacting our customers.The Company's proxy
5 capacity factor value,and the Wind Projects costs,were
6 updated for final submission in the 2017R RFP.The
7 January 2018 supplemental filing will provide updated
8 capacity factor estimates and project costs for the Wind
9 Projects,if they are selected for the final shortlist.
10 Q.Is there anything about the Wind Projects that
11 makes the estimated capacity factor more uncertain than
12 for other wind facilities the Company has developed?
13 A.No.The Company's methodology for estimating
14 the capacity factors for the Wind Projects is the same as
15 the methodology previously relied on by the Commission.
16 In this respect,the Wind Projects are no riskier than
17 any of the previous wind projects the Company has
18 successfully developed for customers.
19 Q.What efforts has the Company taken to validate
20 the capacity factors developed for the Wind Projects?
21 A.The Company engaged an independent third-party
22 wind-resource data technical analyst to review and
23 determine the appropriate capacity factor estimates to
24 incorporate into its Wind Project analyses and 2017R RFP
25 submissions.The third-party technical assessments are
1071 Teply,Di-Reb -15
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1 based on an annual 50-percent probability ("P50")
2 approach and provide estimated wind production over
3 several years to account for normal and expected annual
4 variations.By the very nature of a P50 estimate,actual
5 wind project production is expected to be below the P50
6 estimate half of the years and above the P50 estimate the
7 other half of the years.Requiring the Company to provide
8 the full PTC and energy benefits at the higher of the P50
9 capacity factor or actual production
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1072 Teply,Di-Reb -15a
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1 is asymmetrical and unreasonable.O 2 Q.Has the Company taken additional efforts to
3 validate the capacity factors assumed in the bids to be
4 included in the 2017R RFP?
5 A.As Mr.Link testifies,the Company engaged
6 another independent third-party wind-resource data
7 technical analysts to review and determine the
8 appropriate capacity factor estimates to incorporate into
9 any final shortlist analyses.The third-party experts
10 based their assessments on a P50 approach.The Company
11 intends to include this independent study in its
12 supplemental filing.
13 Q.How have the Company's Wyoming wind resources
14 performed from 2010 through 2016,as compared to the
15 annual capacity factors estimated for the individual
16 projects at the time of acquisition decision-making?
17 A.Overall,the Company's existing wind projects
18 in the Medicine Bow,Wyoming area near the proposed
19 location of the Aeolus substation have out-performed the
20 pre-construction estimates,as set forth in the following
21 table:
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1073 Teply,Di-Reb -16RockyMountainPower
1
2 WYOMING WIND CAPACITY FACTOR SUMMARY
3 Capacity Factor MW Pre-Construction
Summary Nameplate COD PSO Average Actual DiiTerence
4 (non-leap years)2010 -2016
SEVEN MILE HILL I 99 12/31/2008 41.3 percent 39.2 percent -5.0 percent
5 SEVEN MILE HILL II 19.5 12/31/2008 39.3 percent 42.5 percent 8.1 percent
HIGH PLAINS 99 9/13/2009 35.7 percent 35.2 percent -1.3 percent
6 MCFADDENRIDGEI 28.5 9/29/2009 34.5 percent 37.2 percent 7.9 percent
DUNLAP I 111 10/1/2010 36.4 percent 40.2 percent 10.4 percent
7 Total 357
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1074 Teply,Di-Reb -16a
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1 Q.Do the results to date indicate fatal flaws or
2 undue risk in the third-party P50 analysis the Company
3 relies on to assess project economics and customer
4 benefits before acquisition of new wind projects?
5 A.No.If anything,the data presented above
6 indicates the Company's approach to P50 capacity factor
7 assessment for its Wyoming projects has provided a
8 conservative representation of results on an average
9 basis through seven years of project operation.
10 Q.Is there a mechanism in place to appropriately
11 capture the variability in resource benefits inherent
12 with new wind projects?
13 A.Yes.As utilized with previously implemented
14 wind projects,the Energy Cost Adjustment Mechanism
15 captures the variability in resource benefits inherent
16 with wind projects,in conjunction with other system
17 energy costs and PTCs,and distributes those benefits to
18 customers.
19 Q.Does your summary above provide different
20 results than the data provided in Mr.Phillips'testimony
21 about the Company's track record in estimating wind
22 project capacity factors?(See Phillips Direct,page 30,
23 Table NLP-5.)
24 A.Yes.I've limited my wind project capacity
25 factor data set to those projects the Company developed
1075 Teply,Di-Reb -17
Rocky Mountain Power
1 in the Medicine Bow area of Wyoming and placed in serviceO2between2007and2010.The Company's results with the
3 relatively recent Wyoming wind projects that were
4 developed near Medicine Bow,Wyoming,are better
5 correlated and more representative of the results the
6 Company would expect with the Wind Projects,particularly
7 considering that each of the four Wind Projects
8 incorporated into the Application are located adjacent to
9 the Company's existing operating sites included in the
10 chart above.Mr.Phillips'reliance on capacity factor
11 data including projects
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1076 Teply,Di-Reb -17aRockyMountainPower
1 developed in the earliest years of the wind industry,andO2thosedevelopedoutsideoftheMedicineBowareaof
3 Wyoming in those early years,skews the data set and
4 presents an inapt comparison.
5 Q.Mr.Keller testifies the Company should bear
6 the risks associated with the performance and
7 availability of the Wind Projects through proper
8 operations and maintenance because these are within the
9 Company's control (Keller Direct,page 19,lines 23-24).
10 Does the Company accept this condition as a fair
11 risk-allocation approach?
12 A.No.While the Company is engaged in
13 negotiations for contractual performance guarantees with
14 third-party maintenance providers for the Wind Projects,
15 imputing an incremental regulatory mechanism pertaining
16 to availability risk for the life of the new Wind
17 Projects is unreasonable and unprecedented.The
18 Commission has never imposed such a condition on any of
19 the Company's previous wind projects.
20 Q.Mr.Lobb recommends a condition requiring the
21 Company to provide a mechanical availability guarantee
22 ("MAG")based on the industry average of 97 percent for
23 the Wind Projects.(Lobb Direct,page 9,lines 21-24.)Is
24 this a reasonable condition?
25 A.The Company will negotiate availability
1077 Teply,Di-Reb -18
Rocky Mountain Power
1 guarantees for the Wind Projects in any third-party-O 2 provided maintenance,as provided by the competitive
3 market.In the Company's wind repowering project,the
4 Company was able to negotiate guarantee for repowered
5 projects'performance such that the projects will
6 (redacted).It is reasonable to expect that similar
7 guarantees can be negotiated for the Wind Projects.
8 However,higher wind
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1078 Teply,Di-Reb -18a
Rocky Mountain Power
1 availability guarantees often require a cost premium inO2operationsandmaintenancecontracts,and there are cases
3 where lower availability guaranties could lead to lower
4 LCOE for customers.Mandating an availability guarantee
5 threshold could be detrimental in some cases.
6 CONCLUSION AND RECOMMENDATION
7 Q.What is your conclusion of your rebuttal
8 testimony?
9 A.The Combined Projects remain well positioned to
10 provide customer benefits and are being effectively
11 developed in parallel to ongoing regulatory proceedings,
12 including the 2017R RFP,procurement activities,and
13 upcoming permitting,to mitigate project risks and
14 deliver desired outcomes.Project development activities
15 continue to be managed within a reasonable timeline to
16 assess project risks,incorporate those assessments into
17 decision-making,and allow for changes in project
18 direction (i.e.,off-ramps),if necessary.The Company
19 appreciates the engagement of the parties and believes
20 the Combined Projects will benefit from this rigorous
21 stakeholder review before the Company makes major
22 commitments to the projects.The Company looks forward to
23 the opportunity to file its supplemental testimony in
24 January 2018,with the results of the 2017R RFP and more
25 detailed cost and production information about the
1079 Teply,Di-Reb -19RockyMountainPower
1 Combined Projects.
2 Q.Does this conclude your rebuttal testimony?
3 A.Yes.
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1080 Teply,Di-Reb -19a
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1 Q.Are you the same Chad A.Teply who submittedO2directandrebuttaltestimonyinthisproceedingon
3 behalf of Rocky Mountain Power ("Company"),a division of
4 PacifiCorp?
5 A.Yes.
6 PURPOSE AND SUMMARY OF SUPPLEMENTAL DIRECT TESTIMONY
7 Q.What is the purpose of your supplemental direct
8 testimony in this proceeding?
9 A.I reflect the results of the Company's 2017R
10 request for proposals ("2017R RFP"),by updating my
11 testimony supporting the Company's application
12 ("Application")for conditional certificates of public
13 convenience and necessity ("CPCNs")and for binding
14 ratemaking treatment related to the Company's proposal to
15 construct or procure new wind resources ("Wind Projects")
16 and to construct the Aeolus-to-Bridger/Anticline
17 transmission line and network upgrades ("Transmission
18 Projects")(collectively,the "Combined Projects").I
19 describe the four new wind facilities totaling 1,170
20 megawatts ("MW")selected as final shortlist resources in
21 the 2017R RFP,and explain how those resources compare to
22 the original proxy benchmark resources incorporated into
23 the Application.I also provide the information required
24 by Idaho Code §§61-526 and Rule 112 of the Idaho Public
25 Utilities Commission ("Commission"),for CPCNs for the
1081 Teply,Di-Supp -1
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1 Wind Projects and for the associated facilities necessaryO2tointerconnecttheWindProjects.
3 Q.Please summarize your supplemental testimony.
4 A.The Company determined the final shortlist from
5 the 2017R RFP in early January 2018.The Company
6 successfully engaged the competitive market,and the RFP
7 results increase the benefits of the Combined Projects to
8 customers.The Company is on track to successfully
9 deliver the Combined Projects by year-end 2020 through
10 timely
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1082 Teply,Di-Supp -la
Rocky Mountain Power
1 development,procurement,and implementation.All of the
2 steps taken by the Company ensure that the Wind Projects
3 will qualify for production tax credits ("PTCs").
4 The Company is also well positioned to
5 negotiate and implement risk-mitigation measures,and
6 maintain controllable implementation plans for the Wind
7 Projects,including associated interconnection
8 infrastructure.The schedules for the Combined Projects
9 provide reasonable timelines to assess project risks,
10 incorporate the assessments into decision-making,and
11 allow for changes in project direction in response to
12 changing circumstances (i.e.,off-ramps).The Combined
13 Projects are in the public interest,providing
14 substantial benefits to customers.
