20180529Technical Hearing Transcript Vol IV.pdf

O 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 )
EACILITIES )
BEFORE
COMMISSIQNER ERIC ANDERSON (Presiding)en
COMMISSIONER KRISTINE RAPER
COMMISSIONER PAUL KJELLANDER
O
PLACE:Commission Hearing Room
472 West Washington Avenue
Boise,Idaho
DATE:May 11,2018
VOLUME IV -Pages 1491 -1938
ORIGINAL CSB REPORTING
O Certified Shorthand Reporters
PostOfficeBox9774 Reporter:Boise,Iddio 83707 Constance Bucy,[e-mail] CSRPh:208-890-5198 Fax:[phone]
1 A PPE A R A NCES
(III 2
3 For the Staff:Mk.Brandon Karpen
Deputy Attorney General
4 472 West Washington
Boise,Idaho 83720-0074
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For Rocky Mountain Ms.Katherine A.McDowell
6 Power:and NW.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:Mt.Randall C.Budge
and Thomas J.Budge
13 Racine,Olson,Nye &Budge
O 201 East Center
14 PO Box 1391
Pocatello,Idaho 83204-1391
15
For PIIC:Nk.Ronald L.Williams
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
2 WITNESS EXAM NT ON BY PAGE
3 Bradley Mullins Mr.Williams (Direct)1491
(PIIC)Direct Testimony 1494
4 Supplemental Testimony 1565
Mr.Williams (Direct-Cont'd)1637
5 Mr.Lowney (Redirect)1641
Mr.Karpen (Cross)1654
6 Commissioner Raper 1656
Commissioner Kjellander 1659
7 Mr.Williams (Redirect)1662
8 Anthony Yankel Mr.Olsen (Direct)1664
(PIIC)Direct Testimony 1666
9 Supplemental Testimony 1709
Mr.Olsen (Direct-Cont'd)1729
10 Mr.Lowney (Redirect)1732
Mr.Karpen (Cross)1742
11 Commissioner Kjellander 1743
Mr.Olsen (Redirect)1744
12
Nikki Kobliha Mr.Lowney (Direct)1747
13 (RMP)Supplemental Testimony 1749
14 Michael Eldred Mr.Karpen (Direct)1764
(Staff)Supplemental Testimony 1766
15 Mr.Budge (Cross)1789
Ms.McDowell (Cross)1795
16 Commissioner Raper 1802
Mr.Karpen (Redirect)1804
17
Richard Keller Mr.Karpen (Direct)1806
18 (Staff)Direct Testimony 1808
Ms.McDowell (Cross)1834
19 Mr.Karpen (Redirect)1846
20 Michael Louis Mr.Karpen (Direct)1850
(Staff)Direct Testimony 1853
21 Supplemental Testimony 1874
Mr.Budge (Cross)1897
22 Mr.Williams (Cross)1899
Mr.Olsen (Cross)1904
23 Ms.McDowell (Cross)1906
Commissioner Raper 1908
24 Mr.Karpen (Redirect)1911
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CSB REPORTING INDEX
208.890.5198
1 I NDEX (Continued)
2 WITNESS EXAMINATION BY PAGE
3 Terri Carlock Mr.Karpen (Direct)1914
(Staff)Settlement Testimony 1916
4 Mr.Karpen (Direct-Cont'd)1922
Mr.Budge (Cross)1926
5 Mr.Williams (Cross)1930
Commissioner Raper 1934
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CSB REPORTING INDEX
208.890.5198
1 EXH I B I TS
2 NUMBER DESCRIPTION PAGE
3 FOR ROCKY MOUNTAIN POWER:
4 70.-74.Admitted 1937
5 75.Excerpt from the testimony of Identified 1643
Mr.Mullins in Docket No.Admitted 1937
6 17-035-40
7 76.Comments from Mr.Mullins to the Identified 1647
Oregon PUC on the 2016 IRP of Admitted 1937
8 Portland General Electric
9 77.Order No.30892 in Case Identified 1733
No.IPC-E-09-03 Admitted 1937
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11
FOR THE STAFF:
12
101.Analysis based on equal Premarked
13 probability of outcome Admitted 1765
14 102.Impact of 2021 Rate Case on Premarked
Idaho Net Benefits Admitted 1765
15
103.The Independent Evaluator's Premarked
16 Final Report on PacifiCorp's Admitted 1765
2017R RFPs
17
104.Confidential exhibit sponsored Premarked
18 by Michael Eldred Admitted 1765
19
20 FOR THE MONSANTO COMPANY:
21 220.Admitted 1937
22
23 FOR PACIFICORP IDAHO INDUSTRIAL CUSTOMERS:
24 301.Regulatory Appearances of Bradley Premarked
25
G.Mullins Admitted 1493
CSB REPORTING EXHIBITS
208.890.5198
1 EXH I B I TS (Continued)O 2 NUMBER DESCRIPTION PAGE
3 FOR PACIFICORP IDAHO INDUSTRIAL CUSTOMERS:(Continued)
4 302.Company Responses to Data Premarked
Requests Admitted 1493
5
303.Forward Curve Forecast Error Premarked
6 Analysis (2007-2016)-Admitted 1493
Confidential
7
304.Forward Curve Forecast Error Premarked
8 Analysis (2007-2016)-Admitted 1493
Confidential
9
305.Company Responses to Data Premarked
10 Requests Admitted 1493
11 306.Impact of Most Recent Load Premarked
Forecast on Resource Needs Admitted 1493
12 Assessment -Confidential
O 13 307.Questions &Answers from May 31,Premarked
2017,Pre-Bidder's Conference Admitted 1493
14
308.Admitted 1937
15
16 FOR IDAHO IRRIGATION PUMPERS ASSOCIATION:
17 401.Exhibit sponsored by Anthony Premarked
Yankel Admitted 1665
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CSB REPORTING EXHIBITS
208.890.5198
1 BOISE,IDAHO,FRIDAY,MAY 11,2018,8:30 A.M.
2
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4 COMMISSIONER ANDERSON:Good morning.
5 We're going to call the technical hearing back to order,
6 PAC-E-17-07,and I believe we finished up with Monsanto
7 yesterday with their testimony and we'll move on to
8 PacifiCorp Industrial Customers if that's the order that
9 you wish to go in.
10 MR.WILLIAMS:Yes,Mr.Chairman,I would
11 call Bradley G.Mullins.
12 COMMISSIONER RAPER:I'd be happy to swear
13 him in for you.
14
15 BRADLEY G.MULLINS,
16 produced as a witness at the instance of the PacifiCorp
17 Idaho Industrial Customers,having been first duly sworn
18 to tell the truth,was examined and testified as follows:
19
20 DIRECT EXAMINATION
21
22 BY MR.WILLIAMS:
23 Q Would you please state your name and
24 business address for the record?
25 A My name is Bradley G.Mullins.My
CSB REPORTING 1491 MULLINS (Di)
208.890.5198 PIIC
1 business address is 1750 SW Harbor Way,Suite 450,
2 Portland,Oregon,97201.
3 Q And are you the same Mr.Mullins that in
4 this case on November 20th,2017,filed 36 pages of
5 direct testimony with Exhibits 301 through 304?
6 A Yes.
7 Q And if I asked you those questions today,
8 would your answers be the same?
9 A They would.
10 Q And are you the same Brad Mullins that
11 filed supplemental direct testimony in this case on April
12 11th,2018,consisting of 37 pages with Exhibits 305
13 through 307?
14 A I am.
15 Q And if I asked you the same questions
16 today contained in that testimony,would your answers be
17 the same?
18 A They would.
19 MR.WILLIAMS:Mr.Chairman,I would ask
20 that Mr.Mullins'testimony be spread upon the record as
21 if read and submit him for --excuse me,I have some
22 additional questions in response to the supplemental,the
23 testimony,the stipulated settlement if I could first go
24 through those with Mr.Mullins.
25 COMMISSIONER ANDERSON:Before you make
CSB REPORTING 1492 MULLINS (Di)
208.890.5198 PIIC
1 the motion to --O 2 MR.WILLIAMS:Oh,I'm sorry.I would
3 just ask that --
4 COMMISSIONER ANDERSON:You may.Without
5 objection,we'll spread Mr.Mullins'testimony,direct
6 and supplemental,and exhibits across the record.
7 MR.WILLIAMS:Thank you,Mr.Chairman.I
8 apologize for the confusion.
9 (PIIC Exhibit Nos.301-307 were admitted
10 into evidence.)
11 (The following prefiled direct and
12 supplemental direct testimonies of Mr.Bradley Mullins
13 are spread upon the record.)
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CSB REPORTING 1493 MULLINS (Di)
208.890.5198 PIIC
1 I .INTRODUCTION AND SUMMARY
2 Q.PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3 A.My name is Bradley G.Mullins,and my business
4 address is 333 SW Taylor Street,Suite 400,Portland,
5 Oregon 97204.
6 Q.PLEASE STATE YOUR OCCUPATION AND ON WHOSE
7 BEHALF YOU ARE TESTIFYING.
8 A.I am an independent energy and utilities
9 consultant representing large energy consumers throughout
10 the United States,with a focus in the West.I am
11 testifying on behalf of the PacifiCorp Idaho Industrial
12 Customers ("PIIC"),a trade association whose members
13 consist of large electric customers served by Rocky
14 Mountain Power ("PacifiCorp")in Idaho.
15 Q.PLEASE SUMMARIZE YOUR EDUCATION AND WORK
16 EXPERIENCE.
17 A.I have a Master of Accounting degree from the
18 University of Utah.After obtaining my Master's degree,
19 I worked at Deloitte in San Jose,California,where I
20 specialized in performing research and development tax
21 credit studies.I later worked at PacifiCorp as an
22 analyst involved in power supply cost forecasting and
23 began working independently as an energy and utilities
24 consultant in 2013.I currently provide services to
25 utility customers on matters such as power costs,utility
1494 Mullins,Di -1
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1 planning,revenue requirements,rate spread,and rate
2 design.A list of cases where I have submitted testimony
3 can be found in Mullins Exhibit No.301.This is the
4 first testimony I have submitted before the Idaho Public
5 Utilities Commission.
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1 Q.WHAT IS THE PURPOSE OF YOUR RESPONSE TESTIMONY?O 2 A.The purpose of my testimony is to respond to
3 PacifiCorp's proposal to construct or procure 860 MW of
4 wind resources (collectively,the "Wind Projects").1
5 I also respond to PacifiCorp's proposal to construct the
6 "Aeolus-to-Bridger/Anticline Line"and associated network
7 upgrades (the "Transmission Projects").2 I refer to the
8 Wind Projects and Transmission Projects collectively as
9 "Energy Vision 2020."
10 PacifiCorp's filing has proposed the Wind
11 Projects and the Transmission Projects as largely
12 inseparable investments.Subsequent to it filing
13 testimony in this matter,however,PacifiCorp has
14 modified its ongoing request for proposal ("RFP")for the
15 Wind Projects,pursuant to an Order from the Utah Public
16 Service Commission.3 One of the modifications was to
17 allow the RFP to consider procuring wind resources in
18 geographic locations that do not require construction of
19 the associated Transmission Projects.This is a source
20 of ambiguity in PacifiCorp's proposal,since it is not
21 clear how the Commission might consider the public
22 convenience and necessity if it is possible that
23 PacifiCorp might procure resources other than the Wyoming
24 wind resources described in its application.
25 Q.WHAT WAS THE SCOPE OF YOUR REVIEW?
1496 Mullins,Di -2
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1 A.I reviewed the confidential,andO2non-confidential,filing and workpapers of PacifiCorp.
3 I also conducted discovery,and reviewed PacifiCorp's
4 responses to discovery requests
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22 1 REDACTED Link,Direct at 2:11-15.
2 Id.
23 3 Application of Rocky Mountain Power for Approval of
Solicitation Process for Wind Resources,Ut.PSC Docket No.
24 17-035-23,Order Approving RFP with Suggested Modification
at 7 (Sep.22,2017).
25 4 Id.
1497 Mullins,Di -2a
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1 submitted in this matter.Responses to data requests
2 relevant to my testimony may be found in Mullins Exhibit
3 No.302.Finally,I conducted a number of supplemental
4 analytics surrounding the economics of Energy Vision
5 2020,such as an analysis reviewing of the accuracy of
6 previously issued official forward price curves.
7 Q.WHAT IS YOUR RECOMMENDATION?
8 A.Based on my review,I recommend the Commission
9 find that the proposed Energy Vision 2020 resources are
10 neither useful nor for the convenience and necessity of
11 Idahoans receiving service in this State.I also
12 recommend the Commission find that Energy Vision 2020 is
13 not in the public interest,and reject the argument that
14 Energy Vision 2020 might provide financial benefits to
15 Idahoans,beyond mere speculation.Based on my review,
16 the case that Energy Vision 2020 might provide actual
17 ratepayer benefits is marginal at best,and accordingly,
18 it is would be unwise to proceed with such a significant,
19 $(redacted)billion investment.