15 GENERAL DESCRIPTION OF THE 2017R RFP FINAL SHORTLIST
16 Q.Please describe the Wind Projects selected to
17 the 2017R RFP final shortlist.
18 A.The Wind Projects selected to the 2017R RFP
19 final shortlist are four facilities in Wyoming totaling
20 approximately 1,170 MW:
21 1.McFadden Ridge II-109 MW Company benchmark;
22 2.TB Flats I and II (combined into single
23 project)-500 MW Company benchmark;
24 3.Cedar Springs-400 MW third-party build-transfer
25 and power-purchase agreement;and
1083 Teply,Di-Supp -2
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1 4.Uinta-161 MW third-party build-transfer.
2 Q.How do these projects relate to the benchmark
3 projects included in the Application?
4 A.In its Application,the Company provided
5 detailed information on four proxy benchmark wind
6 facilities to meet CPCN requirements,and committed to
7 providing
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1084 Teply,Di-Supp -2a
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1 updated information regarding the Wind Projects
2 ultimately selected in the 2017R RFP.The Company's
3 McFadden Ridge II and TB Flats I and II benchmarks were
4 selected to the final shortlist.The Company's fourth
5 benchmark wind facility,Ekola,was not selected to the
6 2017R RFP final shortlist.
7 Q.Please describe the McFadden Ridge II project.
8 A.McFadden Ridge II is a nominal 109 MW wind
9 facility located in Carbon and Albany counties,Wyoming,
10 which the Company is currently developing on a Company-
11 controlled site.McFadden Ridge II is expected to have
12 approximately 44 2.3-MW-to-2.5-MW wind turbine
13 generators.The facility will consist of an electrical
14 collection system,a 34.5-kV-to-230kV collector
15 substation,230-kV breakers,a 230-kV tie-line between
16 the wind project and the point of interconnection
17 substation,meteorological towers,access roads,and
18 required communication and control facilities (e.g.,
19 metering,hardware,software,and associated
20 communication circuits and other equipment).
21 The McFadden Ridge II project selected to the
22 shortlist is substantively identical to the project
23 described in the Company's direct testimony.
24 Q.Please describe the TB Flats I and II project.
25 A.TB Flats I and II is a nominal 500 MW wind
1085 Teply,Di-Supp -3RockyMountainPower
1 facility located primarily in Carbon County,Wyoming,O 2 although some facilities may be sited in Albany County as
3 well.We expect TB Flats I and II to have approximately
4 134 2.0-MW-to-4.2-MW wind turbine generators and similar
5 project infrastructure as described for McFadden Ridge
6 II,with the addition of an operations and maintenance
7 ("O&M")building.
8 The TB Flats I and II project,as selected to
9 the 2017R RFP final shortlist,was submitted as a single
10 Company benchmark project alternative to benefit from
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1086 Teply,Di-Supp -3a
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1 economies of scale and is no longer presented as twoO2stand-alone projects of 250 MW for TB Flats I and 250 MW
3 for TB Flats II projects for CPCN purposes as originally
4 described in the Application.
5 The TB Flats I and II project is substantively
6 identical to the TB Flats I and TB Flats II projects
7 described in the Company's direct testimony.
8 Q.Please describe the Cedar Springs project.
9 A.Cedar Springs is a nominal 400 MW wind facility
10 located in Converse County,Wyoming,that is being
11 developed by a third-party.We expect the project to
12 consist of approximately 161 2.3-MW-to-2.5-MW wind
13 turbine generators and similar project infrastructure as
14 described for McFadden Ridge II,with the addition of an
15 O&M building.The Cedar Springs project,as proposed,
16 will be procured as 50-percent build-transfer and
17 50-percent power-purchase agreement.
18 Q.Please describe the Uinta project.
19 A.Uinta is a nominal 161 MW wind facility located
20 in Uinta County,Wyoming.The Uinta project is being
21 developed and delivered by a third-party under a
22 build-transfer agreement.We expect the project to
23 consist of approximately 47 2.3-MW-to-3.6-MW wind turbine
24 generators and similar project infrastructure as
25 described for McFadden Ridge II,with the addition of an
1087 Teply,Di-Supp -4
Rocky Mountain Power
1 O&M building.O 2 Q.What are the total costs for the Wind Projects?
3 A.The proposed Wind Projects are estimated to
4 cost approximately $1.30 billion,recognizing the split
5 procurement attributes of the Cedar Springs facility.
6 This amount is lower than the cost estimate for the
7 initial benchmark projects included in the Application,
8 even though the Wind Projects selected to the 2017R RFP
9 final shortlist
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1088 Teply,Di-Supp -4a
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1 provide additional capacity.The overall costs of the
2 Combined Projects reflected in the Company's supplemental
3 direct testimony are consistent with the costs included
4 in the Application.
5 Q.Do all four Wind Projects rely on the
6 Transmission Projects for interconnection?
7 A.No.McFadden Ridge II,TB Flats I and II,and
8 Cedar Springs,which total 1,009 MW,rely on the
9 construction of the Transmission Projects,which will
10 relieve existing congestion and allow interconnection of
11 those Wind Projects.Uinta,which has a nominal capacity
12 of 161 MW,will interconnect to the Company's
13 transmission system in southwest Wyoming and is not
14 reliant on the Transmission Projects for interconnection
15 and delivery.In total,the benefits generated by the
16 Wind Projects'zero-fuel-cost generation,which lowers
17 net power costs and provides 10 years of PTCs,continue
18 to support cost-effective development of the Transmission
19 Projects.
20 Q.Did the 2017R RFP consider the recently passed
21 federal tax legislation and any potential impacts on wind
22 project proposals?
23 A.Yes.As discussed in detail in Mr.Rick T.
24 Link's testimony,the 2017R RFP process was adjusted to
25 allow proposals to be updated to reflect any impacts to
1089 Teply,Di-Supp -5
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1 proposal pricing,or project viability,before
2 determination of the final shortlist.
3 Q.Has recently passed federal tax legislation
4 resulted in a change to the time-sensitive nature of the
5 Combined Projects?
6 A.No.The time-sensitive nature of the Combined
7 Projects remains and is primarily driven by the pending
8 phase-out of PTCs for new wind resources.As Company
9 witness Ms.Nikki L.Kobliha explains,the recently
10 passed federal tax legislation did not modify the PTC
11 provisions of the tax code.
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1090 Teply,Di-Supp -5a
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1 Q.To receive 100 percent of safe-harbor PTCs,
2 must wind turbine generators still be placed in service
3 by the end of calendar year 2020?
4 A.Yes.To receive 100 percent of safe-harbor
5 PTCs,wind turbine generators in new facilities that
6 began construction before January 1,2017,through
7 purchase of safe-harbor equipment,must be reviewed,
8 approved,implemented,and placed in service by year-end
9 2020.The Company's implementation schedule for the
10 Combined Projects is designed to meet these criteria and
11 provide customers the economic benefit of 100 percent of
12 the PTCs.
13 Q.Do the Wind Projects selected to the 2017R RFP
14 final shortlist meet the Internal Revenue Service ("IRS")
15 start-of-construction criteria?
16 A.Yes.The Company confirmed through its due
17 diligence efforts that each of the Wind Projects selected
18 to the 2017R RFP final shortlist have acquired,or
19 secured the rights to,sufficient wind turbine generator
20 equipment and other facility-specific components before
21 December 31,2016,to meet the start-of-construction
22 definition for tax purposes.These transactions satisfy
23 the safe-harbor requirements under the PTC guidance
24 issued by the IRS.More specifically,the Company has
25 confirmed 2016 safe-harbor purchases of wind turbine
1091 Teply,Di-Supp -6
Rocky Mountain Power
1 generator equipment for each of the 2017R RFP finalO2shortlistWindProjectswiththerespectiveproject
3 developers.Each of the shortlisted 2017R RFP project
4 developers has provided the appropriate evidence of the
5 safe-harbor purchases that will be applied to each of the
6 respective Wind Projects.
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1092 Teply,Di-Supp -6a
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1 Q.How does the Company plan to continue to
2 procure the Wind Projects selected to the 2017R RFP
3 shortlist?
4 A.With the final shortlist determined,the
5 Company will continue to engage the shortlisted
6 counterparties in negotiations to finalize terms and
7 conditions,with a target for execution of definitive
8 agreements by April 16,2018.The final shortlist Wind
9 Projects include a combination of Company benchmark
10 resources,facilities that have been selected instead of
11 one or more of the Company benchmark resources,and
12 facilities in addition to the Company benchmark
13 resources.These Wind Projects have been assessed as
14 equal to or better than the Company benchmark resources
15 included in the Application.In each case,the individual
16 Wind Projects'developer has submitted its proposed
17 commercial structure for construction and procurement of
18 the resource within the guidelines of the 2017R RFP.
19 Q.Please provide an updated timeline of key
20 decision points,regulatory outcomes,and project
21 development activities.
22 A.The following timeline provides an overview of
23 the key events that have already occurred,and the events
24 that will occur as the currently anticipated resource
25 procurement and development efforts continue.
1093 Teply,Di-Supp -7
Rocky Mountain Power
1 Energy vision 2020 New Wind and Transmission Timeline
2
Apr,4,2017-PacifiCorp 2017 Integrated Resource Plan ("IRP")
3 filing
4 Jun.30,2017-Idaho CPCN filing
Jun.30,2017-Wyoming CPCN filing
5 Jun.30,2017-Utah Resource Decision filing
2017
6 Sept.27,2017-PacifiCorp 2017R RFP issued to market
Nov.17,2017-PacifiCorp 2017R RFP initial shortlist
7 determination
Nov.22,2017-PacifiCorp 2017R RFP initial shortlist price
8 updates from market
9 Dec.11,2017-Oregon Commission action on 2017 IRP action
items
10
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1094 Teply,Di-Supp -7a
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(III =
2 Dec.2017-U.S.Tax Code legislation passed
3 Jan.2018-PacifiCorp 2017R RFP final shortlist
determination
4
Jan.16,2018-Idaho CPCN supplemental filing
5 Jan.16,2018-Wyoming CPCN supplemental filing
Jan.16,2018-Utah Resource Decision supplemental filing
6
Feb.22-28,2018-Wyoming CPCN public hearing
7 Mar.6-9,2018-Utah Resource Decision public hearing
Mar.12-15,2018-Idaho CPCN public hearing
8
Mar.9,2018-Wyoming legislative session ends (budget session)
9 2018
Apr.6,2018-Idaho CPCN Commission Order
10 Apr.6,2018-Utah Resource Decision Commission Order
Apr.30,2018-Wyoming CPCN Commission Order (conditioned upon
11 rights-of-way ("ROW")acquisition)
12 Apr.16,2018-Executable Wind Projects Agreements Finalized
13 May 31,2018-Wind Projects Limited Notice to Proceed ("LNTP")
14 Jun.30,2018-USFWS Eagle Take Permit first-year data
collection complete (benchmarks)
15
Nov.30,2018-Transmission Projects EPC Contract LNTP (500 kV)
16
Dec.31,2018-Wyoming Industrial Siting Council permits
17 received,New Wind (benchmarks)
Dec.31,2018-Wyoming Industrial Siting Council permit
18 received,Transmission
19 Jan.1,2019-Complete Transmission Projects ROW acquisition
(anticipated)
20 Jan.1,2019-Wyoming CPCN issued (transmission ROW acquired;
anticipated)
21
Mar.31,2019-Wyoming legislative session ends (full session;
22 approximate date)
23 2019 Apr.1,2019-Transmission EPC Contract Full Notice to Proceed
("FNTP")(500 kV)
24 Apr.1,2019-Wind Projects FNTP
Apr.1,2019-Wind Projects Turbine Supply Agreement release
25 (benchmarks)
1095 Teply,Di-Supp -8
Rocky Mountain Power
1 Jun.30,2019-USFWS Eagle Take Permit second-year data
collection complete (benchmarks)
2
Sept.30,2019-Submit voluntary USFWS Eagle Take Permit
3 application (benchmarks)
4 Mar.15,2020-Wyoming legislative session ends (budget
session;approximate date)
5
2020 Dec.31,2020-Receive voluntary Eagle Take Permit (if issued
6 by USFWS)(benchmarks)
7 Dec.31,2020-New Wind and Transmission Projects in-service
8
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1 Q.Is the Company currently on track to meet this
2 development schedule and complete the Combined Projects
3 by the end of 2020?
4 A.Yes.
5 CONTINUED DEVELOFMENT,NEGOTIATIONS,AND IMPLEMENTATION
6 Q.What is the current status of development for
7 each of the Wind Projects?
8 A.As part of the 2017R RFP process,the Wind
9 Projects have undergone preliminary vetting for
10 interconnection status,wind resource performance,PTC
11 eligibility,permitting status,conformance to
12 specifications,constructability,and equipment supply.
13 Going forward,the Company's resource development team
14 will engage shortlisted project counterparties in
15 detailed commercial negotiations of scope,schedule,
16 cost,and terms within the construct of the 2017R RFP,
17 and otherwise continue with established development plans
18 and activities for the Wind Projects.
19 Q.Will the Company develop additional information
20 for the Wind Projects?
21 A.Yes.If material changes in circumstances or
22 new information on the Wind Projects becomes available
23 during the detailed negotiations,ongoing development,
24 and project implementation activities,the Company will
25 assess the information to ensure the Company delivers the
1097 Teply,Di-Supp -9
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1 most competitive Wind Projects for customers.The Company
2 will communicate any material changes in circumstances,
3 as discussed in the rebuttal testimony of Company
4 witnesses Ms.Cindy A.Crane and Ms.Joelle R.Steward.
5 Q.Are applications with the Wyoming Industrial
6 Siting Council ("ISC")for the Wind Projects being
7 prepared?
8 A.Yes.The Company's McFadden Ridge II benchmark
9 project scope was included in a previous permitting
10 process before the ISC,which was approved.The ISC
11 Permit
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1098 Teply,Di-Supp -9a
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1 applications for the TB Flats I and II,Cedar Springs,
2 and Uinta projects are being developed and will be filed
3 in accordance with the individual project development and
4 implementation schedules to support year-end 2020
5 in-service dates now that those projects have been
6 selected to the 2017R RFP final shortlist.Based upon a
7 review of the shortlisted project schedules,the Company
8 expects the ISC review processes and hearings for the TB
9 Flats I and II,Cedar Springs,and Uinta projects will
10 proceed through April 2019,subject to updates identified
11 during detailed negotiation of project contracts,
12 schedules,and implementation plans with each of the
13 shortlisted Wind Projects counterparties.
14 Q.Has the Company performed preliminary
15 evaluations of the wind potential at each Wind Project
16 site?
17 A.Yes.Studies for each of the Wind Projects were
18 completed by the individual project developers.The
19 Company also validated wind potential with a third-party
20 wind resource evaluation firm as part of the 2017R RFP
21 process.Wind assessments for each of the Wind Projects
22 indicate that the sites have favorable wind regimes
23 suitable for high performance wind resources.In
24 particular,the Company previously provided testimony in
25 this docket regarding the wind resources and the
1099 Teply,Di-Supp -10
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1 anticipated capacity factors expected to be produced by
2 the Company's project layouts for the McFadden Ridge II
3 and TB Flats I and II wind projects.The third-party
4 developers of the Cedar Springs and Uinta Wind Projects
5 provided similar assessments of the wind resources and
6 expected capacity factors for their projects,which is
7 included in the exhibits for each project attached to my
8 testimony.
9 The 2017R RFP evaluation team also reviewed the
10 wind resource assessments
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1 and independently determined whether the wind data
2 supported the proposed capacity factors or whether
3 adjustments to the proposed capacity factor for a project
4 were warranted.Mr.Link provides additional testimony
5 regarding the results of the 2017R RFP team's independent
6 review in his supplemental direct testimony.
7 Q.Has each Wind Project developer determined who
8 will be responsible for construction of each Wind
9 Project?
10 A.Not yet.Each of the Wind Project developers
11 has indicated its intent to issue competitive procurement
12 requests for proposals to obtain firm fixed pricing to
13 engineer,procure,construct and commission each wind
14 facility now that they have been added to the 2017R RFP
15 final shortlist.For the McFadden Ridge II and TB Flats I
16 and II projects,the Company is negotiating with
17 shortlisted EPC contractors that submitted formal
18 proposals in 2017.
19 Q.Has each Wind Project developer determined who
20 will supply the wind turbine generators for each Wind
21 Project?
22 A.Not entirely.As discussed above,each of the
23 Wind Project developers has acquired or has rights to
24 acquire safe-harbor wind turbine generator equipment and
25 other project-specific components,which it proposes to
1101 Teply,Di-Supp -11
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1 use at the Wind Projects as required to meet the IRS's
2 start-of-construction criteria for PTC eligibility.Each
3 of the Wind Project developers also indicated its intent
4 to finalize procurement of follow-on wind turbine
5 generator equipment through competitive procurement
6 requests for proposals or under existing master supply
7 agreements,and identified its intended equipment
8 suppliers,models,and configurations in its 2017R RFP
9 submittals.
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1102 Teply,Di-Supp -lla
Rocky Mountain Power
1 Q.How did the Company generate the cost
2 information for construction,operation,and maintenance
3 of the individual Wind Projects through their useful
4 lives?
5 A.As further discussed in Mr.Link's testimony,
6 the Company prepared its capital cost estimates for the
7 Wind Projects using information from a variety of
8 sources.
9 For its McFadden Ridge II benchmark Wind
10 Project,the Company obtained wind turbine costs from
11 competitive procurement processes that were held in 2016
12 to procure the Company's safe-harbor wind turbine
13 generator equipment and in 2017 for follow-on wind
14 turbine generator equipment.The Company also obtained
15 balance of plant engineering,procurement,construction,
16 and commissioning costs from a competitive procurement
17 process that was held in 2017 to support final submittals
18 in the 2017R RFP process.Transmission interconnection
19 costs were estimated using comparable wind facility
20 transmission studies and prior project experience,and
21 internal project development;management and permitting
22 costs were estimated based upon the Company's experience
23 with construction of past wind facilities and other
24 recent generation resource additions.The Company applied
25 contingencies in various cost categories to account for
1103 Teply,Di-Supp -12
Rocky Mountain Power
1 project uncertainties given the current stage of
2 development of the project.O&M cost estimates were
3 developed based upon the Company's experience with wind
4 resource O&M budgets and third-party contracts for the
5 Company's existing wind facilities.Ongoing capital costs
6 were estimated based upon the Company's experience and
7 indicative costs provided by wind turbine generator
8 suppliers for critical capital components.
9 For the third-party developed Wind Projects,
10 the Company received competitive market proposals for a
11 combination of build-transfer projects and power-
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1104 Teply,Di-Supp -12a
Rocky Mountain Power
1 purchase agreements within the guidelines provided in the
2 2017R RFP.All bid proposals received through that
3 process require a bid-validity date through April 16,
4 2018,and final shortlist bidders provided a letter
5 signed by an officer that commits to the requirements of
6 the 2017R RFP.Transmission interconnection costs for the
7 individual projects were informed by transmission system
8 impact studies,and internal project development,
9 management,and permitting costs were estimated based
10 upon the developers'experience with development and
11 construction of past wind facilities.O&M cost estimates
12 were developed based upon the Company's experience with
13 wind resource O&M budgets and third-party contracts for
14 the Company's existing wind facilities.Ongoing capital
15 costs were estimated based upon the Company's experience
16 and indicative costs provided by wind turbine generator
17 suppliers for critical capital components.