20 Energy Vision 2020 is not a project necessary
21 for reliability purposes.It is being justified
22 primarily in relation to PacifiCorp's forecasts of future
23 power and gas prices.My analysis shows that PacifiCorp
24 has historically overestimated prices in its forward
25 price curve.My review also shows that PacifiCorp's
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1 economic analysis contains a number of speculative
2 assumptions that have material impacts on the economic
3 case for making the investment.
4 II.BACKGROUND ON THE PROPOSAL
5 Q.HOW DOES PACIFICORP'S PROPOSAL RELATE TO ENERGY
6 GATEWAY?
7 A.The Transmission Projects include sub-segment
8 D2 of Energy Gateway.The Energy Gateway was a notion
9 discussed at least as far back as PacifiCorp's 2008
10 Integrated
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1 Resource Plan ("IRP").5 The idea behind the Energy
2 Gateway was to rely on a 'hub and spoke'configuration,
3 to efficiently integrate transmission lines with
4 resources and loads centers.It was designed to
5 "facilitate needed infrastructure to integrate and
6 deliver large volumes of renewable energy in the west."6
7 Subsequent to the Energy Gateway proposal,many
8 stakeholders have questioned the need to make such
9 significant transmission additions.
10 Q.HAVE PARTS OF THE ENERGY GATEWAY HAVE BEEN
11 CONSTRUCTED?
12 A.Yes.Both the 'Populous to Terminal'and
13 'Sigurd to Red Butte'Energy Gateway segments have been
14 constructed.Both were expensive and raised significant
15 controversy.In PacifiCorp's 2010 general rate case,
16 for example,the Commission reviewed the Populous to
17 Terminal Energy Gateway segment.7 The record in that
18 case established that the Populous to Terminal line was
19 originally estimated to cost $78 million,but in fact
20 cost $801 million,the amount requested by PacifiCorp for
21 inclusion in rate base.S In that 2010 case the
22 Commission determined that 27%of the line,or $216.4
23 million,was not used and useful,and was plant held for
24 future use.
25 Q.WHEN DID PACIFICORP FIRST ANNOUNCE ITS PROPOSAL
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1 TO BUILD ENERGY GATEWAY SUB-SEGMENT D2?O 2 A.The idea was introduced late in the public
3 process leading up the 2017 IRP.Over the course of the
4 2017 IRP process,parties were given the impression no
5 further Energy Gateway segments would be proposed to be
6 built in the 2017 IRP action plan.In the
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23 5 See PacifiCorp,2008 Integrated Resource Plan at 60-66 (May
28,2009).
24 6 Id.at 63.
7 Case No.PAC-E-10-07
25 8 Id.See Order No.32196,p.35
1501 Mullins,Di -4a
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1 January 26-27,2017 General Public Meeting,for example,
2 the preferred regional haze portfolio did not include any
3 Energy Gateway additions,and there was no discussion
4 indicating that PacifiCorp was still considering the
5 inclusion of additional Energy Gateways segments in the
6 2017 IRP.
7 It was not until the last General Public
8 Meeting on March 2-3,2017,held approximately one month
9 prior to issuing the 2017 IRP,when PacifiCorp announced
10 its intention to include construction of Energy Gateway
11 sub-segment D2 in the action plan,in conjunction with
12 1,100 MW of new wind resources.9 This timing was
13 surprising to many because much of the financial
14 commitment underlying the newly proposed wind resources
15 was made in December 2016,in order to qualify for the
16 production tax credit.
17 Q.DID PACIFICORP UPDATE ITS ANALYSIS OF ENERGY
18 VISION 2020 AFTER THE IRP?
19 A.Yes.Around July 28,2017,PacifiCorp updated
20 its analysis of Energy Vision 2020.The July update
21 contained supplemental studies that further considered
22 the economic benefits of Energy Vision 2020,using the
23 System Optimizer ("SO")and Planning and-Risk ("PaR")
24 dispatch models.The results were summarized in Table 2
25 of Mr.Link's Direct Testimony.PacifiCorp also noted in
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1 discovery that it performed some supplemental analysis in
2 its Rebuttal Testimony in Utah Public Service Commission
3 Docket No.17-035-23;I have not reviewed the results of
4 that analysis.
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22 9 Note that PacifiCorp's request in this matter is limited to
860 MW,since at least 240 MW of new QF wind resources have
23 already been acquired.The 860 MW included in PacifiCorp's
request in this matter is also different than the total
24 capacity included in its RFP of approximately 1,270 MW.These
varied capacities are a source of uncertainty with respect to
25 Pacificorp's request.
1503 Mullins,Di -5a
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1 Q.WHAT CHANGES DID PACIFICORP MAKE IN ITS UPDATED
2 ANALYSIS
3 A.PacifiCorp filed a summary in Oregon that
4 detailed the specific changes in the July 28,2017
5 analysis,relative to the 2017 IRP.lo These changes
6 included incorporating new modelling adjustments in order
7 to improve the forecast economics of Energy Vision 2020.
8 These outside-the-model adjustments were designed to
9 account for energy imbalance market ("EIM")benefits,
10 line losses benefits,and reliability benefits.
11 PacifiCorp confirmed in discovery that,in the 2017 IRP,
12 it had made these additional outside-the-model
13 adjustments in a way that increased the benefits it
14 estimated for Energy Vision 2020,but has since
15 incorporated those adjustments into the System Optimizer
16 and Planning and Risk models.11
17 Q.WHAT WERE THE RESULTS OF THE SUPPLEMENTAL
18 STUDIES?
19 A.The supplemental studies suggested that the
20 Energy Vision 2020 projects might produce a wide range of
21 economic outcomes,depending on uncertain future market
22 prices and carbon price assumptions.The analysis
23 suggested there was a $530 million range of potential
24 economic outcomes,between (-)$121 million and $409
25 million,depending on the market price and carbon
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1 assumptions used in PacifiCorp's analysis.After
2 considering some of the speculative modeling assumptions
3 that went into developing studies,however,it is clear
4 that the potential for a detrimental outcome is much
5 greater than PacifiCorp represents.
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23 10 See In re PacifiCorp,dba Pacific Power,2017 Integrated
Resource Plan,Or.PUC Docket No.LC 67,PacifiCorp's 2017 IRP
24 Informational Filing (Jul 28,2017).
11 Mullins Exhibit No.302 at 9-10 (PacifiCorp'.s Response to PIIC
25 Data Request ("DR")10).
1505 Mullins,Di -6a
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1 Q.HOW MUCH CAPITAL WOULD PACIFICORP DEPLOY WITH
2 RESPECT TO ENERGY VISION 2020?
3 A.PacifiCorp's proposal would represent a
4 staggering commitment of ratepayers capital of over
5 $(redacted)billion.Confidential Table 1 details the
6 overnight capital cost of the respective aspects of the
7 Energy Vision 2020 project.
8 CONFIDENTIAL TABLE 1
Enerav Vision 2020 Capital Investment Detail ($000)
10 Gateway Subsegment D $g
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Network Upgrades
12 McFadden H
TB Fhts I13TBFhtsH
14 Total Network Upgrades
15 Wind Resources
Ekok Fhts16McFadden H
17 TBFhts
TB Fhts H
18 Total Wind
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21 Q.DOES PACIFICORP HAVE AN INCENTIVE TO DEPLOY
22 THIS CAPITAL?
23 A.Yes.It has been widely documented that
24 utilities subject to rate of return regulation have an
25 incentive to over-invest in capital in order to increase
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1 earnings.12 This phenomenon is often referred to as the
2 Averch-Johnson Effect-based on the economists who first
3 developed the model to describe it back in the 1960s-and
4 has a real and significant
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24 12 See Harvey Averch &Leland L.Johnson,Behavior of the Firm
Under Regulatory Constraint,52 AM.
25 ECON.REV.996,1052 (1962).
1507 Mullins,Di -7a
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1 impact on how utility operations are managed.As the
2 saying goes,the utility earns on what it builds.
3 Accordingly,when considering the capital investments
4 identified in Confidential Table 1,it is important to
5 recognize that shareholders have the potential to benefit
6 hugely if it is deployed.
7 Q.WHY DO RATEPAYERS OPPOSE THE PROJECT?
8 A.The renewable aspects of Energy Vision 2020 are
9 appealing.Notwithstanding,ratepayer advocates
10 throughout the system generally view Energy Vision 2020
11 to be a very risky investment proposal.There might be
12 scenarios where Energy Vision 2020 might produce some
13 economics benefits,but from a ratepayer perspective,it
14 appears more likely that Energy Vision 2020 will result
15 in harm than benefit.If Energy Vision 2020 was based on
16 a demonstrated resource need,it might provide a better
17 justification for taking on the additional risks of the
18 investment.However,the Energy Vision 2020 project is
19 discretionary and not necessary,based largely on
20 speculative assumptions of future prices.In the past,
21 bets like Energy Vision 2020 have worked against
22 ratepayers,and for that reason,most ratepayer
23 advocates,including myself,recommend against proceeding
24 with the proposed investment.
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1
2 III.THE NEW WIND AND TRANSMISSION RESOURCES ARE NOT
NECESSARY
3
4 Q.WHY IS THE ISSUE OF RESOURCE NEED CENTRAL TO
5 DETERMINING WHETHER ENERGY VISION 2020 IS IN THE PUBLIC
6 INTEREST?
7 A.Fundamental to public utility regulation is the
8 concept that ratepayers should be required to pay only
9 for utility plant necessary to provide utility services.
10 The concept was recognized over a decade ago,"that the
11 basis of all calculations as to the reasonableness
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1 of rates to be charged ...must be the fair value of the
2 property being used by it for the convenience of the
3 public."3
4 Q.HOW HAS NOTION OF RESOURCE NECESSITY BEEN
5 EMBODIED IN PUBLIC UTILITY REGULATION IN IDAHO?
6 A.Yes.My understanding is Idaho has a
7 relatively strong used and useful standard.
8 Statutorily,Idaho Code §61-502A prohibits the
9 Commission from setting rates for a utility that grants a
10 return for property that is not used and useful in
11 providing utility service,unless the Commission makes an
12 "explicit finding"to the contrary.In addition,Idaho
13 Code §61-526 requires that the present or future
14 "necessity"be proven by the utility,before it can
15 construct the transmission line and generation
16 facilities.Finally,I would note that PacifiCorp has
17 requested "binding ratemaking treatment"for its
18 investment in these assets,pursuant to Idaho Code
19 Section 61-541.As I understand,this particular code
20 section creates an even higher burden on a utility of
21 having to prove,or "describe,"the need for a project
22 than does section 61-526,as well as requiring the
23 utility to address and mitigate risks associated with a
24 proposed project.The higher standard of "necessity"is
25 warranted under section 61-526,given that ratebasing is
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1 essentially guaranteed.
2 Q.IS ENERGY VISION 2020 PROPERLY CHARACTERIZED AS
3 ADDRESSING A RESOURCE NEED?
4 A.No.Table 5.14 of the 2017 IRP shows available
5 front office transactions of 1,670 MW exceed the system
6 position by a wide margin through the first ten years of
7 the study period.14 In 2026,PacifiCorp expects that
8 currently available resources and front office
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24 13 Smyth v.Ames,169 U.S.547 (1989).
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1511 Mullins,Di -9a
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1 transactions will exceed total requirements,including a
2 13%planning reserve,by approximately 447 MW.This
3 means that,without acquiring any new generating
4 resources or transmission lines,PacifiCorp will continue
5 to be capable of providing adequate services to customers
6 in Idaho.Based on this distinction,the proposal
7 cannot be reasonably characterized as addressing a
8 resource need,and is more reasonably characterized as an
9 economic opportunity,based the current relationship
10 between projected forward prices and the projected costs
11 of the new resources.
12 Q.WHY IS THE ISSUE OF RESOURCE NEED IMPORTANT,
13 WHEN CONSIDERING SUCH SIGNIFICANT UTILITY INVESTMENTS?
14 A.When a legitimate resource need has been
15 established,a resource must be acquired,irrespective of
16 whether the resource produces financial benefits to
17 ratepayers,or increases overall financial risk to
18 ratepayers.Thus,when a resource need has been
19 established,the pertinent inquiry is to determine which
20 type of resource best fulfills the resource need at the
21 least cost,and least risk to ratepayers.In the case
22 of a project justified on the basis of a resource need,
23 ratepayers appropriately take on the risk that the
24 project might be uneconomic,since the project must be
25 completed in order for the utility to continue to provide
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1 adequate utility service.
2 In contrast,in the absence of a resource need,
3 a potential resource acquisition might appropriately be
4 considered a utility investment,but only to the degree
5 that it clearly produces economic rents to ratepayer
6 through reduced rates,commensurate with the risk of the
7 investment.From this perspective,the decision of
8 whether to proceed with a resource acquisition is
9 fundamentally different from a ratepayer perspective,
10 depending on whether a resource need has been
11 established,or not.This means that,in the case of
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1 an economic project,the threshold for proceeding with
2 the investment must be sufficiently high,and should not
3 be speculative,to ensure ratepayers will recognize
4 positive economic rents associated with the project.
5 Q.CAN YOU PROVIDE AN ANALOGY TO ILLUSTRATE YOUR
6 POINT?
7 A.The distinction between a resource constructed
8 to fulfill a resource need,versus an economic project,
9 can be analogized to the considerations one might make
10 when deciding whether to acquire a home as a primary
11 residence,versus acquiring a home as a rental property.
12 When making the decision to acquire a home as a primary
13 residence,there are many risks that are not necessary to
14 consider,simply because one needs a place to live.In
15 contrast,when considering whether to invest in a rental
16 property,one performs a fundamentally different
17 analysis.One must determine,for example,whether the
18 rents forecasted to be received are sufficient to cover
19 the costs and risks,with a reasonable margin to justify
20 the investment.In addition,one only would only proceed
21 with a rental property if it has sufficient capital and
22 the timing is right,etc.
23 Q.DOES DISPLACEMENT OF FRONT OFFICE TRANSACTIONS
24 REPRESENT THE FILLING OF A RESOURCE NEED?
25 A.No.Front office transactions are market
1514 Mullins,Di -11
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1 resources that customers have access to today,and not
2 without cost.Customers have invested significantly in
3 the transmission system in order to have access to
4 bilateral markets.The fact that these markets exist is
5 representative of the fact that there is surplus power in
6 the West.Surplus power exists because there is load
7 diversity between the utilities,allowing the utilities
8 to buy and sell among each other.There is also a large
9 amount of independent power and qualifying facilities
10 contributing to surplus power available in bilateral
11 markets.When accessing
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1515 Mullins,Di -lla
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1 these markets,little to no incremental ratepayer
2 supplied capital is required,and for that reason,it is
3 preferred from a ratepayer perspective that PacifiCorp
4 rely on front office transactions,rather than making
5 significantly more risky capital investments.The risk
6 of deploying the capital is great,particularly when one
7 considers weaknesses in the underlying economics.
8 Finally,to the extent that PacifiCorp does not rely on
9 the supply of energy in bilateral markets,and instead
10 acquires its own resources,that will have the effect of
11 increasing regional supply,reducing market prices,and
12 reducing the economics of its proposed resources.
13 Q.IS THE IRP AN APPROPRIATE FRAMEWORK FOR
14 EVALUATING ECONOMIC RESOURCE ACQUISITIONS?
15 A.No.The IRP analysis may be useful for
16 selecting among available resources when a clear resource
17 need has been established.Since the IRP is designed to
18 determine which resource is best to fill an established
19 resource need,however,it can ignore many of the risks
20 associated with acquiring new resources.If a resource
21 is necessary,many risks must be assumed irrespective of
22 the resource acquired.When dealing with a
23 discretionary,economic investment,however,there are a
24 number of additional risks that must be considered,which
25 PacifiCorp has not adequately addressed in its analysis.
1516 Mullins,Di -12
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1 IV.THERE ARE MANY RISKS PACIFICORP HAS NOT CONSIDERED
2 Q.WHAT ADDITIONAL RISKS ASSOCIATED WITH ENERGY
3 VISION 2020 HAS PACIFICORP NOT CONSIDERED?
4 A.Four specific risks that I have identified with
5 the Energy Vision 2020 investments include:1)the
6 current status of the Multi-State Protocol;2)forecasted
7 oversupply conditions;3)the movements towards
8 regionalized transmission;and,4)pending tax reform.
9 There are many more of these types of risk,which are not
10 normally considered
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1517 Mullins,Di -12a
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1 in the context of an IRP analysis,but are appropriately
2 considered in the context of a discretionary economic
3 investment.
4 Q.WHAT IS THE CURRENT STATUS OF THE MULTI-STATE
5 PROCESS?
6 A.The 2017 Protocol will expire on December 31,
7 2019,and stakeholders are currently in the process of
8 trying to develop a replacement interjurisdictional
9 allocation methodology.In place of the current
10 framework,PacifiCorp has proposed sweeping changes to
11 the way that the cost of generation will be allocated
12 amongst the states.PacifiCorp's current proposal is to
13 split up the system,assign each state a fixed allocation
14 of existing resources,and move to a subscription based
15 method for assigning new resources to each state.
16 Within the context of the Multistate Process,
17 it's not yet clear how the Energy Vision 2020 would fit
18 within a fixed allocation or subscription framework,and
19 this source of uncertainty is a real risk to ratepayers.
20 It can hardly be considered wise,from a ratepayer
21 perspective,to begin making significant,irreversible
22 financial decisions immediately prior to splitting up the
23 system into a subscription model.It is akin to a
24 couple buying an expensive house after they have decided
25 to divorce.It makes the allocation of assets and risks
1518 Mullins,Di -13
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1 much more complicated.
2 Q.WHAT ABOUT OVERSUPPLY CONDITIONS IN THE WEST?
3 A.One of the more pressing issues of the time
4 affecting electric utilities in the West has to do with
5 persistent oversupply conditions.Most are aware of the
6 implications of the "duck curve,"and the impact that
7 surplus renewables are having on supply;e.g.,reducing
8 prices in bilateral markets.It is important to
9 recognize that PacifiCorp is not the only entity in the
10 West aware of the low cost for renewable resources,with
11 the thought of
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1519 Mullins,Di -13a
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1 building them.Given current price trajectories for
2 renewables,it is reasonable to expect that oversupply
3 conditions will get worse,not better.For example,
4 PacifiCorp has indicated in presentations to large
5 customers that it is already experiencing negative EIM
6 prices in Wyoming and there should be an expectation that
7 this negative pricing will persist if PacifiCorp
8 constructs the Wind Projects.PacifiCorp has not
9 considered this risk,and at a minimum,the potential for
10 oversupply is a reason to put greater weight on the low
11 price scenarios in the economic analysis.
12 Q.DO CURRENT QUALIFYING FACILITY DEVELOPMENTS
13 REFLECT THESE OVERSUPPLY CONDITIONS?
14 A.Yes.In its 2017,Q2 avoided cost update filing
15 with the Utah Public Service Commission,PacifiCorp
16 identified that it has potential qualifying facility
17 ("QF")resources amounting to total nameplate capacity of
18 approximately 5,775 MW,with total contribution to
19 capacity of approximately 2,920 MWh.15 When added to the
20 approximate 860 MW of new wind proposed in this case,
21 Idaho ratepayers might be looking at paying for several
22 thousand megawatts of renewable and QF resource
23 additions.It is noteworthy that the influx of QF
24 resources is not being driven by the policies of Idaho,
25 but the policies of surrounding states.This can be
1520 Mullins,Di -14
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1 noted from that fact that only 5.6 MW of these new QF
2 resources are being developed in Idaho.16 In any
3 instance,PacifiCorp's analysis does not consider how the
4 dramatic influx of QF contracts might impact its
5 proposal,another risk which weighs against constructing
6 the Energy Vision 2020 resources at this time.
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17
18
19
20
21
22
23 15 Rocky Mountain Power's 2017 Avoided Cost Input Changes
Quarterly Compliance Filing,Ut.PSC Docket
24 No.17-035-37,Rocky Mountain Power Q2 Compliance Filing at 6.
16 Id.at 4-6 ("BYU-ID QF"is the only QF resource identified in
25 the list of new and potential QF resources located in Idaho).
1521 Mullins,Di -14a
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1 Q.HOW MIGHT FURTHER REGIONALIZATION OF THE
2 TRANSMISSION SYSTEM IMPOSE RISKS WITH RESPECT TO ENERGY
3 VISION 2020?
4 A.The recent regionalization efforts undertaken
5 through the CAISO appear to have ended suddenly,and
6 might be forgotten as quickly as GridWest was.
7 Notwithstanding,it is reasonable to expect continued
8 movement towards regionalization of the transmission
9 system.The Energy Gateway was a controversial aspect of
10 recent regionalization efforts,as PacifiCorp insisted on
11 being able to complete the projects,outside of the
12 CAISO's regional transmission planning process.Many
13 parties were not supportive of PacifiCorp's proposal to
14 build the Energy Gateway outside of regional planning
15 process,which would otherwise require competitive
16 bidding with respect to new transmission investments.
17 In addition,Under Order 1000,FERC has
18 expressed a preference for utilities to perform
19 inter-regional transmission planning.From an
20 inter-regional perspective,segment D2 of the Energy
21 Gateway may not be the best solution for addressing
22 transmission needs in the West.Ratepayer capital
23 would be better deployed for the purpose of improving
24 reliability throughout the West,not for the purpose of
25 pursuing transmission investments driven by economics.
1522 Mullins,Di -15
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1 Q.WHAT RISKS MIGHT TAX REFORM POSE ON THE ENERGY
2 VISION 2020 INVESTMENT?
3 A.Changes to the tax code have the potential to
4 produce dramatic impacts on the economic benefits of the
5 Energy Vision 2020 project.The current House Bill has
6 provisions that would more than eliminate any potential
7 for economic benefits with respect to Energy Vision 2020
8 by reducing corporate tax rates and eliminating
9 inflationary escalators on the
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1523 Mullins,Di -15a
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1 production tax credit.The potential impacts of these
2 potential changes will be discussed further below.
3 Q.AFTER CONSIDERING THESE RISKS,ARE THE ENERGY
4 VISION 2020 PROJECTS IN THE PUBLIC INTEREST?
5 A.No.Since the Energy Vision 2020 project is
6 driven by economic,not reliability concerns,there
7 should be an overwhelming case presented by PacifiCorp
8 for making the investment.PacifiCorp has failed to meet
9 this burden of proof.In fact,after one considers the
10 speculative nature of many of PacifiCorp's assumptions,
11 it is likely that the economics will not be favorable
12 resulting in great harm to ratepayers.
13 V.IMPACT OF FORECAST MARKET PRICES
14 Q.WHAT IMPACT DO MARKET PRICE ASSUMPTIONS HAVE ON
15 PACIFICORP'S ANALYSIS?
16 A.The economic case underlying the proposed
17 Energy Vision 2020 investment is dependent,almost
18 entirely,on PacifiCorp's assumptions related to future
19 natural gas and power prices.Under PacifiCorp's
20 analysis,if prices are high,the Energy Vision 2020
21 project could prove to be beneficial.If prices do not
22 increase in the way PacifiCorp forecasts,however,Energy
23 Vision 2020 will not be beneficial.As a result,the
24 case for Energy Vision 2020 can be viewed largely as
25 speculation in future market prices.Market prices are a
1524 Mullins,Di -16
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1 key assumption in PacifiCorp's proposal,and for that
2 reason,it is important to have a clear understanding of
3 the likely accuracy of PacifiCorp's forecast.
4 Q.HOW ACCURATELY HAS PACIFICORP FORECAST MARKET
5 PRICES IN THE PAST?
6 A.There should be little expectation that anyone
7 might be able to predict future market prices with any
8 degree of accuracy,particularly as far as 20 or 30 years
9 into the future.It
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1525 Mullins,Di -16a
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1 should not be surprising therefore,that PacifiCorp has
2 not done a very good job in the past at predicting future
3 prices.In fact,the analysis I discuss below
4 demonstrates that PacifiCorp has systematically
5 over-forecast market prices in the past.
6 Q.DO THE SAME CONCERNS ABOUT THE FORWARD PRICE
7 CURVE APPLY TO A PROJECT BUILT BASED ON A RELIABILITY
8 NEED?
9 A.No.When a project is constructed for
10 reliability purposes,based upon a defined resource need,
11 the accuracy of the long-term price forecast is less
12 impactful because the price forecast affects which
13 specific type of resource should be build,but not
14 whether a resource is built at all.Thus,the accuracy
15 of the forward price curves are of greater importance in
16 the case of an investment driven by economic factors.
17 Q.WHAT ANALYSES HAVE YOU PERFORMED SURROUNDING
18 PACIFICORP'S PRICE FORECASTING?
19 A.PacifiCorp issues periodic Official Forward
20 Price Curves ("OFPCs").These OFPCs are usually issued
21 on a quarterly basis,although at times they are issued
22 at more frequent intervals.The OFPCs contain a
23 schedule of escalating forecast market prices sometimes
24 more than thirty to forty years in the future.I have
25 performed an analysis to consider the accuracy of
1526 Mullins,Di -17
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1 previously issued OFPCs.My analysis demonstrates that
2 PacifiCorp's forecast has tended to overstate future
3 prices,and by significant margins.In addition,I also
4 discuss PacifiCorp's 2012 long term gas hedge,a contract
5 that was similarly justified based on forecast market
6 prices,but has proved to be detrimental to ratepayers.