18 Q.Will the Company and third-party developers
19 collaborate with the Wyoming Game and Fish Department,
20 the U.S.Fish and Wildlife Service,and other
21 environmental agencies to develop and implement the Wind
22 Projects?
23 A.Yes.The Company and the third-party project
24 developers have initiated discussions with the Wyoming
25 Game and Fish Department and the U.S.Fish and Wildlife
1105 Teply,Di-Supp -13
Rocky Mountain Power
1 Service regarding developing and implementing the Wind
2 Projects.The Company and the third-party project
3 developers have also begun pre-construction usage surveys
4 for various avian,bat,and wildlife species using
5 recommendations from applicable state and federal
6 guideline documents,including the 2012 Land Based Wind
7 Energy Guidelines.The Company and third-party project
8 developers will coordinate with county,state,and
9 federal agencies that have jurisdiction over development,
10 permitting,
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1106 Teply,Di-Supp -13a
Rocky Mountain Power
1 and operations to ensure appropriate environmental and
2 safety measures are implemented throughout the life of
3 the Wind Projects..The Company is committed to
4 establishing development and implementation schedules and
5 protocols that recognize the potential environmental
6 impacts of the Wind Projects and strive to mitigate
7 negative impacts.
8 Q.Will the Wind Projects'wind turbine generators
9 or associated infrastructure be built in Wyoming's
10 Greater Sage Grouse Core area?
11 A.No.The Wind Projects'wind turbine generators
12 and associated infrastructure,including the associated
13 generation interconnection tie-lines,will not be located
14 within the current boundaries of Wyoming's Greater Sage
15 Grouse Core area.
16 Q.How will potential visual and lighting impacts
17 from the Wind Projects be addressed?
18 A.State and county permitting regulations contain
19 requirements that recognize and address potential visual
20 and lighting impacts.The Company and third-party
21 developers will incorporate those applicable measures
22 into the siting,construction,and operations of the Wind
23 Projects as part of the permitting process.Such measures
24 may include:down shielded lighting on project
25 infrastructure;Federal Aviation Administration
1107 Teply,Di-Supp -14RockyMountainPower
1 approved/recommended turbine lighting protocols;active
2 aviation light management;and use of approved paint
3 colors for turbines.
4 Q.When will construction of the Wind Projects
5 begin and end?
6 A.As described in detail in the exhibits attached
7 to my testimony,site construction of the Wind Projects
8 will begin as soon as the second quarter of 2019.The
9 Company and the third-party developers will not begin
10 construction,however,until all of the necessary
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1108 Teply,Di-Supp -14a
Rocky Mountain Power
1 regulatory approvals and applicable permits and
2 authorizations from other local,state,tribal or federal
3 governmental agencies that have jurisdiction over the
4 construction or operation of the Wind Projects have been
5 received,including approval from the Wyoming ISC to
6 ensure that the projects ultimately selected are in the
7 best interest of customers.The Company anticipates that
8 substantial completion for the Wind Projects,under
9 normal construction circumstances,weather conditions,
10 labor availability and materials delivery,will be
11 achieved by November 15,2020,or as otherwise updated
12 during detailed negotiation of project contracts,
13 schedules,and implementation plans with each of the
14 shortlisted Wind Projects counterparties.
15 Q.What is the expected operational life of the
16 Wind Projects?
17 A.The anticipated operational life of the Wind
18 Projects has been assessed at 30 years for the purposes
19 of the CPCN Application and this supplemental filing,
20 which aligns with the Company's currently approved
21 depreciable life for wind resources.The operational life
22 may be reviewed and extended based on advances in turbine
23 technologies or improvements in maintenance processes (or
24 both)through the course of the Company's regular
25 depreciation studies and filings.
1109 Teply,Di-Supp -15
Rocky Mountain Power
1 Q.Will the Wind Projects be decommissioned or
2 .repowered at the end of their operational life?
3 A.The Company may dismantle and reclaim the Wind
4 Projects delivered under a build-transfer agreement at
5 the end of their operational life based upon the
6 requirements of the operating permit.Typically,county
7 and state agencies identify the decommissioning
8 requirements during the permitting process,including
9 expected reclamation efforts and overall decommissioning
10 costs and security requirements.The Company may also
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1110 Teply,Di-Supp -15a
Rocky Mountain Power
1 consider replacing or upgrading the existing
2 infrastructure at the end of the operational life if
3 conditions (i.e.,economics,permitting,customer load
4 needs,etc.)are conducive to reinvestment in the Wind
5 Projects.
6 REQUIREMENTS OF IDAHO CODE §§61-526 AND COMMISSION
7 RULE 112
8 Q.Please summarize how the Company's Application
9 meets the requirements for a CPCN application.
10 A.Idaho Code §§61-526 and Rule 112 of the Idaho
11 Public Utilities Commission ("Commission")Rules of
12 Procedure ("RP"),describe what must be included in an
13 application for a CPCN.The exhibits to my testimony
14 include the required information for the Wind Projects.
15 Q.Please describe your exhibits for the nominal
16 400 MW Cedar Springs facility that provide the
17 information required by Idaho Code §§61-526 and
18 Commission Rule 112.
19 A.The nominal 400 MW Cedar Springs facility is
20 included in Confidential Exhibit No.31 to my testimony.
21 Confidential Exhibit No.31 subparts are:
22 o Confidential Exhibit No.31-1-Wind Turbine
23 Generator ("WTG")Site Layout
24 o Confidential Exhibit No.31-2-Site Wind
25 Resource Data
1111 Teply,Di-Supp -16RockyMountainPower
1 o Confidential Exhibit No.31-3-Preliminary
2 Project Schedule
3 o Confidential Exhibit No.31-4-Project Map
4 o Confidential Exhibit No.31-5-Metes and Bounds
5 Property Information
6 o Highly Confidential Exhibit No.31-6-Generation
7 Tie-line Property Information
8 o Confidential Exhibit No.31-7-Environmental
9 Studies
10 o Confidential Exhibit No.31-8-Raptor Nest
11 Information
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1112 Teply,Di-Supp -16a
Rocky Mountain Power
1 o Confidential Exhibit No.31-9-Permitting Matrix
2 o Confidential Exhibit No.31-10-System Impact
3 Re-Study Q712
4 o Confidential Exhibit No.31-11-230-kV Tie-line
5 Structure Details
6 Q.Please describe the exhibits for the nominal
7 500 MW TB Flats I and II wind facility that provide the
8 information required by Idaho Code §§61-526 and
9 Commission Rule 112.
10 A.The nominal 500 MW TB Flats I and II wind
11 facility is included in Confidential Exhibit No.32 to my
12 testimony.Confidential Exhibit No.32 subparts that have
13 been updated since my direct testimony was filed in this
14 Case are:
15 o Confidential Exhibit No.32-1-Preliminary Site
16 Layout
17 o Confidential Exhibit No.32-2-Parcel Map
18 o Confidential Exhibit No.32-3-Large Generator
19 Interconnection Facilities Study
20 Q.Please describe the exhibits for the nominal
21 109 MW McFadden Ridge II wind facility that provide the
22 information required by Idaho Code §§61-526 and
23 Commission Rule 112.
24 A.The required information for the nominal 109 MW
25 McFadden Ridge II wind facility is included in Exhibit
1113 Teply,Di-Supp -17
Rocky Mountain Power
1 No.33 to my testimony.Exhibit No.33 subparts have been
2 updated since my direct testimony was filed in this
3 docket are:
4 o Confidential Exhibit No.33-1-WTG Site Layout
5 Q.Please describe the exhibits for the nominal
6 161 MW Uinta wind facility that provide the information
7 required by Idaho Code §§61-526 and Commission Rule 112.
8 A.The required information for the nominal 161 MW
9 Uinta wind facility is included in
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1114 Teply,Di-Supp -17a
Rocky Mountain Power
1 Confidential Exhibit No.34 to my testimony.Confidential
2 Exhibit No.34 subparts are:
3 o Confidential Exhibit No.34-1--Project Details
4 and Facilities
5 o Confidential Exhibit No.34-1A-Site Layout
6 o Confidential Exhibit No.34-1-D-
7 Preliminary One-Line Diagrams
8 o Confidential Exhibit No.34-1-E-Wetlands
9 and Surface Water
10 o Confidential Exhibit No.34-2-Site Description
11 o Confidential Exhibit No.34-2-A-
12 Preliminary Metes and Bounds Description
13 o Confidential Exhibit No.34-3-Geology
14 o Confidential Exhibit No.34-3-A-Vicinity
15 Topography
16 o Confidential Exhibit No.34-3-B-
17 Groundwater
18 o Confidential Exhibit No.34-3-C-Surficial
19 Geology
20 o Confidential Exhibit No.34-3-D-Bedrock
21 Geology
22 o Confidential Exhibit No.34-3-E-Mineral
23 Deposits
24 o Confidential Exhibit No.34-4-Natural Resources
25 o Confidential Exhibit No.34-4-A-Visual
1115 Teply,Di-Supp -18
Rocky Mountain Power
1 Resources
2 o Confidential Exhibit No.34-4-B-Visual
3 Simulations
4 o Confidential Exhibit No.34-4-C-Regional
5 Summary
6 o Confidential Exhibit No.34-4-H-Studie.s
7 Status
8 o Confidential Exhibit No.34-4-I-
9 Environmental Studies
10 o Highly Confidential Exhibit No.34-5-Property
11 Acquisition Status
12 o Confidential Exhibit No.34-5-B-Landowner
13 Map
14 o Confidential Exhibit No.34-6-Preliminary
15 Construction Schedule
16 o Confidential Exhibit No.34-7-Site Wind
17 Resource Data
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1116 Teply,Di-Supp -18a
Rocky Mountain Power
1 Q.Please provide a summary of the capital
2 expenditures required to construct the Wind Projects.
3 A.Confidential Exhibit No.35 to my testimony
4 includes the summary.
5 CONCLUSION AND RECOMMENDATION
6 Q.Please explain why the Wind Projects are in the
7 public interest.
8 A.The Wind Projects are in the public interest
9 because:(1)they will become an essential element of the
10 Company's diversified resource portfolio that is needed
11 to serve customers;(2)the facilities are desirable due
12 to location-specific attributes;and (3)the Wind
13 Projects will benefit customers as a whole.
14 Q.Please summarize your recommendation to the
15 Commission.
16 A.I recommend that the Commission determine that
17 the Wind Projects provide significant benefits to
18 customers and therefore are in the public interest.Based
19 on those findings and conclusions,I recommend that the
20 Commission grant the Company the CPCNs for the Wind
21 Projects at the conclusion of these proceedings.
22 Q.Does this complete your supplemental direct
23 testimony?
24 A.Yes.
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1117 Teply,Di-Supp -19
Rocky Mountain Power
1 Q.Are you the same Chad A.Teply who previously
2 submitted testimony in this proceeding on behalf of Rocky
3 Mountain Power ("the Company"),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 in this proceeding?
8 A.I address the limited change to the final
9 shortlist of the Company's 2017R Request for Proposals
10 ("2017R RFP")by updating my previous testimony to
11 describe the new wind resources ("Wind Projects")
12 selected as final shortlist resources in the 2017R RFP
13 and explain how the Wind Projects compare to the original
14 proxy-benchmark resources incorporated into my direct
15 testimony.
16 Q.Please summarize your testimony.
17 A.The Company has updated the final shortlist for
18 the 2017R RFP and replaced the McFadden Ridge II project
19 with the Ekola Flats project,a benchmark included in the
20 Company's initial filing.The Ekola Flats project has
21 remained substantively identical to the project described
22 in my direct testimony.The Company is on track to
23 successfully deliver the Combined Projects by year-end
24 2020 through timely development,procurement,and
25 implementation.All of the steps taken by the Company
1118 Teply,Di-2nd Supp -1
Rocky Mountain Power
1 ensure that the Wind Projects will qualify for production
2 tax credits ("PTCs").
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1119 Teply,Di-2nd Supp -la
Rocky Mountain Power
1 SECOND SUPPLEMENTAL DIRECT TESTIMONY
2 Q.Please describe any changes to the Wind
3 Projects selected to the 2017R RFP final shortlist since
4 the Company's January 16,2018,supplemental filing.
5 A.There is one change to the final shortlist,the
6 109 MW McFadden Ridge II Company benchmark project has
7 been replaced by the 250 MW Ekola Flats Company benchmark
8 project.Thus,the Wind Projects selected to the 2017R
9 RFP final shortlist are still four facilities in Wyoming,
10 which now total approximately 1,311 MW:
11 1.Ekola Flats -250 MW Company benchmark;
12 2.TB Flats I and II (combined into single
13 project)-500 MW Company benchmark;
14 3.Cedar Springs -400 MW third-party
15 build-transfer and power purchase
16 agreement;and
17 4.Uinta -161 MW third-party build-transfer.
18 Q.How do these projects relate to the benchmark
19 projects included in the initial application?
20 A.The Ekola Flats and TB Flats I and II projects
21 were benchmark projects included in the Company's initial
22 application.The Cedar Springs and Uinta projects were
23 not included in the Company's initial application,but
24 were included in the Company's January 16,2018,
25 supplemental filing.
1120 Teply,Di-2nd Supp -2
Rocky Mountain Power
1 Q.Has the Ekola Flats project substantively
2 changed since the Company provided detailed information
3 in its initial application?
4 A.No.The Ekola Flats project selected to the
5 updated final shortlist is substantively identical to the
6 project described in my direct testimony (Teply Direct,
7 page 17 lines 4-
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1121 Teply,Di-2nd Supp -2a
Rocky Mountain Power
1 6;Confidential Exhibit No.1.Ekola Flats is still a
2 nominal 250 MW wind facility located in Carbon County,
3 Wyoming.It is currently being developed by a third-party
4 under a Development Transfer Agreement and will be
5 delivered by the Company under an engineer,procure,and
6 construct ("EPC")contractual structure,with a turbine
7 supply agreement ("TSA")being the other major commercial
8 agreement for the project.Ekola Flats is expected to
9 have approximately 64 2.3-MW-to-4.2-MW wind turbine
10 generators.The facility will consist of an electrical
11 collection system,one (two,if more economic)
12 34.5-kilovolt ("kV")to 230-kV collector substation,
13 230-kV breakers,and 230-kV infrastructure between the
14 wind project and the point-of-interconnection substation,
15 meteorological towers,access roads,required
16 communication and control facilities (e.g.,metering,
17 hardware,software,and associated communication circuits
18 and other equipment),and an operations and maintenance
19 ("O&M")building.
20 Q.What are the total updated costs for the Wind
21 Projects?
22 A.The Wind Projects are estimated to cost $1.46
23 billion,based on their total nominal capacity of 1,311
24 MW and recognizing the split procurement attributes of
25 the Cedar Springs facility.This compares to the
1122 Teply,Di-2nd Supp -3RockyMountainPower
1 Company's initial estimated costs of $1.37 billion for
2 860 MW of nominal capacity described in my direct
3 testimony (Teply Direct,page 5 line 13).
4 On a cost per kilowatt of installed capacity,
5 the Wind Projects are estimated to cost approximately
6 $1,310 per kilowatt,again recognizing the split
7 procurement attributes of the Cedar Springs project.This
8 amount is lower than the cost per kilowatt estimate for
9 the initial benchmark projects,as well as the original
10 shortlist projects included in the January 16,2018,
11 supplemental direct testimony.Thus,the Wind
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1123 Teply,Di-2nd Supp -3a
Rocky Mountain Power
1 Projects selected to the 2017R RFP final shortlist
2 provide additional capacity while continuing to deliver
3 significant customer benefits.The overall costs of the
4 Combined Projects reflected in this filing are generally
5 consistent with the costs included in the initial filing.
6 Q.Does the Ekola Flats project rely on the
7 Transmission Projects for interconnection?
8 A.Yes.The Ekola Flats project relies on the
9 construction of the Transmission Projects,which will
10 relieve existing congestion and allow interconnection of
11 the Wind Projects.In total,the benefits generated by
12 the Wind Projects'zero-fuel-cost generation,which
13 lowers net power costs and provides 10 years of federal
14 PTCs,continue to support cost-effective development of
15 the Transmission Projects.
16 Q.Does the Ekola Flats project meet the Internal
17 Revenue Service's ("IRS")start-of-construction criteria
18 to qualify for PTCs?
19 A.Yes.The Ekola Flats project has sufficient
20 wind turbine generator equipment procured before December
21 31,2016,to meet the start-of-construction definition
22 for tax purposes.The procurement transaction for Ekola
23 Flats satisfies the safe-harbor requirements under the
24 PTC guidance issued by the IRS.
25 Q.How does the Company plan to continue to
1124 Teply,Di-2nd Supp -4
Rocky Mountain Power
1 procure the Ekola Flats project?
2 A.The Company will continue to engage the Ekola
3 Flats shortlisted EPC and TSA counterparties in
4 negotiations to finalize terms and conditions,with a
5 target for executable definitive agreements by April 16,
6 2018,to align with the ongoing regulatory review
7 proceedings .
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1125 Teply,Di-2nd Supp -4aRockyMountainPower
1 CONTINUED DEVELOPMENT,NEGOTIATIONS,AND IMPLEMENTATION
2 Q.Does re-introduction of the Ekola Flats project
3 require additional landowner notifications?
4 A.Yes.Under the Wyoming Certificate of Public
5 Convenience and Necessity statute applicable to wind and
6 transmission facilities,additional landowner
7 notifications are required for the 230 kV interconnection
8 infrastructure for the Ekola Flats project.Notifications
9 will be sent to landowners within 2,000 feet of any 230
10 kV transmission infrastructure related to the project.
11 This approach is consistent with notifications provided
12 to landowners when the Company filed supplemental direct
13 testimony.
14 Q.Is an application with the Wyoming Industrial
15 Siting Council ("ISC")for the Ekola Flats project being
16 prepared?
17 A.Yes.The ISC Permit Application for the Ekola
18 Flats project is being developed and will be filed timely
19 to support year-end 2020 in-service date now that the
20 project has been selected to the 2017R RFP final
21 shortlist.Based upon a review of the shortlisted project
22 schedules,the Company expects the ISC review processes
23 and hearings for the Ekola Flats project will be
24 completed in 2018,subject to updates identified during
25 agency coordination and development of a detailed project
1126 Teply,Di-2nd Supp -5
Rocky Mountain Power
1 implementation plan.The ISC is required to hold a
2 hearing within ninety days of each application under W.S.
3 §35-12-109.
4 Q.Has the Company performed preliminary
5 evaluations of the wind potential at the Ekola Flats
6 project site?
7 A.Yes.The Company submitted a third-party wind
8 potential assessment for Ekola Flats as part of its 2017R
9 RFP benchmark proposal.The Company's 2017 RFP evaluation
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1127 Teply,Di-2nd Supp -5a
Rocky Mountain Power
1 team also validated wind potential with a third-party
2 wind resource evaluation firm as part of the 2017R RFP
3 process,as described in the Company's supplemental
4 direct testimony.Wind assessments for the Ekola Flats
5 project indicate that the site has a favorable wind
6 regime suitable for a high performance wind resource.Due
7 to its proximity to the Company's existing Seven Mile
8 Hill wind project,the Company is confident in the
9 anticipated performance of the Ekola Flats project on a
10 net capacity factor basis.
11 Q.Has the Company determined who will be
12 responsible for construction of the Ekola Flats project?
13 A.Not yet.The Company is negotiating with
14 shortlisted EPC contractors that submitted formal
15 proposals for the Ekola Flats project in 2017.
16 Q.Has the Company determined who will supply the
17 wind turbine generators for the Ekola Flats project?
18 A.Yes.The Company is finalizing negotiations
19 with the shortlisted turbine suppliers that submitted
20 formal proposals for the Ekola Flats project follow-on
21 turbines in 2017 and as identified in its 2017R RFP
22 benchmark proposal.The Company has acquired or has
23 rights to acquire safe-harbor wind turbine generator
24 equipment which it proposes to use at the Ekola Flats
25 project as required to meet the IRS's
1128 Teply,Di-2nd Supp -6RockyMountainPower
1 start-of-construction criteria for PTC eligibility.
2 Q.How did the Company generate the cost
3 information for construction,operation,and maintenance
4 of the Ekola Flats project through its useful life?
5 A.As discussed in my supplemental direct
6 testimony in this docket,the Company prepared its
7 capital cost estimates for the Wind Projects using
8 information from a
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1129 Teply,Di-2nd Supp -6a
Rocky Mountain Power
1 variety of sources.O 2 For its Ekola Flats benchmark project,the
3 Company obtained wind turbine costs from solicitations in
4 2016 to procure the Company's safe-harbor wind turbine
5 generator equipment,and in 2017 for follow-on wind
6 turbine generator equipment.The Company also obtained
7 balance of plant engineering,procurement,construction,
8 and commissioning costs from a solicitation in 2017 to
9 support final submittals in the 2017R RFP process.