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1527 Mullins,Di -17a
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1 a.PacifiCorp's Forward Price Curve Systematically
Overstates Future Market Prices
2
3 Q.PLEASE PROVIDE AN OVERVIEW OF THE ANALYSIS YOU
4 PREPARED WITH RESPECT TO PACIFICORP'S PREVIOUSLY ISSUED
5 OFPCS.
6 A.In Mullins Exhibit No.303 and Mullins Exhibit
7 No.304,I present an analysis exploring the accuracy of
8 PacifiCorp's previously issued OFPCs.Mullins Exhibit
9 No.303 examines the accuracy of OFPCs issued over the
10 period 2007 through 2016.Mullins Exhibit No.304
11 examines the accuracy of OFPCs issued over the period
12 2010 through 2016.Mullins Exhibit No.304 considers a
13 shorter period of 2010 through 2016 in order to determine
14 whether structural changes in natural gas and power
15 markets-which occurred generally in the period 2008
16 through 2010,as a result of fracking and other
17 factors-might have contributed to the over-forecasting
18 observed in the longer-term analysis presented in Mullins
19 Exhibit No.303.
20 Q.WHAT DOES YOUR ANALYSIS SHOW?
21 A.The analysis in Mullins Exhibit No.303 shows
22 that,over the period 2007 to 2016,PacifiCorp has
23 historically overestimated future forward prices,and
24 that the magnitude of the overestimation tended to be
25 greater the further out the forecast was made.In
1528 Mullins,Di -18
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1 addition,the same pattern of overestimation can be
2 observed when considering only the curves issued over the
3 shorter period of 2010 through 2016 in Mullins Exhibit
4 No.304.This indicates that PacifiCorp's
5 over-forecasting cannot be explained by the unexpected,
6 rapid decline in natural gas prices that occurred between
7 2008 and 2010.
8 The analysis for the Henry Hub market has been
9 reproduced in Confidential Figure 1,below,based on
10 OFPCs issued over the period 2007 through 2016.
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1529 Mullins,Di -18a
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e 21
3
4 CONFIDENTIAL FIGURE 1
5 HenryHub Forecast Error HenryHub,
For OFPCs Issued 2007 to 2016
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Similarly looking figures may be found in
22 Mullins Exhibit No.303 for other power and gas markets.
23 In addition,Mullins Exhibit No.304 also contains
24 similarly looking figures over,although the slope of the
O 25 median error line tended to be reduced slightly when the
1530 Mullins,Di -19
PIIC
1 analysis was performed over the shorter period.
2 Q.PLEASE DESCRIBE THE DATA PRESENTED IN
3 CONFIDENTIAL FIGURE 1.
4 A.Confidential Figure 1 is a plot of the
5 percentage forecast error associated with forward prices
6 included in forward price curves issued by PacifiCorp
7 over the period 2017 the end of 2016.Each dot in the
8 figure represents the percentage difference between a
9 price that was forecast in a forward curve and the
10 ultimate spot price for the given prompt month.
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1531 Mullins,Di -19a
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1 To the extent that the error is positive,it means that
2 the price in the forward curve exceeded the ultimate spot
3 price.To the extent that the error is negative,it
4 means that the price in the forward curve was less than
5 the ultimate spot price.Along the x-axis,the set of
6 forecast errors were separated by the number of months
7 before the prompt month for which the forward price was
8 calculated.Thus,a forecast error further to the right
9 indicates the forecast error associated with a price that
10 was forecast further in advance of the prompt month.
11 Similarly,a forecast error on the left side of the
12 x-axis represents a price that was forecast nearer to the
13 prompt month.Overlaid on the figure is the median
14 forecast error based on the number of months in advance
15 of the prompt month that the forward prices were
16 calculated,as well as the interquartile range of the
17 forecast errors.
18 Q.HOW CAN THE DATA PRESENTED IN CONFIDENTIAL
19 FIGURE 1 BE USED TO DETERMINE PACIFICORP'S ABILITY TO
20 PREDICT FORWARD PRICES?
21 A.If the OFPCs are reasonably accurate,one would
22 expect PacifiCorp's price forecast to be an unbiased
23 expectation of future spot prices.That is,forward
24 prices would exceed the ultimate spot price 50%of the
25 time and be less than the spot price 50%of the time.
1532 Mullins,Di -20
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1 That is clearly not the case.
2 Q.COULD THE ABOVE ANALYSIS ALSO BE USED TO
3 DETERMINE IF THERE IS A RISK PREMIUM EMBEDDED IN THE
4 FORWARD PRICE CURVE?
5 A.Another way to look at PacifiCorp's over
6 forecasting is as a risk premium,an additional amount
7 above the spot market price that PacifiCorp is willing to
8 pay in order to lock in a fixed price.If there is no
9 risk premium embedded in the OFPC,the median forward
10 curve forecast error should be zero.If,however,the
11 median forecast error exceeds zero,that is an indication
12 of a risk premium.It makes sense that there might be a
13 risk premium
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1533 Mullins,Di -20a
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1 built into forward prices,based on the fact that the
2 curves are always upsloping,having the attributes of a
3 contango market
4 Q.WHAT DOES THE DATA IN YOUR ANALYSIS CONFIRM
5 ABOUT THE EXISTENCE OF RISK PREMIUMS IN PACIFICORP'S
6 FORECASTS?
7 A.The empirical analysis in Confidential Figure 1
8 indicates that there have been risk premiums embedded in
9 the forward curves and that those risk premiums have been
10 substantial.For a transaction executed more than one
11 year in advance of the prompt month,the expected
12 forecast error for Henry Hub was approximately
13 (redacted)%.This means that each time PacifiCorp
14 purchases a financial gas swap more than one year in
15 advance of the prompt month,ratepayers should
16 statistically expect ultimately to pay an amount that is
17 (redacted)%greater than the actual spot price of natural
18 gas.
19 Similar risk premiums may be observed in power
20 markets.As can be identified in Mullins Exhibit No.
21 303,the risk premium observed in PacifiCorp's Palo Verde
22 market was approximately (redacted)%for transactions
23 executed more than one year in advance.For transactions
24 executed more than 5 years in advance,the observed risk
25 premium rose to approximately (redacted)%,meaning that,
1534 Mullins,Di -21
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1 if a transaction were executed more than five years in
2 advance based on the Palo Verde Market,ratepayers would
3 be required to pay nearly (redacted)the spot rate for
4 power.These are considerable premiums,with many
5 troubling implications extending beyond just the Energy
6 Vision 2020 investment.
7 Q.HOW SHOULD THE ABOVE ANALYSIS BE CONSIDERED
8 WHEN EVALUATING THE ECONOMIC CASE FOR ENERGY VISION 2020?
9 A.In the case of Energy Vision 2020,the
10 economics rely on forward prices extending 40 years into
11 the future in some of its analyses.The analyses in
12 Mullins Exhibit No.303 and Mullins Exhibit No.304 only
13 detail forecast errors for prices forecast five to seven
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1535 Mullins,Di -21a
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1 years in advance of the prompt month,due to the
2 availability of data.Based on the analysis,however,
3 it is reasonable to assume that PacifiCorp will
4 over-estimate forward prices by even greater magnitudes
5 when estimated 20 to 40 years into the future.
6 Ratepayers throughout PacifiCorp's system are not
7 comfortable taking on the risk that PacifiCorp's price
8 forecast might be overstated.Since PacifiCorp has
9 historically overstated market prices,and by significant
10 margins,little weight should be given to the economics
11 in medium and high-priced gas scenarios.In fact,even
12 the prices in the low priced scenario are probably
13 overstated based on the magnitude of risk premium
14 observed in PacifiCorp's historical curves.
15 Q.HAS THE COMMISSION RECOGNIZED THE INHERENT
16 DIFFICULTY ASSOCIATED WITH LONG-TERM PRICE FORECASTING?
17 A.Yes.The Commission has recently expressed
18 similar skepticism regarding long-term price forecasts
19 used to develop for QF avoided costs,in agreeing with
20 PacifiCorp and other investor owned utilities and
21 granting them the right to reduce the length of QF
22 contracts for wind and solar projects from 20 years,down
23 to two years.As experienced in the recent past,
24 previous attempts to execute long term transactions
25 justified based on the prices in PacifiCorp's OFPC have
1536 Mullins,Di -22
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1 not worked in ratepayers favor due to the observed
2 forecast errors,and there should be little expectation
3 that Energy Vision 2020 might produce any different
4 result.
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1537 Mullins,Di -22a
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1 b.Previous Bets on PacifiCorp's Forward Price Curve
Have Been Detrimental to Ratepayers
2
3 Q.HAS PACIFICORP ENTERED INTO AN RECENT LONG-TERM
4 TRANSACTION JUSTIFIED ON THE BASIS OF ITS PRICE FORECAST?
5 A.Yes.In 2012,PacifiCorp entered into a pair
6 of long-term gas hedging contract.The execution of
7 those contract was discussed in Utah Public Service
8 Commission Docket No.12-035-102.Execution of the
9 long-term contracts was subject to a provision that the
10 levelized price of the contract not exceed the forward
11 market prices in PacifiCorp's forecast.The stipulation
12 in that matter required that "refreshed pricing yields a
13 market ratio below 100 percent calculated from
14 PacifiCorp's most current forward price curve at the time
15 bid prices are refreshed"1
16 Q.DID PACIFICORP EXECUTE A CONTRACT PURSUANT TO
17 ITS GAS HEDGING CONTRACTS?
18 A.PacifiCorp entered into two contracts with J
19 Arron,the Commodities trading division of Goldman Sacs.
20 I have reviewed the terms of those contracts,and
21 previously contested them in a Wyoming proceeding on the
22 basis that they constituted affiliate transactions.At
23 the time of the transaction as Berkshire Hathaway
24 possessed warrants on Goldman Sacs equating to beneficial
25 ownership of about 8.4%.I am not contesting the
1538 Mullins,Di -23
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1 transactions in this matter,but merely pointing out how
2 detrimental they have been to ratepayers,having been
3 justified on the basis of PacifiCorp's official forward
4 price curve similar to Energy Vision 2020.
5 /
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18
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21
22
23 17 In the Matter of the Voluntary Request of Rocky Mountain Power
for Approval of Resource Decision to
24 Acquire Natural Gas Resources,Ut.PSC Docket No 12-035-102,
25
Settlement Stipulation,¶5
1539 Mullins,Di -23a
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1 Q.HOW DETRIMENTAL HAVE THE LONG-TERM GAS HEDGINGO2CONTRACTSBEENTORATEPAYERS?
3 A.From a ratepayer perspective,the contracts
4 have not been beneficial and have resulted in significant
5 and unnecessary costs.Confidential Figure 2,below,
6 shows the historical settlements,as well as the future
7 mark-to-market cost,associated with the long term gas
8 hedging contracts.
9
10 CONFIDENTIAL FIGURE 2
MUCost)of J.Arron Long-tennGas Hedging Contracts ($millions)
11
12
13
14
i
15
16
17
18
19
20
21
22 Q.WHAT DOES CONFIDENTIAL FIGURE 2 SHOW?
23 A.Confidential figure 2 shows that PacifiCorp has
24 a record of losing when making bets on PacifiCorp's
''25 official forward price curve.Based on current forwardO
1540 Mullins,Di -24
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1 prices forecasts,which themselves may be overstated,
2 ratepayers are poised to incur approximately $(redacted)
3 million in cost with respect to the above long-term gas
4 hedging contract.
5 /
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1541 Mullins,Di -24a
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1 Q.WHAT IS YOUR CONCLUSION REGARDING FORECASTINGO2RISKSANDTHEPROPOSEDPROJECTS?
3 A.In total,the Energy Vision 2020 proposals will
4 likely cost ratepayers several billion dollars,and
5 similar to the above long-term gas hedging contracts,
6 PacifiCorp purports that the Energy Vision 2020
7 investment would be justified primarily based on its
8 expectation surrounding future market prices.Yet,
9 PacifiCorp's price curves have historically failed to
10 reasonably estimate future prices,and the experience
11 with respect to the long-term gas hedging contracts shows
12 how significant the impact of these inaccurate
13 assumptions can be.Based on the experience with the
14 long-term gas hedge,it is not reasonable for PacifiCorp
15 to make long-term bets on the accuracy of its forward
16 price curve,particularly bets of the magnitude
17 contemplated with Energy Vision 2020.