10 Transmission interconnection costs were estimated using
11 comparable wind facility transmission studies and prior
12 project experience,and internal project development,
13 management and permitting costs were estimated based upon
14 the Company's experience with construction of past wind
15 facilities and other recent generation resource
16 additions.The Company applied contingencies in various
17 cost categories to account for project uncertainties
18 given the current stage of development of the project.
19 O&M cost estimates were developed based upon the
20 Company's experience with wind resource O&M budgets and
21 third-party contracts for the Company's existing wind
22 facilities.Ongoing capital costs were estimated based
23 upon the Company's experience and indicative costs
24 provided by wind turbine generator suppliers for critical
25 capital components.
1130 Teply,Di-2nd Supp -7
Rocky Mountain Power
1 Q.Will the Company and third-party developers
2 collaborate with the Wyoming Game and Fish Department,
3 the U.S.Fish and Wildlife Service,and other
4 environmental agencies to develop and implement the Ekola
5 Flats project?
6 A.Yes.The Company and the third-party project
7 developer have initiated discussions with the Wyoming
8 Game and Fish Department and the U.S.Fish and Wildlife
9 Service regarding developing and implementing the Ekola
10 Flats project.The Company and the
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1131 Teply,Di-2nd Supp -7a
Rocky Mountain Power
1 third-party project developer have also begun
2 pre-construction usage surveys for various avian,bat,
3 and wildlife species using recommendations from
4 applicable state and federal guideline documents,
5 including the 2012 Land Based Wind Energy Guidelines.The
6 Company and the third-party project developer will
7 coordinate with county,state,and federal agencies that
8 have jurisdiction over development,permitting,and
9 operations to ensure appropriate environmental and safety
10 measures are implemented throughout the life of all of
11 the Wind Projects.The Company is committed to
12 establishing development and implementation schedules and
13 protocols that recognize the potential environmental
14 impacts of all of the Wind Projects and strive to
15 mitigate negative impacts.
16 Q.Will the Ekola Flats wind turbine generators or
17 associated infrastructure be built in Wyoming's Greater
18 Sage Grouse Core area?
19 A.No.The Ekola Flats wind turbine generators and
20 associated infrastructure will not be located within the
21 current boundaries of Wyoming's Greater Sage Grouse Core
22 area.
23 Q.How will potential visual and lighting impacts
24 from the Ekola Flats project be addressed?
25 A.State and county permitting regulations contain
1132 Teply,Di-2nd Supp -8
Rocky Mountain Power
1 requirements that recognize and address potential visual
2 and lighting impacts.The Company and the third-party
3 developer will incorporate those applicable measures into
4 the siting,construction,and operations of the Ekola
5 Flats projects as part of the permitting process.Such
6 measures may include:down-shielded lighting on project
7 infrastructure;Federal Aviation Administration
8 approved/recommended turbine lighting protocols;active
9 aviation light management;and use of approved paint
10 colors for turbines.
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1133 Teply,Di-2nd Supp -Ba
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1 Q.When will construction of the Ekola FlatsO2projectbeginandend?
3 A.As described in detail in the exhibits attached
4 to my testimony,site construction of the Ekola Flats
5 project will begin as soon as the second quarter of 2019.
6 The Company and the third-party developer will not begin
7 construction,however,until all of the necessary
8 regulatory approvals and applicable permits and
9 authorizations from other local,state,tribal or federal
10 governmental agencies that have jurisdiction over the
11 construction or operation of the Ekola Flats project have
12 been received,including approval from the Wyoming ISC.
13 The Company anticipates that substantial completion for
14 the Ekola Flats project,under normal construction
15 circumstances,weather conditions,labor availability and
16 materials delivery,will be achieved by November 15,
17 2020,or as otherwise updated during detailed negotiation
18 of project contracts,schedules,and implementation
19 plans.
20 Q.What is the expected operational life of the
21 Ekola Flats project?
22 A.The anticipated operational life of the Ekola
23 Flats project has been assessed at 30 years in this
24 filing,which aligns with the Company's currently
25 approved depreciable life for wind resources.The
1134 Teply,Di-2nd Supp -9
Rocky Mountain Power
1 operational life may be reviewed and extended based on
2 advances in turbine technologies or improvements in
3 maintenance processes (or both)through the course of the
4 Company's regular depreciation studies and filings.
5 Q.Will the Ekola Flats project be decommissioned
6 or repowered at the end of its operational life?
7 A.The Company may dismantle and reclaim the Ekola
8 Flats project at the end of its operational life based
9 upon the requirements of the operating permit.Typically,
10 county and state agencies identify the decommissioning
11 requirements during the permitting
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1135 Teply,Di-2nd Supp -9aRockyMountainPower
1 process,including expected reclamation efforts and
2 overall decommissioning costs and security requirements.
3 The Company may also consider replacing or upgrading the
4 existing infrastructure at the end of the operational
5 life if conditions (i.e.,economics,permitting,customer
6 load needs,etc.)are conducive to reinvestment in the
7 project.
8 Q.Has the Company provided information on the
9 estimated costs for Ekola Flats?
10 A.Yes.Confidential Exhibit No.47 is a summary
11 of estimated costs for the Ekola Flats,TB Flats I and
12 II,Cedar Springs,and Uinta Wind Projects.Company
13 witness Mr.Rick T.Link provides information including
14 data and models used in the analysis of the Combined
15 Projects,and describes other cost information considered
16 recoverable.
17 Q.Please describe the exhibits attached to this
18 testimony for the nominal 250 MW Ekola Flats facility.
19 A.Confidential Exhibit No.46 provides
20 information for the nominal 250 MW Ekola Flats project.
21 Subparts to that exhibit include:
22 o Confidential Exhibit No.46-1:Updated
23 Wind Turbine Generator Site Layout
24 o Confidential Exhibit No.46-7:Updated
25 Project Map
1136 Teply,Di-2nd Supp -10
Rocky Mountain Power
1 o Confidential Exhibit No.46-14:Signed
2 Large Generator Interconnection Agreement
3 o Confidential Exhibit No.46-16:
4 Third-party Wind Assessments
5 Q.Please provide a summary of the capital expenditures
6 required to construct the Wind Projects.
7 A.Confidential Exhibit No.47 to my testimony includes
8 the summary.
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1137 Teply,Di-2nd Supp -10a
Rocky Mountain Power
1 Q.Please describe the exhibits included with this
2 testimony labeled Confidential Exhibit No.31-4 and
3 Confidential Exhibit No.32-1.
4 A.To clarify the locations of the 230 kilovolt
5 transmission tie-in lines for the Cedar Springs and the
6 TB Flats I and II wind projects,Confidential Exhibit No.
7 31-4 and Confidential Exhibit No.32-1 filed with my
8 supplemental testimony on January 16,2018,were updated.
9 These exhibits replace the original Confidential Exhibit
10 No.31-4 for Cedar Springs and the original Confidential
11 Exhibit No.32-1 for TB Flats in their entirety.
12 CONCLUSION AND RECOMMENDATION
13 Q.What do you conclude in your second
14 supplemental direct testimony?
15 A.The Combined Projects remain well positioned to
16 provide customer benefits and are being effectively
17 developed concurrently with ongoing regulatory
18 proceedings--including the 2017R RFP,procurement
19 activities,and upcoming permitting--to mitigate project
20 risks and deliver desired outcomes.The Company continues
21 to manage project-development activities within a
22 reasonable timeline to assess project risks,incorporate
23 those assessments into decision-making,and allow for
24 changes in project direction (i.e.,off-ramps),if
25 necessary.The Company appreciates the parties'
1138 Teply,Di-2nd Supp -11
Rocky Mountain Power
1 engagement,and believes the Combined Projects will
2 benefit from this rigorous stakeholder review before the
3 Company makes major commitments to the projects.
4 Q.Does this conclude your second supplemental
5 direct testimony?
6 A.Yes.
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1139 Teply,Di-2nd Supp -lla
Rocky Mountain Power
1 Q.Are you the same Chad A.Teply who previously
2 submitted testimony in this case on behalf of Rocky
3 Mountain Power ("Company"),a division of PacifiCorp?
4 A.Yes.
5 PURPOSE AND SUMMARY OF TESTIMONY
6 Q.What is the purpose of your supplemental
7 rebuttal testimony in this proceeding?
8 A.I support the Company's request for
9 certificates of public convenience and necessity
10 ("CPCNs")and binding ratemaking treatment for new wind
11 resources ("Wind Projects")and the Aeolus-to-Bridger/
12 Anticline line and network upgrades ("Transmission
13 Projects")(collectively,the "Combined Projects"),by
14 responding to the supplemental testimony submitted by
15 Monsanto witness Mr.Nicholas L.Phillips,PacifiCorp
16 Idaho Industrial Customers ("PIIC")witness Mr.Bradley
17 G.Mullins,and Staff witnesses Mr.Michael Louis and Mr.
18 Michael Eldred.
19 Q.Please summarize your testimony.
20 A.The conditions proposed by Mr.Phillips,Mr.
21 Mullins,and Mr.Louis are unsupported,and my
22 understanding is that none of them have ever been applied
23 to the Company's past resource acquisitions.Further,
24 these witnesses have not presented any basis to upend the
25 traditional regulatory compact as it pertains to the
1140 Teply,Supp-Reb -1
Rocky Mountain Power
1 Combined Projects.
2 The Wind Projects'cost risks that Mr.Eldred
3 identifies are project implementation concerns that are
4 managed and mitigated in the normal course of business
5 during new generation development.The Company has
6 extensive experience addressing and mitigating these
7 risks.
8 Now that the 2017R Request for Proposals has
9 concluded,and as final contract negotiations progress,
10 the risks associated with the Combined Projects continue
11 to
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1141 Teply,Supp-Reb -la
Rocky Mountain Power
1 decrease.The Company is now better positioned to provide
2 customer benefits through the timely development of the
3 Wind Projects.
4 RESPONSE TO PROPOSED CONDITIONS
5 Q.Mr.Phillips continues to recommend that the
6 Commission impose several conditions if the CPCN is
7 approved.(Phillips Supp.Direct,page 3,line 9 to page
8 4 line 11 and again on page 59,line 15 to page 60,line
9 11.)Do you have any additional concerns about these
10 proposed conditions?