18 VI.THE ECONOMIC CASE IS NOT COMPELLING
19 Q.WHY DO YOU BELIEVE THAT PACIFICORP HAS
20 OVERSTATED THE POTENTIAL FOR BENEFITS ASSOCIATED WITH
21 ENERGY VISION 2020?
22 A.Even if one were to ignore PacifiCorp's pattern
23 of over-forecasting future prices,the economic case for
24 Energy Vision 2020 is not compelling.Upon examination of
25 the assumptions PacifiCorp used to inform its analysis,
1542 Mullins,Di -25
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1 it is apparent that there is not an overwhelming economic
2 case for deploying the significant amount of capital
3 underlying Energy Vision 2020.In fact,the data
4 suggests that it is more likely that these projects will
5 end up costing ratepayer greatly in the long run.In
6 Confidential Table 2,below,I detail the impact of
7 peeling away some of the speculative assumptions in
8 PacifiCorp's analysis.
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1543 Mullins,Di -25a
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1
CONFIDENTIAL TABLE 22NetPresentValueRevenueRequirement("NPVRR")
3 bpact of SpeculativeAssumptions ($million)
4 Company Identified Benefit /(Cost)(Low Gas Med CO2)$(32)-$(73)
5
Impact of SpeculativeAssumptions:
6 SupplementalGRID Study Adjustments (65)
WholesaleTransmissionRevenues
TransmissionCosts
8 Wind Integration Costs (105)
Tax Reform (211)
9 Toml (544)
10 Potential Harm to Ratepayers $(576)-$(617)
11 -
12 With forecast ratepayer NPVRR cost of $32
13 million to $73 million under the low gas price scenario,
14 the potential for Energy Vision 2020 to result in harm to
15 ratepayers is great.After considering these speculative
16 assumptions,Energy Vision 2020 could end up costing
17 ratepayers approximately $576 million to $617 million on
18 an NPVRR basis.These are not the characteristics of a
19 project that PacifiCorp should be pursuing as a utility
20 investment.
21 a.Supplemental GRID Stuclies
22 Q.WHAT SUPPLEMENTAL GRID STUDIES DID PACIFICORP
23 PERFORM WHEN DEVELOPING THE ECONOMIC CASE FOR ENERGY
24 VISION 2020?
25 A.As a part of the initial economic analyses
1544 Mullins,Di -26
PIIC
1 surrounding Energy Vision 2020,PacifiCorp performed
2 supplemental GRID studies where it quantified additional
3 projected benefits of approximately $64.5 million,on a
4 NPVRR basis,over a 20-year period.The studies were
5 used to quantify the certain aspects of PacifiCorp's
6 proposal related to reduced line
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1545 Mullins,Di -26a
PIIC
1 losses,reliability benefits,and EIM benefits,which
2 PacifiCorp believed would be additive to the economics
3 calculated using the IRP models.
4 Q.HAVE THESE MODELING ADJUSTMENTS BEEN
5 INCORPORATED INTO THE IRP MODELS?
6 A.Yes.PacifiCorp confirmed that it has
7 subsequently incorporated the adjustments underlying the
8 supplemental GRID studies into the System Optimizer and
9 Planning and Risk models.Those adjustments,however,
10 have little basis in reality,yet are a key driver in the
11 economic benefits that PacifiCorp purports with respect
12 to Energy Vision 2020.
13 Q.WHAT ADDITIONAL CLAIMED BENEFITS DID PACIFICORP
14 INCLUDE WITH RESPECT TO LINE LOSSES?
15 A.PacifiCorp believes that the new
16 transmission line will have a positive impact on line
17 losses,and modeled the line losses by quantifying the
18 power cost impacts of reducing loads in Wyoming.
19 Notwithstanding,I expects that the addition of new
20 resources in remote areas of Wyoming would actually
21 increase line losses,in contrast to resources at
22 locations nearer to loads.While the lines themselves
23 may have improved loss ratings,adding more resources to
24 remote locations on PacifiCorp's system causes more power
25 to flow over long distances,subjecting more power to
1546 Mullins,Di -27
PIIC
1 transmission level losses.For example,a study
2 performed by Steve Knudson in the Utah proceeding on the
3 ongoing RFP showed that locating new resources in Wyoming
4 far from load would result in materially higher real
5 system power losses in critical winter and summer peak
6 conditions.18 In addition,ratepayers have no way to
7 ensure that the line loss reductions are actually
8 achieved.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24 18 In re the Application of Rocky Mountain Power for Approval
of Solicitation Process of Wind Resources,Ut.PSC Docket
O 25 No 17-035-23,Prefiled Testimony of F.Steven Knudsen
at 12:245-247.
1547 Mullins,Di -27a
PIIC
1 Q.WHAT ADDITIONAL CLAIMED BENEFITS DID PACIFICORP
2 INCLUDE WITH RESPECT TO THE EIM?
3 A.With respect to the additional claimed EIM
4 benefits,I am concerned with this aspect of PacifiCorp's
5 analysis because the benefits associated with the EIM are
6 being modeled in a way that is completely different than
7 the way that EIM benefits are established when setting
8 power costs in general rate cases,and other similar
9 dockets.In its economic analysis of Energy Vision 2020,
10 PacifiCorp modeled the entrance of Idaho Power into the
11 EIM by increasing the transfer capability between Jim
12 Bridger and Walla Walla by 300 MW,even though no actual
13 increase to transfer capability will occur as a result of
14 the EIM.Thus,PacifiCorp's models were configured to
15 allow additional phantom transfers of power from Jim
16 Bridger into the Northwest,even though PacifiCorp does
17 not have transmission rights to accommodate those
18 transfers.Such an assumption has no basis in the way
19 that the EIM actually operates,as the EIM does not allow
20 a utility to rely on the system of another utility in
21 order to effectuate firm transfers of power in excess of
22 firm rights.Attempting to use the EIM to effectuate
23 firm transfers in the manner contemplated by PacifiCorp
24 is a prohibited practice and would violate many
25 provisions of the EIM.To accomplish the additional firm
1548 Mullins,Di -28
PIIC
1 transfers,PacifiCorp would basically have to manipulate
2 its hour-ahead schedules,with the expectation that EIM
3 would redispatch its resources in order to serve loads in
4 the Northwest.
5 In contrast,the EIM will likely represent an
6 additional cost associated with the Wind Projects,which
7 PacifiCorp has not considered in its economic analysis.
8 The Wind Projects will be subject to uninstructed
9 imbalance charges,and the cost of those charges
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
1549 Mullins,Di -28a
PIIC
1 are not reflected in PacifiCorp's analysis.Due to
2 transmission constraints in eastern Wyoming,I expect the
3 uninstructed imbalance charges to be material.
4 Q.ARE THESE MODELING ADJUSTMENTS APPROPRIATELY
5 USED TO JUSTIFY SUCH MAJOR RESOURCE ADDITIONS?
6 A.No.These supplemental analyses are hardly a
7 sound basis to justify such significant resource
8 additions and ratepayer risks.Notwithstanding,these
9 modeling adjustments would comprise nearly the entirety
10 of the benefits forecast in the medium gas and CO2
11 scenario in PacifiCorp's analysis.Effectively,
12 ratepayers are dealing with a risky marginal project that
13 would clearly not be forecast to be economic in the
14 absence of these modeling adjustments.Ratepayers and
15 regulators should not be comfortable making significant
16 resource additions based on these types of aggressive
17 modeling assumptions.
18 b.Wholesale Transmission Revenues
19 Q.WHAT HAVE YOU IDENTIFIED WITH RESPECT TO
20 PACIFICORP'S ASSUMPTIONS SURROUNDING WHOLESALE
21 TRANSMISSION REVENUES?
22 A.PacifiCorp assumes that,in connection with the
23 Aeolus to Bridger segment,it will receive about
24 $(redacted)million,on a NPVRR basis,of associated
25 incremental transmission revenues over the 20-year
1550 Mullins,Di -29
PIIC
1 period.19 PIIC performed discovery with respect to these
2 claimed incremental benefits in Data Request 11.In
3 response to that data request,PacifiCorp describes these
4 additional claimed benefits as the amount by which
5 projected incremental revenue received from other
6 transmission customers will offset the revenue
7 requirement for these transmission investments.20
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22 19 Calculated from PacifiCorp's confidential workpaper
"Energy Gateway GM 2017 03 13 w Bonus",Tab
23 "Gateway",Column "G."
20 Mullins Exhibit No.302 at 11:12 (PacifiCorp's Response
24 to PIIC DR 11).
25
1551 Mullins,Di -29a
PIIC
1 Q.DO YOU AGREE WITH PACIFICORP'S ASSUMPTION?O 2 A.No.PacifiCorp's analysis was highly
3 simplified,and does not represent the way that the
4 formula rates will actually work.PacifiCorp simply
5 assumed that 12%of the new investment would be funded by
6 Open Access Transmission Tariff ("OATT")customers,based
7 upon the historical percentages of transmission revenue
8 requirement that was funded by OATT customers.But,
9 PacifiCorp did not perform a rigorous analysis of how the
10 amount of costs allocated to OATT customers will change
11 as a result of the project.
12 Q.DOES PACIFICORP PROPERLY ACCOUNT FOR THE WAY
13 THAT THE PROJECT MIGHT FLOW THROUGH FORMULA RATES?
14 A.No.PacifiCorp's analysis fails to account for
15 the fact that when the Energy Vision 2020 project is
16 constructed,it will require PacifiCorp's merchant
17 operations to maintain additional transmission capacity
18 in order to utilize the wind facilities.When this
19 additional capacity is acquired,it will dilute the
20 percentage of costs allocated to OATT customers,
21 resulting in additional cost being allocated to retail
22 customers.The amount of this benefit is comparable to
23 the overall amount of benefits expected under the base
24 case scenario.
25 Notwithstanding,this 12%assumption was made
1552 Mullins,Di -30
PIIC
1 with little rigor and is fundamentally inconsistent with
2 how the new project will impact the costs borne by retail
3 customers.Once again,this assumption is hardly a basis
4 to justify the significant investment that PacifiCorp
5 proposes,yet the preponderance of alleged benefits could
6 be attributed solely to this assumption.
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1553 Mullins,Di -30a
PIIC
1 c.Cost Assumptions
2 Q.HOW MUCH CERTAINTY DO RATEPAYERS HAVE WITH
3 RESPECT TO PACIFICORP'S COST ASSUMPTIONS?
4 A.The total capital required for the Aeolus to
5 Bridger/Anticline transmission project is forecast to be
6 about $(redacted)million.21 Given this large magnitude,
7 even small changes to this cost assumption can have the
8 effect of eliminating the claimed positive economics of
9 the project.
10 Q.DOES PACIFICORP RECOGNIZE THAT THERE IS A GREAT
11 DEAL OF UNCERTAINTY SURROUNDING ITS COST ASSUMPTIONS?
12 A.Yes.In response to PIIC Data Request 15,
13 PacifiCorp estimated the accuracy of its transmission
14 cost assumption to be within plus,or minus,15%of
15 actual spending.22 That is a range of approximately $97
16 million above and below PacifiCorp's estimate.That
17 magnitude of error would eliminate any claimed favorable
18 economics associated with the project,under the medium
19 price scenarios.
20 Q.HAS PACIFICORP MADE OTHER QUESTIONABLE COST
21 ASSUMPTIONS?
22 A.PacifiCorp also makes some assumptions
23 regarding operating expenses.In response to PIIC Data
24 Request 14 for example,PacifiCorp identifies an
25 assumption in its model to include $1 million of
1554 Mullins,Di -31
PIIC
1 incremental operations and maintenance expenses
2 associated with the new transmission project.23 When
3 requested to substantiate this estimate,PacifiCorp noted
4 that it had no supporting workpapers for the estimate,
5 and therefore,no basis to refute that incremental
6 operating expenses might be substantially higher than its
7 estimate.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21 21 See PacifiCorp's confidential workpaper "Energy Gateway GM
22 2017 03 13 w Bonus",Tab "Summary",Cell "G26"
23 22 Mullins Exhibit No.302 at 18:19 (PacifiCorp's Response to
PIIC DR 15).
24 23 Mullins Exhibit No.302 at 17 (PacifiCorp's Response to PIIC
DR 14).
25
1555 Mullins,Di -31a
PIIC
1 d.Wind Integration CostO2Q.WHAT LEVEL OF WIND INTEGRATION COSTS DID
3 PACIFICORP INCLUDE IN ITS ANALYSIS?
4 A.PacifiCorp includes integration costs of
5 approximately $0.63/MWh in this case.However,
6 PacifiCorp's currently approved wind integration charge
7 in Idaho is $3.06/MWh.PacifiCorp also has an
8 application pending before the Commission in Case No.
9 PAC-E-17-11 to reduce its wind integration charge from
10 $3.06 to $0.57/MWh.It seems that the higher wind
11 integration charge was just fine for PacifiCorp in the
12 context of its reducing avoided cost payments to
13 independent QF projecth,but now seems too high with
14 respect to the new Wyoming wind projects.PacifiCorp's
15 manipulation of wind integration charges is obviously and
16 patently self-serving.Of great concern in this case is
17 PacifiCorp's blatant manipulation of the wind integration
18 charge to justify the economics of the new Wyoming wind.
19 I would also note that this Commission has yet to approve
20 PacifiCorp's new proposed wind integration charge,and
21 until changed,PacifiCorp is obligated to evaluate the
22 new wind resources with the wind integration charge on
23 file and approved by this Commission.
24 Q.WHAT WIND INTEGRATION VALUES HAS PACIFICORP
25 USED PREVIOUSLY?
1556 Mullins,Di -32
PIIC
1 A.Based on the 2014 Wind Integration Study,
2 PacifiCorp estimated intra-hour wind integration costs of
3 approximately $2.35/MWh-almost four times as much as is
4 assumed for the new wind in this docket.24 In addition,
5 PacifiCorp has previously
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23 24 See e.g.,In The Matter of the Application of Rocky Mountain
Power for Authority of a General Rate Increase in Its Retail
24 Electric Utility Service Rates in Wyoming of $32.4 Million Per
25
arector reent,,
G i
a200600-4-ER-151
.
1557 Mullins,Di -32a
PIIC
1 identified inter-hour wind integration costs of
2 approximately 0.75/MWh,25 yet the economic analysis for
3 Energy Vision 2020 includes no inter-hour wind
4 integration costs.
5 Q.WHAT IS THE IMPACT OF USING THIS WIND
6 INTEGRATION ASSUMPTION?
7 A.I estimate that if the 2014 Wind Integration
8 Study results were used,including inter-hour wind
9 integration,it would reduce PacifiCorp's claimed
10 economics of the Energy Vision 2020 project by
11 approximately $104.9 million.
12 Q.IS IT POSSIBLE TO VERIFY THAT THIS SAVINGS IN
13 WIND INTEGRATION COSTS WILL BE ACHIEVED?
14 A.No.Generally,it is not possible in actual
15 operations to determine the amount of actual wind
16 integration costs that PacifiCorp might incur with
17 respect to the Wind Projects.If the actual wind
18 integration costs are higher than PacifiCorp expects it
19 will reduce the economics of the project,yet it is not
20 possible to verify whether wind integration costs will
21 ultimately be in line with PacifiCorp's assumptions in
22 this matter.
23 e.Potential Impacts of Tax Reform
24 Q.WHAT IMPACT MIGHT TAX REFORM HAVE ON THE
25 PROJECT ECONOMICS?
1558 Mullins,Di -33
PIIC
1 A.Much of the projected benefits of PacifiCorp's
2 proposed strategy come in the form of expected tax
3 benefits.Notwithstanding,if reduced corporate tax
4 rates are approved,the benefits of favorable tax
5 provisions will be diminished.This is a significant
6 risk associated with the project and,in response to PIIC
7 Data Request 13,PacifiCorp estimated that,if tax reform
8 is approved,it will reduce the project economics by
9 approximate $93 million.Thus,any projected benefits in
10 the medium gas and CO2 case
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24 25 Mullins Exhibit No.302 at 15:16 (PacifiCorp's Response to
25
PIIC DR 13).
1559 Mullins,Di -33a
PIIC
1 could be entirely eliminated if Congressional efforts
2 associated with tax reform are advanced.
3 Q.ARE THERE OTHER POTENTIAL TAX REFORM PROVISION
4 THAT MIGHT IMPACT THE ECONOMICS?
5 A.Yes.The proposed House Bill would eliminate
6 the inflationary escalator applied to production tax
7 credits,which would similarly reduce the project
8 economics.PacifiCorp's analysis,however,assumes 2%
9 per year inflationary escalation for production tax
10 credits.I estimate that removing the escalation
11 assumption on production tax credits reduces the NPVRR
12 economics of Energy Vision 2020 by approximately $116.4
13 million.Thus in total,tax reform has the potential to
14 reduce the already questionable economics of the Energy
15 Vision 2020 project by $209.4 million on a NPVRR basis.
16 f.Summary of Economic Case
17 Q.PLEASE SUMMARIZE WHY YOU BELIEVE THE ECONOMIC
18 CASE FOR ENERGY VISION 2020 IS NOT COMPELLING.
19 A.Taking all of the speculative assumptions into
20 consideration,it is clear that the Energy Vision 2020
21 project is hardly a slam-dunk,as PacifiCorp would imply.
22 If these speculative assumptions are stripped away,the
23 project cannot be viewed as being economic for
24 ratepayers.Based on these assumptions,it is clear that
25 there are a great number of risks associated with the
1560 Mullins,Di -34
PIIC
1 project that cannot be reasonably captured in the
2 probabilistic analysis that PacifiCorp performed.Risk
3 such as the possibility of changing tax provisions,make
4 economic projects inherently more risky to ratepayers,
5 than a project justified based on a demonstrated resource
6 need.For that reason,there needs to be an overwhelming
7 case presented in order to pursue an economic project.
8 Yet,in this
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
1561 Mullins,Di -34a
PIIC
1 case,there is not an overwhelming economic case,and in
2 fact,it appears more likely that the project will cost
3 ratepayers significantly.
4 VII.SINGLE ISSUE RATE MAKING SHOULD BE AVOIDED
5 Q.HOW HAS PACIFICORP PROPOSED TO RECOVER THE
6 COSTS OF ENERGY VISION 2020?
7 A.The ratemaking proposal of PacifiCorp in this
8 matter was described in the Direct Testimony of Mr.
9 Larsen.Prior to PacifiCorp's next general rate case,
10 PacifiCorp proposes to use a Resource Tracking Mechanism
11 ("RTM"),as a component of Energy Cost Adjustment
12 Mechanism,to recover costs associated with the New Wind
13 and New Transmission investments.26
14 Q.IS PACIFICORP'S RATEMAKING PROPOSAL
15 APPROPRIATE?
16 A.No.PacifiCorp's proposal would constitute
17 single issue ratemaking,which is inherently unfair to
18 ratepayers and should generally be avoided.
19 Q,WHY IS SINGLE ISSUE RATEMAKING UNFAIR TO
20 RATEPAYERS?
21 A.When utility regulatory commissions determine
22 the appropriateness of a cost that a utility seeks to
23 recover from its customers,the standard practice is to
24 review and consider all relevant factors as part of a
25 general rate case,rather than just certain factors in
1562 Mullins,Di -35
PIIC
1 isolation.Isolation of a single issue,as PacifiCorpO2requestswithrespecttotheRTM,is disfavored as a
3 matter of policy because it distorts the fundamental
4 "matching principle"of traditional ratemaking.While
5 under traditional ratemaking,revenues and costs are
6 balanced at a common point in time,single issue
7 ratemaking often isolates only those costs expected to
8 increase,without recognizing counterbalancing savings in
9 another area.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24 26 Larsen,Direct at 2:5-22.
25
1563 Mullins,Di -35a
PIIC
1 As a result,single issue ratemaking often results in
2 over-earning by the utility and over-paying by the
3 customer.Accordingly,the Commission should view the
4 ratemaking proposal surrounding the RTM with great
5 caution.
6 Q.HOW SHOULD AN INVESTMENTS SUCH AS ENERGY VISION
7 2020 BE INCORPORATED INTO RATES?
8 A.From a ratepayer perspective,it is more
9 appropriate to consider investments of the scope
10 contemplated with Energy Vision 2020 in a general rate
11 case.This will allow all aspects of utility's costs to
12 be considered.In a general rate case,ratepayers can be
13 assured to receive credit from other aspects of
14 PacifiCorp's results,which might have trended favorably.
15 Q.DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
16 A.Yes.
17
18
19
20
21
22
23
24
25
1564 Mullins,Di -36
PIIC
1 I .INTRODUCTION AND SUMMARY
2 Q.ARE YOU THE SAME BRADLEY G.MULLINS THAT FILED
3 DIRECT TESTIMONY IN THIS MATTER?
4 A.Yes.I previously filed testimony on behalf of
5 the PacifiCorp Idaho Industrial Customers ("PIIC").My
6 address has changed to 1750 SW Harbor Way,Suite 450,
7 Portland,Oregon 97062.
8 Q.WHAT IS THE PURPOSE OF YOUR SUPPLEMENTAL
9 TESTIMONY?
10 A.I respond to the Supplemental Direct Testimony
11 of Rocky Mountain Power ("PacifiCorp")witnesses Rick
12 Link,Rick Vail and Chad Teply concerning PacifiCorp's
13 proposal to construct 1,311 MW of new wind resources in
14 eastern Wyoming ("Wind Projects")and its proposal to
15 construct a 140 mile high voltage 500 kV transmission
16 line between Aeolis and Jim Bridger,including associated
17 network upgrades,("Transmission Projects").
18 Collectively,I refer to the Wind Projects and
19 Transmission Projects as the "Combined Projects."
20 Q.WHAT WAS THE SCOPE OF YOUR REVIEW?
21 A.In addition to reviewing PacifiCorp's testimony
22 and workpapers,I conducted discovery and reviewed
23 PacifiCorp's response to data requests.Relevant
24 responses to data requests can be found in Mullins
25 Exhibit No.305.I also review highly confidential
1565 Mullins,Supp-Di -1
PIIC
1 documents relating to the bids received in both the
2 Renewable Request for Proposal ("Wind RFP")issued on
3 September 27,2018 and the Request for Proposal Solar
4 Resources ("Solar RFP")issued on November 15,2017.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1566 Mullins,Supp-Di -la
PIIC
1 Q.PLEASE PROVIDE AN OVERVIEW OF YOUR TESTIMONY?
2 A.The Wind RFP and Solar RFP demonstrate that the
3 cost of energy and capacity from renewable resources has
4 been declining rapidly.Notwithstanding,as discussed in
5 my Direct Testimony,there is no immanent need for new
6 resources.In discovery,PacifiCorp indicated in its
7 most recent load forecast that loads are forecast to
8 decline between 2017 and 2036 on both a peak-and
9 energy-basis.1 As a result,PacifiCorp is still in a
10 surplus capacity position through 2026,irrespective of
11 how front office transactions are considered in the load
12 and resource balance.
13 And even if one were to conclude that a
14 resource need existed,PacifiCorp's final resource
15 procurement proposal is not the least-cost,nor
16 least-risk,alternative for taking advantage of
17 increasingly low-priced wind and solar resources.Both
18 independent evaluators acknowledged that there were low
19 cost,lower risk power purchase agreements ("PPAs")
20 available through the Wind RFP,which were disqualified
21 solely based on the generator interconnection queue
22 position of the respective wind sites.Further,
23 PacifiCorp's solar sensitivity studies also demonstrated
24 that the final and best pricing in the ongoing Solar RFP
25 produced greater ratepayer savings than the Combined
1567 Mullins,Supp-Di -2
PIIC
1 Projects.
2 Finally,I also continue to disagree with many
3 of the assumptions in PacifiCorp's benefits study.I
4 have also identified a number of new issues surrounding
5 market prices,transmission revenues,transmission
6 capital assumptions,and energy imbalance market
7 benefits.After adjusting for these factors,my analysis
8 suggest the Combined Projects will not produce a net
9 present value ratepayer benefit,and in fact,will result
10 in a net cost
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24 1 See Mullins Exhibit 306 (Conf.).The most recent load forecast
25
was provided in response to PIIC Data Request 26.
1568 Mullins,Supp-Di -2a
PIIC
1 of $103,956,638 under the medium gas,medium CO2 Scenario
2 on a Net Present Value Revenue Requirement ("NPVRR")
3 basis.
4 Q.WHAT IS YOUR RECOMMENDATION?
5 A.As a result of a variety of issues that have
6 been identified with PacifiCorp's final short list,and
7 the process leading up to the selection of those
8 resources,I recommend that the Commission decline to
9 approve PacifiCorp's request for a Certificate of Public
10 Convenience and Necessity ("CPCN").The RFP that
11 ultimately took place was not the competitive RFP process
12 that was described when PacifiCorp first filed this case.
13 My perspective is that,where a range of
14 potentially beneficial alternatives exist,the utility
15 should select the resource option that results in the
16 greatest public good.Choosing a generating resource
17 that is second best,or in this case,not even close to
18 the next best alternative,is not,in my view,an
19 appropriate resources to be granted a CPCN.