11 A.Yes.The Company addressed Mr.Phillips'
12 conditions in its rebuttal testimony (see,e.g.,Teply
13 Rebuttal,page 11,line 8 to page 18,line 3),and the
14 Company continues to object to Mr.Phillips'
15 recommendation for the same reasons already stated-most
16 notably because they are unprecedented and depart from
17 Commission practice that is not justified based on the
18 nature of the Combined Projects.To propose a punitive
19 cap on capital costs and overly onerous conditions
20 regarding other project costs and performance criteria,
21 as Mr.Phillips has done,is counterproductive to the
22 ongoing proceedings and discourages innovative resource
23 development in the future.In particular,the $1,781.44
24 million cost cap referenced in Mr.Phillips'testimony
25 does not in any way reflect the reasonable costs to
1142 Teply,Supp-Reb -2RockyMountainPower
1 deliver the Combined Projects.O 2 Q.Have other parties also proposed cost caps?
3 A.Yes.Both Mr.Mullins (Supp.Direct,page 4,
4 lines 4-21),and Mr.Louis (Supp.Direct,page 14,lines
5 8-19),have proposed hard caps for the Combined Projects
6 at the amounts presented in the Company's Supplemental
7 Direct testimony.Similar to Mr.Phillips'proposed hard
8 caps,Mr.Mullins'and Mr.Louis'proposed hard caps are
9 also unprecedented,not justified based on the nature of
10 the Combined Projects,and a depart
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1143 Teply,Supp-Reb -2a
Rocky Mountain Power
1 from Commission practice.While Mr.Mullins1 and Mr.
2 Louis claim to base their respective hard cap
3 recommendations on the Company's estimated costs for the
4 Combined Projects,a hard cap with no opportunity for
5 recovery of prudently incurred costs above the hard cap
6 is not appropriate for major projects at this stage of
7 development and implementation (i.e.pre-approval stage).
8 The Company should have the ability to prudently manage
9 unforeseen circumstances to deliver the Combined Projects
10 and present its case,recognizing that the Commission
11 will ultimately determine whether any such actions and
12 costs were prudently deployed.The Company has
13 historically prudently managed its projects through
14 development,implementation,and operation,and the
15 Commission should have the opportunity to review all
16 costs incurred to implement the Company's resource
17 additions.The Company has never been incentivized to
18 proceed at any cost as Mr.Mullins'and Mr.Louis'
19 conditions would presume,and nothing about the Combined
20 Projects diminishes the Company's incentive to meet its
21 cost estimates.
22 Q.How is the Company mitigating the cost and
23 performance risks that form the basis of Mr.Phillips'
24 proposed conditions?
25 A.The Company relies extensively on the contract
1144 Teply,Supp-Reb -3
Rocky Mountain Power
1 negotiation process to mitigate many of the risks
2 discussed by Mr.Phillips.For example,the Company is
3 currently negotiating the engineering,procurement,and
4 construction contracts for the benchmark Wind Projects
5 and negotiating the build-transfer agreements ("BTA")for
6 the BTA Wind Projects.These contracts will have robust
7 risk-mitigation provisions,
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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.
1145 Teply,Supp-Reb -3a
Rocky Mountain Power
1 including fixed construction costs,terms and conditions
2 to guarantee on-time delivery of the resources,
3 counterparty representation and warranties,and
4 commercially available indemnities and securities.The
5 Company is currently engaged with each of the Wind
6 Project developers,and with the shortlisted benchmark
7 construction contractors and wind turbine generator
8 suppliers,to finalize definitive agreements in parallel
9 with the ongoing regulatory reviews of the Combined
10 Projects.
11 The Company is also continuing with its
12 detailed due diligence and support of each of the Wind
13 Projects as their individual project development
14 activities continue with state and local permitting
15 activities,public outreach,engagement of state and
16 federal wildlife agencies,as well as landowners,
17 leaseholders,and affected mineral rights holders,where
18 applicable.
19 Q.Can the Company also use contracting to
20 mitigate the risk of greater-than-expected operational
21 expenses and reduced equipment availability through the
22 life of the Wind Projects?
23 A.Yes.The Company has previously described its
24 intent to negotiate third-party maintenance contracts for
25 the Wind Projects that will address operations and
1146 Teply,Supp-Reb -4RockyMountainPower
1 maintenance cost and run-rate capital expenditure risks
2 for the Wind Projects.The Company will also negotiate
3 availability guarantees for the Wind Projects in any
4 third-party-provided maintenance agreements,as provided
5 by the competitive market.In the Company's ongoing wind
6 repowering project negotiations,the Company secured
7 performance guarantees established at a production rate
8 of (redacted)///////////////////////////////////////
9 ///////.It is reasonable to expect that similar
10 guarantees can be negotiated for the Wind Projects.While
11 the
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1147 Teply,Supp-Reb -4a
Rocky Mountain Power
1 Company cannot guarantee future outcomes,development of
2 the Wind Projects will include these important
3 risk-mitigation measures,similar to those that have been
4 included to support past investments.
5 Q.Mr.Phillips recommends capping the Company's
6 net fixed system costs to those levels assumed in the
7 Company's economic analyses for the life of the Wind
8 Projects.(Phillips Corrected Supp.Response,page 3,
9 lines 21-23,and page 59,lines 26-28.)Is this condition
10 reasonable?
11 A.No.Mr.Phillips'proposal to cap recovery of
12 net fixed system costs ignores the reality that the
13 Company's generation resources and net system fixed costs
14 will continue to evolve around the Combined Projects over
15 their life as economic development opportunities,
16 individual project developments,energy industry
17 regulations and policies evolve.
18 Requiring the Company to guarantee these future
19 outcomes is another example of Mr.Phillips proposing an
20 unprecedented and unsupported condition that goes well
21 beyond the existing regulatory compact.
22 Q.Mr.Phillips continues to recommend that the
23 Company include in base rates and net power costs the
24 full PTC benefits and energy benefits based on the
25 assumed net capacity factors included in the Company's
1148 Teply,Supp-Reb -5
Rocky Mountain Power
1 filing.(Phillips Supp.Direct,page 4,lines 1-5.)Do
2 you agree?
3 A.No.I explained in rebuttal testimony why the
4 imputation of the estimated capacity factor is
5 unreasonable (see Teply Rebuttal Testimony,page 14,line
6 1 through page 18,line 3.)The Company has used the best
7 information currently available to estimate the
8 production of the new Wind Projects.Actual production is
9 an example of an item
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1149 Teply,Supp-Reb -5aRockyMountainPower
1 beyond the Company's control,as discussed by Mr.Keller
2 in his direct testimony.Mr.Keller noted that the
3 Company's assumptions "were within a reasonable range"
4 and that "risks and uncertainties can be categorized into
5 one of two groups:those the company can control and
6 those it cannot."(Keller Direct,page 3,lines 10-13,
7 and page 4,lines 5-7).
8 Q.Mr.Phillips also claims there is a risk that
9 avian impacts may cause excessive curtailment of the Wind
10 Projects.(Phillips Supp.Direct,page 56,lines 4-9).
11 Has Mr.Phillips substantiated this concern?
12 A.No.Mr.Phillips speculates that avian issues
13 "could"require curtailment at any of the Wind Projects
14 and follows with the general association that curtailment
15 "could"then cause the output and related PTCs to be
16 lower than assumed in the Company's analysis.
17 The Company has significant experience
18 operating its Wyoming wind resources to protect
19 threatened and endangered avian species,and has active
20 curtailment programs at two existing wind plants.To meet
21 its obligations,the three-year average megawatt hours of
22 wind generation curtailment has been approximately 0.4
23 percent and 1.1 percent of total megawatt-hours produced
24 at the two facilities where avian curtailment occurs.
25 Recognizing the variable nature of the wind resource,and
1150 Teply,Supp-Reb -6
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1 that curtailment protocols have been allowed by the
2 agencies having jurisdiction to balance protection of
3 wildlife with optimizing use of these renewable
4 resources,the Company does not consider curtailment
5 protocols to be a risk driver that would justify
6 rejection of the Wind Projects or warrant specific CPCN
7 conditions.In addition,the Company's avoidance,
8 minimization,and mitigation actions anticipated for
9 future projects are expected to reduce or eliminate the
10 potential usage of informed curtailment.Those
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1151 Teply,Supp-Reb -6a
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1 efforts include raptor nest buffers,habitat setbacks,
2 and micro-siting of wind turbines based on known wildlife
3 usage patterns.As with the Company's objection to
4 guaranteed capacity factors,any annual fluctuations in
5 energy production due to curtailment protocols are well
6 within the intended application of the existing energy
7 cost adjustment mechanism.
8 RESPONSE TO OTHER RISKS
9 Q.Mr.Eldred identifies testimony submitted in
10 the Wyoming CPCN proceeding by Anadarko regarding
11 split-estate landowner concerns.He raises a concern that
12 the issues raised by Anadarko are a significant future
13 cost risk for the Wind Projects.(Eldred Supp.Direct,
14 page 16,lines 2-18.)Has the Company taken steps to
15 address Anadarko's concerns and mitigate future cost risk
16 for the Wind Projects?
17 A.Yes.The Company and Anadarko reached an
18 agreement on a path forward to mitigate their concerns on
19 split-estates,which resulted in Anadarko withdrawing
20 from the Wyoming proceeding.The Company intends to
21 implement similar measures with other concerned
22 split-estate landowners to facilitate cost-effective
23 development and implementation of the Wind Projects.
24 Resolution of Anadarko's concerns has not materially
25 impacted any of the economic analysis supporting the
Combined Projects.
1152 Teply,supp-Reb -7
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1 Q.Mr.Eldred also identifies testimony submitted
2 by Anadarko in Wyoming regarding potential schedule risks
3 associated with a need for a supplemental federal
4 Environmental Impact Study ("EIS")for the Wind Projects
5 due to their parallel track implementation plans with the
6 Transmission Projects.(Eldred Supp.Direct,page 18,
7 line 13 to page 19,line 7.)Has the Company addressed
8 this assertion and any associated schedule risk?