20 Further,I continue to recommend that the
21 Commission reject PacifiCorp's proposal for single issue
22 ratemaking through the proposed renewable resource
23 tracking mechanism,as well as its request for
24 preapproval.The conditions surrounding Langley Gulch's
25 ratemaking preapproval were unique,and not appropriately
1569 Mullins,Supp-Di -3
PIIC
1 applied in this case.
2 Q.IF THE CPCN IS TO BE GRANTED,ARE THERE
3 CONDITIONS THAT COULD BE IMPOSED TO PROTECT RATEPAYERS?
4 A.Since there are better resource alternatives
5 available at this time,there are no conditions that will
6 ultimately hold ratepayers harmless.Ratepayers will be
7 harmed if PacifiCorp constructs the Combined Projects,
8 and will incur greater harm if PacifiCorp's assumptions
9 prove to be false.Plus,the margins for achieving
10 ratepayer benefits are very thin,even in PacifiCorp's
11 benefits study.Accordingly,if PacifiCorp constructs
12 the
13 /
14
15 /
16
17 /
18
19
20
21
22
23
24
25
1570 Mullins,Supp-Di -3a
PIIC
1 Combined Projects,PacifiCorp should,at a bare minimum,
2 bear the risk of the underlying economic benefits failing
3 to materialize due to faulty assumptions and forecasts in
4 its benefits study.The following conditions address some
5 of those risks:
6 1.The collective rate base for of the WindProjects,inclusive of any allowance for funds
7 used during construction,construction overhead
and other expenditures transferred to plant
8 with respect to the Wind Projects,shall becappedforratemakingpurposeat
9 $1,370,237,000,the amount included inPacifiCorp's benefit study presented in
10 PacifiCorp's Supplemental Direct Testimony.
11 2.The collective rate base for the network
upgrades associated with the constructing the
12 Wind Projects,inclusive of any allowance for
funds used during construction,construction
O 13 overhead and other expenditures transferred toplantwithrespecttosuchnetworkupgrades,
14 shall be capped for ratemaking purposes at
$110,700,000,the capital assumed in the
15 benefits study presented in PacifiCorp's
Supplemental Direct Testimony.
16
3.The rate base for the Transmission Projects,
17 inclusive of any allowance for funds usedduringconstruction,construction overhead and
18 other expenditures transferred to plant with
respect to the Transmission Projects,shall be
19 capped for ratemaking purposes at $679,168,000,
the capital assumed the benefits study
20 presented in PacifiCorp's Supplemental Direct
Testimony.
21
4.In future ratemaking proceedings,PacifiCorp
22 shall be required to impute an amount ofproductiontaxcreditsreflectedinrevenue
23 requirement if-as a result of a negative IRSruling,change in tax law,or other
24 factor-PacifiCorp is ultimately foundineligibletoclaiminflationadjusted
25 production tax credits,at the full $/MWh rate
1571 Mullins,Supp-Di -4
PIIC
1 assumed in PacifiCorp's Supplemental DirectTestimony.
2
5.In all future ratemaking proceedings where a
3 dispatch model is used to forecast power costs,PacifiCorp shall include a 300 MW transmission
4 link between Jim Bridger and Walla Walla,
consistent with the EIM benefits assumption
5 made in the benefits study presented inPacifiCorp's Supplemental Direct Testimony.
6
6.In future ratemaking proceedings,PacifiCorp
7 shall be required to impute an additional
amount of transmission revenues,if the
8 proportion of transmission revenue requirement
allocated to PacifiCorp's merchant function
9 increases as a direct result of the
construction of the Combined Projects.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
1572 Mullins,Supp-Di -4a
PIIC
1 7.In future ratemaking proceedings,PacifiCorp
shall be prohibited from recovering any costs
2 associated with ongoing capital maintenance andcapitalreplacementsfortheTransmission
3 Projects,since those costs were not considered
in the benefits study presented in PacifiCorp's
4 Supplemental Direct Testimony.
5 8.In future ratemaking proceedings,PacifiCorp
shall not be allowed to recover any positive
6 net uninstructed imbalance charges incurredthroughtheEnergyImbalanceMarket("EIM")
7 associated with the Wind Projects,since those
costs were not considered in the benefits study
8 presented in PacifiCorp's Supplemental DirectTestimony.
9
10 II.BACKGROUND
11 Q.WHAT IS PACIFICORP'S FINAL RESOURCE PROPOSAL?
12 A.PacifiCorp has concluded its evaluation of the
13 bids received in the Wind RFP in February 2018,and
14 identified four wind resources,including construction of
15 Gateway sub-segment D2,as its final resource proposal in
16 this case.PacifiCorp received bids from approximately
17 18 different wind sites.2 Of the 18 sites,14 were
18 located in Wyoming and only four sites were located
19 outside of Wyoming.Most of these sites,however,were
20 disqualified by the Company due to transmission queue
21 position issues,which will be discussed below.
22 Accordingly,other than the Company's benchmark
23 resources,only one independent Wyoming wind project had
24 a low enough queue position to be considered by the
25 Company as having a viable bid.3
1573 Mullins,Supp-Di -5
PIIC
1 Q.DID PACIFICORP PERFORM AN UPDATED BENEFITS
2 STUDY BASED UPON ITS FINAL RESOURCE SELECTION?
3 A.Mr.Link performed an updated benefits study
4 which contains numerous adjustments relative to the
5 analysis presented previously in this proceeding,most of
6 which were
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24 2 Utah IE Report,Page 49,Table 10.
25
3 Oregon IE Report,Page 34.
1574 Mullins,Supp-Di -5a
PIIC
1 designed to make the benefits of the Combined Projects
2 appear more attractive.The latest benefits analysis
3 presented in this case was in Mr.Link's Corrected Second
4 Rebuttal and Supplemental Direct testimony.
5 Q.WHAT LEVEL OF BENEFITS DID PACIFICORP PROJECT
6 WITH RESPECT TO THE COMBINED PROJECTS?
7 A.Based upon its nominal revenue requirement
8 studies,PacifiCorp alleges the Combined Projects will
9 result in net present value ratepayers benefit/(cost)of
10 (-)$127,416,419,$166,548,586,and $499,249,164,in low,
11 medium and high gas price scenarios,respectively.4
12 I disagree with these numbers,and expect the
13 projects to be detrimental to customers.
14 Notwithstanding,even if one were to agree with
15 PacifiCorp's modeling assumptions,the wide range of
16 outcomes shows that the Combined Projects are
17 extraordinarily risky to ratepayers.
18 Q.DOES THE TEMPORAL PROFILE OF THE ALLEGED
19 BENEFITS CONTRIBUTE TO THE OVERALL RISKINESS OF THE
20 PROJECTS?
21 A.Yes.It's not just the variability of the
22 alleged benefits that make PacifiCorp's proposal a risky
23 project to ratepayers,but also the distant timing of
24 when those alleged benefits might materialize.The
25 benefits profile alleged by PacifiCorp is very much
1575 Mullins,Supp-Di -6
PIIC
1 concentrated toward the end of the study period,as can
2 be noted in Figure 1,below.
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24 4 CORRECTED Link,Di-Second Supp,page 17,line 1 (CORRECTED
25
Table 3-SS,assuming medium CO2).
1576 Mullins,Supp-Di -6a
PIIC
1
2 FIGURE 1
3 Nominal,Total-Company Benefits Profile of Wind Projects
by PacifiCorp Gas Price Scenario,Medium CO2 ($000)
4
600,000
5 ---1.ow
500.000 ---Medium
400.000 ----I ligh
10 2(18 2028 -3 -038 2043 2048
(100,000)
11 (200,000)
12 NPVRR Low Gas Medium Gas High Gas
O 2018 -2027 (-)$l17,222 (-)$77,960 $65,665132018-2037 (-)$134,580 $55,567 $311,190
14 2018 -2049 (-)$175,689 $112,586 $441,062
2018 -2050 (-)$127,416 $166,549 $499,249
15
16 Q.WHY IS THERE A LARGE INCREASE IN BENEFITS IN
17 THE FINAL YEAR OF THE STUDY PERIOD?
18 A.The increase at the end of the study period
19 represents a new terminal value assumption that
20 PacifiCorp incorporated into its modeling since filing
21 its Direct Testimony.I discuss that issue further
22 below.However,it is important to point out,with
23 respect to Figure 1,that expanding the y-axis makes it
24 more difficult to see the year-to-year savings profile.
25 Q.WHAT DOES FIGURE 1 SHOW?
1577 Mullins,Supp-Di -7
PIIC
1 A.In addition to reviewing the timing of the
2 benefits,Figure 1 also details the net present value of
3 the Combined Projects,measured over various timeframes,
4 based on the Company's modeling.As can be seen,even
5 in PacifiCorp 's model,the Combined
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1578 Mullins,Supp-Di -7a
PIIC
1 Projects are expected to increase rates over the first
2 ten years of the study period under a medium gas
3 scenario.Thus,a key question with respect to
4 PacifiCorp's benefits study is,if the Combined Projects
5 are to cause rates to increase over the next ten years,
6 how reliable are the benefits estimates distant time
7 periods of the study period.Quite simply,I do not
8 believe that PacifiCorp should be gambling with such
9 significant sums of ratepayer money on the prospect that
10 those out year benefits might materialize.
11 III.ISSUES IDENTIFIED IN THE RFP PROCESS
12 Q.DID YOU REVIEW THE INDEPENDENT EVALUATOR
13 REPORTS ASSOCIATED WITH THE PROPOSED RESOURCE
14 PROCUREMENT?
15 A.Yes.Two independent evaluators oversaw the
16 Wind RFP process-Merrimack Energy Group,Inc.on behalf
17 of the Utah Public Service Commission and Bates White on
18 behalf of the Oregon Public Utility Commission.Both
19 identified issues that call into question the
20 reasonableness of PacifiCorp's resource selection in the
21 Wind RFP,as well as issues surrounding the fairness and
22 competitiveness of the Wind RFP.With respect to the
23 Solar RFP process,the independent evaluator was London
24 Economics,who has yet to issue a report with respect to
25 the Solar RFP.London Economics was scheduled to issue
1579 Mullins,Supp-Di -8
PIIC
1 that report on March 30,2018,although that report has
2 not been filed with the Utah Public Service Commission as
3 of the time of writing this testimony.
4 Q.DO YOU AGREE WITH THE CONCLUSIONS OF THESE
5 REPORTS?
6 A.I do not.Particularly,I disagree with
7 conclusory statements such as "[t]he [independent
8 evaluator]is of the opinion that PacifiCorp's selection
9 of the final shortlist of projects totaling 1,311 MW was
10 a reasonable selection based on the constraints
11 identified."5
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18
19
20
21
22
23
24
25 5 Utah IE Report,Page 81.
1580 Mullins,Supp-Di -8a
PIIC
1 From a ratepayer perspective,the constraints identifiedO2aretoosignificanttobeignored.I do,however,agree
3 with many of the issues and some of conclusions
4 identified in the respective reports.
5 Q.WHAT ISSUES DID THE INDEPENDENT EVALUATORS
6 IDENTIFY WITH RESPECT TO THE WIND RFP?
7 A.The independent evaluators have documented at
8 least three problems associated with the RFP process.
9 I'll discuss each of these in the sub-sections that
10 follow.First,both independent evaluators expressed
11 concerns,and surprise,with the way PacifiCorp applied
12 the transmission interconnection queue in making its
13 final resource selections.Second,both independent
14 evaluates noted that the bids received in the solar RFP
15 had the potential to be more cost competitive than the
16 Combined Projects.Third,both independent evaluators
17 noted that PacifiCorp adopted last minute modeling
18 changes that had the effect of favoring utility ownership
19 bids.As a result of these problems,I do not agree that
20 the Wind RFP has resulted in the best resource selection
21 for ratepayers.
22 a.__The Generation Interconnection Queue Influenced the
Wind RFP Selection
23
24 Q.HOW DID THE GENERATION INTERCONNECTION QUEUE
25 INFLUENCE THE WIND RFP SELECTION?
1581 Mullins,Supp-Di -9
PIIC
1 A.PacifiCorp's generation interconnection queueO2includesover5,000 MW of generators seeking
3 interconnection behind the TOT 4A cut-plane,in the
4 transmission constrained area where PacifiCorp proposes
5 to build the new Gateway Segment D2.PacifiCorp's
6 transmission business is required to grant generator
7 interconnection request in serial queue order.Late in
8 the process of making the resource selection in the Wind
9 RFP,PacifiCorp took a position that,as a result of the
10 requirement to grant interconnection request in serial
11 queue order,only those wind resources with a
12 sufficiently low
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1582 Mullins,Supp-Di -9a
PIIC
1 interconnection queue position could be selected in theO2RFPprocess.This meant that bids with queue positions
3 exceeding the incremental capacity provided through
4 Gateway sub-segment D2 were disqualified,irrespective of
5 whether those resource were lower cost or risk relative
6 to the Combined Projects.