9 A.Yes.The Final Gateway West EIS and Record of
10 Decision presented a full National Environmental Policy
11 Act ("NEPA")analysis of each transmission line segment
12 addressing interrelated segments of the same action,
13 dependent actions,reasonably foreseeable future actions,
14 and a cumulative analysis of all actions.The Final EIS
15 addresses the transmission line segments as having
16 independent utility,i.e.,as being usable regardless of
17 additional transmission segments or generation
18 improvements in the project area are constructed.
19 The Wind Projects as "renewable generation"
20 were considered in the Final EIS analysis as part of
21 potential projects contained in PacifiCorp's large
22 generator interconnection queue,and the Wind Projects do
23 not require NEPA analysis as they are fully contained on
24 state and private land.Thus,the Wind Projects are not
25 "connected actions"that require the Company to file a
1153 Teply,Supp-Reb -8
Rocky Mountain Power
1 supplemental EIS.Each of the Wind Projects have their
2 own permitting requirements that will be completed by the
3 respective project developers.
4 Q.Has the Bureau of Land Management ("BLM")
5 confirmed the Company's position that no supplement to
6 the EIS is necessary?
7 A.Yes,in a March 27,2018 letter to the Lincoln
8 County Commission,the Wyoming State
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1154 Teply,Supp-Reb -8a
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1 BLM Director agreed that no supplemental EIS is required.
2 A copy of the BLM letter is provided as Exhibit No.66.
3 CONCLUSION AND RECOMMENDATION
4 Q.What do you conclude in your supplemental
5 rebuttal testimony?
6 A.The conditions proposed by Mr.Mullins,Mr.
7 Phillips,and Mr.Louis are unsupported,and my
8 understanding is that none of them have been applied to
9 the Company's past resource acquisitions.Further,the
10 parties have presented no basis to upend the traditional
11 regulatory compact as it pertains to the Combined
12 Projects.
13 Q.Does this conclude your supplemental rebuttal
14 testimony?
15 A.Yes.
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1155 Teply,Supp-Reb -9
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1 (The following proceedings were had inO2openhearing.)
3 MR.LOWNEY:And Mr.Teply is available
4 for Commissioner questions and cross-examination.
5 COMMISSIONER ANDERSON:Mr.Budge.
6 MR.BUDGE:No questions,Mr.Chairman.
7 COMMISSIONER ANDERSON:Mr.Williams.
8 MR.WILLIAMS:Yes,Mr.Chairman,I do.I
9 have two questions for Mr.Teply.I think he knows
10 exactly what they are if he was listening earlier.
11
12 CROSS-EXAMINATION
13
14 BY MR.WILLIAMS:
15 Q So first of all,Mr.Teply,when did the
16 Company secure the development rights to the TB Flats I
17 and II,Ekola Flats,and McFadden Ridge wind projects?
18 A For the TB Flats I and II and the Ekola
19 Flats projects,those are the development transfer
20 agreements that we secured in early '17 following the
21 issuance of our 2017 IRP and prior to the submittal of
22 our direct testimony in this docket wherein we described
23 those development transfer agreements in support of the
24 application.
25 McFadden is a little bit different.
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1 McFadden is a property that the Company acquired several
2 years ago in conjunction with our High Plains McFadden I
3 project that is in existence today,so that's a different
4 benchmark project than the development transfer
5 agreements that I think you're talking about.
6 Q So when you say early in 2017,can you get
7 a little more specific than that?
8 A Yeah,I think we executed the development
9 transfer agreements after negotiating them,I think,I'm
10 going to use a date of,mid May.That's subject to
11 check,and the important thing,I think,to point out on
12 the development transfer agreements is that those are
13 actually contingent agreements on success through the
14 regulatory processes,so in other words,we secured the
15 right to use those interconnection queue and those
16 development assets to support our proxy benchmark
17 resources at the time back in June.Also,the original
18 developer retained their right to propose and submit
19 project proposals into the 2017 IRP in parallel.
20 Q Okay,I thought these were going to be
21 simple questions,and maybe this was part of your answer,
22 but when I look on your website,I see that the notice,
23 I'm talking about Utah now,the notice of the RFP was
24 issued on September 27th,2017.Was there something in
25 advance of that that was put out to the public,something
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1 in advance of that date?
2 A Yeah,there was and Mr.Link could speak
3 to the RFP process,but following the IRP filing in
4 April,obviously,with the preferred portfolio then
5 incorporating at that time 1,100 megawatts of wind,plus
6 new transmission,a lot of interest in the marketplace.
7 There are a lot of stakeholders that obviously pay
8 attention to the PacifiCorp IRP proceedings,and as you
9 identify new resources,particularly resources that will
10 be delivered prior to 2020,the developers and other
11 participants in,say,that market definitely have an
12 interest in finding out when the follow-on and subsequent
13 RFP will be processed,so subject to check,I would say
14 heading into the application that we have here very much
15 in parallel also starting the dialogue with potential RFP
16 participants.
17 MR.WILLIAMS:All right,thank you,
18 Mr.Chairman.
19 COMMISSIONER ANDERSON:Mr.Olsen.
20 MR.OLSEN:No questions.
21 COMMISSIONER ANDERSON:Mr.Karpen.
22 MR.KARPEN:Thank you.
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1 CROSS-EXAMINATION
2
3 BY MR.KARPEN:
4 Q Good afternoon,Mr.Teply.
5 A Good afternoon.
6 Q I only have a couple of questions for you.
7 I referred earlier with Ms.Crane,you had described a
8 critical path to maintain the development schedule.In
9 your direct testimony,you described that the Company
10 needed a CPCN by March 30th to maintain that development
11 schedule.Is that still the case?
12 A No.Since the direct testimony back in
13 June,obviously,we've tracked through the processes that
14 I just spoke with Mr.Williams about with respect to the
15 IRP,the subsequent RFP,the results of that process,so
16 as we've maintained and developed our project plans,
17 we've adjusted our critical path schedule along the way
18 to accommodate the regulatory proceedings,not only in
19 Idaho,but in the other states that we're progressing
20 through.
21 Q And do you believe that the Company can
22 still maintain its new critical path to qualify for the
23 full PTC benefits?
24 A Yes.
25 Q Excellent.For the record,Staff also
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1 agrees with that;however,we do have concerns there are
2 risks for cost overrun to maintain that critical path.
3 You speak to that in your supplemental rebuttal on page
4 2.Staff expert Louis speaks or you speak to Staff
5 expert Louis'proposed hard caps.You note that such
6 hard caps are unprecedented,not justified based on the
7 nature of the combined projects,and a depart from
8 Commission practice.As we've discussed earlier,the
9 Company has agreed to such hard caps in this very case in
10 other jurisdictions;is that accurate?
11 A As the other witnesses have testified to
12 today,under the broader settlement in the State of
13 Wyoming with multiple other pieces involved,there was a
14 settlement to a hard cap,yes,not at the estimate.
15 Q Sure.Now,you could unpack it to make it
16 just the stipulated projects,though;correct?
17 A I could --maybe will you clarify your
18 question?
19 MR.KARPEN:I'll withdraw.I have no
20 further questions for this witness.
21 COMMISSIONER ANDERSON:Thank you,Mr.
22 Karpen.Commissioner Kjellander.
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1 EXAMINATION
2
3 BY COMMISSIONER KJELLANDER:
4 Q I think I actually understood Mr.Karpen's
5 question,so I'm going to go ahead and take a run at it.
6 Even though you had a stipulation in Wyoming,you could
7 identify what that hard cap was that you actually agreed
8 to;correct?This wasn't a black box settlement over
9 there,was it?
10 A No,we can identify the number.I think
11 Mr.Link actually did earlier today in the hearing
12 testimony,if I'm tracking your question.
13 Q Do you recall what he said,because
14 apparently Mr.Karpen didn't and I don't recall either?
15 A Okay,I thought he referred to a number in
16 his stipulation testimony.Can I look at it real quick?
17 I think it's in there;is that okay?
18 Q That would be fine.
19 MR.LOWNEY:Mr.Teply,if it would help,
20 page 9 of Mr.Link's settlement testimony on line 16 is
21 the number that he referred to earlier and it's a
22 non-confidential number.The two numbers around it are
23 confidential,but the percentage is not.
24 THE WITNESS:Yes,so yes,I can identify
25 that number.
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1 Q COMMISSIONER KJELLANDER:And?
2 A Oh,I'm sorry,yes,the 11.1 percent
3 number.
4 Q Okay.
5 A I'm not sure I'm tracking the question.
6 Q Apparently not.
7 A I'm sorry.
8 COMMISSIONER KJELLANDER:Let's bag and
9 tag it.No more.I'm done.
10 COMMISSIONER ANDERSON:Any redirect?
11 MR.LOWNEY:I just have one question.
12
13 REDIRECT EXAMINATION
14
15 BY MR.LOWNEY:
16 Q Mr.Teply,do you recall when Mr.Williams
17 asked you about the timing of the notice that was made
18 with the Utah Commission related to the issuance of the
19 2017R RFP?
20 A I do recall the question,yes.
21 Q And at least what I heard,and I just want
22 to clarify,was I believe Mr.Williams indicated that
23 that notice was issued in September of 2017.
24 A That was his reference in his question,
25 yes.
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1 Q And isn't it true that that notice was
2 issued in April of 2017,the notice of the intent to
3 issue the RFP?
4 A Subject to check.As I have responded to
5 the question,that's why I mentioned there was a parallel
6 proceeding.I didn't know the date exactly with respect
7 to the issuance,but subject to correct,that sounds
8 correct.
9 MR.LOWNEY:All right,no further
10 questions.
11 COMMISSIONER ANDERSON:Thank you.Thank
12 you very much.
13 (The witness left the stand.)
14 COMMISSIONER ANDERSON:You may call your
15 next witness.
16 MS.McDOWELL:With the exception of Ms.
17 Kobliha who is not available to testify until tomorrow,
18 that concludes the Company's direct presentation of its
19 case,and I guess we would just end.We also presented
20 our rebuttal and supplemental rebuttal testimony,so we
21 would just rest with reserving the right to call
22 witnesses to rebut other testimony that comes in in the
23 next part of the proceeding.
24 COMMISSIONER ANDERSON:Certainly.
25 MS.McDOWELL:Thank you.
CSB REPORTING 1163 TEPLY (ReDi)
208.890.5198 Rocky Mountain Power