7 Q.WHEN DID PACIFICORP INFORM THE INDEPENDENT
8 EVALUATORS OF ITS POSITION WITH RESPECT TO THE
9 INTERCONNECTION QUEUE?
10 A.It appears that PacifiCorp's position with
11 respect to the interconnection queue was not communicated
12 to the independent evaluators until January 31,2018,
13 after best and final pricing had been received.6 Both
14 independent evaluators had no previous knowledge of
15 PacifiCorp's position,and were surprised when PacifiCorp
16 announced it.
17 Q.WERE THE INDEPENDENT EVALUATORS CONCERNED WITH
18 PACIFICORP'S NEW POSITION ON THE INTERCONNECTION QUEUE?
19 A.Yes.In a phone conference two days later,the
20 independent evaluators "expressed some frustration that
21 the bid selection process ended up being limited to
22 selection of only those projects with favorable queue
23 positions,"and that "[a]ll other proposals submitted
24 were behind the interconnection queue constraint and
25 would have no chance of being selected."7
1583 Mullins,Supp-Di -10
PIIC
1 Q.HOW WERE THE HIGHER QUEUE RESOURCES
2 DISQUALIFIED?
3 A.The mechanics of this were described in the
4 Oregon IE Report as follows:
5 The net result of these adjustments calls for
consideration of the overall context of the
6 RFP.Recall that in its RFP as originally
drafted,PacifiCorp proposed to select only
7 projects from the constrained area and offered
three benchmark projects.Based on the final
8 [transmission]analysis...only one other third
party bid on the shortlist (the [CONF]project)
9 could even compete with these offers.In fact,only one other Wyoming wind offer -
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18
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20
21
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24 6 Utah IE Report,Page 63-64.
25
7 Utah IE Report,Page 67.
1584 Mullins,Supp-Di -10a
PIIC
1 the [CONF]wind proposal -had a high enough
queue position to be viable.So this entire RFP
2 really boiled down to two viable benchmarks and
two third-party offers,meaning a lot of the
3 analysis presented here was of questionable
value.
4
To be clear,the remaining viable offers were
5 competitive offers,but were not the best the
market could provide based on cost or risk,but
6 [the best]for the [new]transmission
constraint issue."a majority of offers are no
7 longer viable without transmission
investment...(three redacted)projects are only
8 viable because they are outside the constrained
area in Wyoming.Inside the constraint only
9 three projects -(names redacted)-are
viable."8
10
11 Q.IS PACIFICORP'S APPLICATION OF THE
12 INTERCONNECTION QUEUE CONSISTENT WITH ITS OPENING
13 TESTIMONY?
14 A.No.PacifiCorp did not disclose its position
15 with respect to the application of the interconnection
16 queue when it initially proposed the Wind RFP a year or
17 so ago.
18 In my opinion,it was not appropriate for
19 PacifiCorp to omit this critical component from all
20 discussion in the period leading up to the issuance of
21 the RFP and only to inform parties of its intentions with
22 respect to the interconnection queue after the bidding
23 had been completed.In fact PacifiCorp implied just the
24 opposite when it made statements regarding its
25 expectation for a robust RFP process,such as the
1585 Mullins,Supp-Di -11
PIIC
1 following:"[t]housands of megawatts of Wyoming windO2resourcecapacityarecurrentlyseekinginterconnection
3 service from PacifiCorp's transmission function,
4 suggesting adequate and increasing wind development
5 activity in Wyoming to support a robust response to the
6 2017R RFP."9 If it was PacifiCorp's original intention
7 to prosecute the interconnection queue through the Wind
8 RFP process,then it had an obligation to indicate so
9 when it filed its opening testimony and when it issued
10 the Wind RFP.
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23
24 6 Oregon IE Report at 34-35.
9 Ut.PSC Docket No.17-035-23,Supplemental Testimony of Rick T.
25 Link lines 296-299.
1586 Mullins,Supp-Di -lla
PIIC
1 Q.IS PACIFICORP'S FINAL TREATMENT OF TRANSMISSIONO2COSTSCONSISTENTWITHITSCOMMUNICATIONSTOBIDDERSIN
3 THE PERIOD LEADING UP TO THE ISSUANCE OF THE RFP?
4 A.No.In Q&A's from the May 31,2017
5 pre-issuance bidders conference,PacifiCorp affirmatively
6 stated that "[c]osts associated with providing the
7 transmission capacity in order to relieve existing
8 congestion and facilitate the interconnection and
9 integration of new wind projects will not be assigned to
10 an individual project as part of the RFP evaluation."10
11 Yet,that is not how PacifiCorp ultimately undertook the
12 RFP.The cost associated with providing transmission
13 capacity for those resource with a high queue position
14 was directly assigned to those resources.As the Utah IE
15 noted "the studies found that bids with a queue position
16 of Q0713 or greater triggered the requirements for Energy
17 Gateway South.As a result,the SO model could
18 essentially only select the projects that were actually
19 selected based on their position in the queue."11
20 Q.WHY DID PACIFICORP NOT DISCLOSE ITS POSITION ON
21 THE INTERCONNECTION QUEUE WHEN IT FILED THE WIND RFP?
22 A.It certainly is possible that PacifiCorp did
23 not realize the queue position would be the deciding
24 factor when it initially conceived the Wind RFP.If
25 true,however,that is simply an indication that
1587 Mullins,Supp-Di -12
PIIC
1 PacifiCorp unintentionally designed an uncompetitive RFP.
2 Whatever the case may be,representations of a robust RFP
3 process have proved to be false.The fact that,in the
4 period leading up to the Wind RFP,PacifiCorp undertook
5 efforts to secure development rights for those
6 resource-which were among the only resources with a low
7 enough queue position to be selected-suggests that
8 PacifiCorp
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24 10 Mullins Exhibit 307.
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11 Utah IE Report at 82.
1588 Mullins,Supp-Di -12a
PIIC
1 probably had formed its position on the interconnection
2 queue well before it filed the RFP.
3 Q.DO YOU AGREE WITH PACIFICORP'S POSITION?
4 A.I believe that is fundamentally a legal
5 question and I am not an attorney.However,my
6 understanding of the RFP as represented by PacifiCorp and
7 as I described above,was that all viable Wyoming wind
8 resources would be considered,that the Company's goal
9 was to acquire the lowest cost resources available to
10 serve load,and that therefore the Company's
11 interconnection queue would not bias the decision making
12 one way or another.Thus,I was under the impression that
13 all Wind RFP bids would be scored or evaluated on the
14 same basis,with the Company being able to then either
15 equalize or mitigate the bidding advantage otherwise
16 available to a bidder with a higher queue position.Such
17 a pro-active step by the Company seems all the more
18 important,where otherwise it seems to have advantaged
19 itself with better queue positions for its own wind
20 resources than for some of the lower cost competitors.
21 Q.WERE THERE MORE COST EFFECTIVE ALTERNATIVES
22 AVAILABLE?
23 A.Since PacifiCorp applied incremental
24 transmission costs to the bids whose queue position
25 exceeded the incremental transmission capacity,the
1589 Mullins,Supp-Di -13
PIIC
1 higher queue position resources had no way of being
2 selected by the model.As a result,the degree to which
3 one of these higher queue resource might be more cost
4 effective than the Combined Projects is not known,
5 assuming the queue were not the limiting factor.
6 Notwithstanding,Table 13 in the Utah independent
7 evaluator's report shows that there were clearly better
8 alternatives.The utility owned Wind Projects had
9 levelized delivered costs ranging from [Highly
10 Confidential](redacted)[End Highly Confidential],
11 including the
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1590 Mullins,Supp-Di -13a
PIIC
1 production tax credit benefits.In contrast,there were
2 thousands of megawatts of wind available through PPA
3 agreements with a comparable cost.For example,the
4 [Highly Confidential](redacted)[End Highly
5 Confidential].That wind project,and many others were
6 better alternatives than the benchmark resources,
7 assuming the interconnection queue was not determinative
8 in the selection process.
9 Q.IN WHAT CIRCUMSTANCES DO RATEPAYERS PREFER PPA
10 OPTIONS?
11 A.Build to transfer agreements carry ongoing
12 development risks that are picked up by ratepayers that
13 are not present with a PPA.If PacifiCorp fails to
14 construct the Combined Projects within the proposed
15 budgets,then those projects might not be economical for
16 ratepayers.The same risk is not present with PPA
17 options,however,where another party has guaranteed the
18 costs through a fixed $/MWh payment.Similarly,with PPA
19 options ratepayers do not bear the risk that production
20 tax credits might be unavailable,due to changes in tax
21 laws or failure to meet the IRS safe harbor requirements.
22 The capacity factor risk of PPAs is also lower because if
23 the wind does not materialize at the level forecast,the
24 ultimate payments to the counterparty will decline.
25 At a minimum,due to the existence of these low
1591 Mullins,Supp-Di -14
PIIC
1 cost PPA options,it is critical for ratepayers to be
2 insulated from all further development risk associated
3 with the Combined Projects,through the imposition of
4 project-by-project hard cap on all construction cost at
5 the level assumed in PacifiCorp's benefits study.
6 Ensuring the production tax credit benefits materialize
7 is also critical to insulating ratepayers from this
8 development risk.
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1592 Mullins,Supp-Di -14a
PIIC
1 Q.IS THE RESULT OF THE WIND RFP GROUNDS TO DENY
2 PACIFICORP'S CPCN PROPOSAL?
3 A.Assuming that the standard requires the public
4 utility to construct plant that achieves the greatest
5 good,yes.In this case,there were potentially better
6 alternatives available,which were summarily disqualified
7 based on their interconnection queue position.As a
8 result,I believe the RFP was deeply flawed,and it is
9 not appropriate to grant a CPCN for a sub-optimal utility
10 plant selected through such a process.
11 b.More Cost-Effective Solar Resources Were AvailableThroughtheSolarRFP
12
13 Q.PLEASE PROVIDE SOME BACKGROUND ON THE SOLAR
14 RFP.
15 A.The requirement to conduct a Solar RFP was a
16 condition imposed by the Utah Public Service Commission
17 when approving the Wind RFP.Because issuing the Wind
18 RFP was imminent,the Solar RFP is on a slightly delayed
19 schedule in relation to the Wind RFP.The Company
20 received best and final pricing from solar bidders in
21 mid-February,and finalized the shortlist selection
22 process mid-March.Based upon the concerns of the
23 independent evaluators,PacifiCorp prepared solar
24 sensitivity studies to compare the economics of the Solar
25 RFP short list with the Combined Projects,as discussed
1593 Mullins,Supp-Di -15
PIIC
1 in Mr.Link's supplemental.
2 Q.WHAT DID THE INDEPENDENT EVALUATORS SAY WITH
3 RESPECT TO THE SOLAR RFP?
4 A.The Utah independent evaluator concluded that
5 "Since PacifiCorp's solicitation is based solely on the
6 solicitation for system wind resources,it is not
7 possible to determine if other resources would have been
8 included in a final least cost,least risk system
9 portfolio,
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1594 Mullins,Supp-Di -15a
PIIC
1 potentially displacing one or more wind resources."12
2 The Oregon independent evaluator stated that "[iln all
3 cases the combination of solar and shortlisted resources
4 provided more net benefits."13
5 Q.HOW MUCH SOLAR WAS INCLUDED IN THE FINAL SHORT
6 LIST FOR THE SOLAR RFP?
7 A.Approximately 1,419 MW,a significant amount of
8 resources,particularly given the lack of demonstrated
9 resource need.
10 Q.WHAT DID THE SOLAR SENSITIVITY STUDIES SHOW?
11 A.When viewed in PacifiCorp's nominal study,the
12 solar bids are overwhelmingly more cost effective than
13 the new wind.The PVRR(d)of the Combined Projects was
14 just (-)$166,548,587 in the nominal revenue requirement
15 studies presented in Mr.Link's Supplemental Direct
16 Testimony,under the medium gas,medium CO2 CaSe.In
17 the medium gas,medium CO2 case,however,the solar
18 project,however,produced a PVRR(d)of (-)$424,128,293.
19 Thus,the solar projects produced benefits that were
20 approximately 2.5 times greater than the Combined
21 Projects,when viewed in the medium gas scenario.
22 Q.WERE THE SOLAR SENSITIVITIES BENEFICIAL UNDER
23 THE LOW GAS PRICE SCENARIO?
24 A.Yes.Not only was the solar short list more
25 beneficial,it was also more durable across price policy
1595 Mullins,Supp-Di -16
PIIC
1 scenarios.PacifiCorp forecast that ratepayers will
2 recognized benefits even in the low gas,zero carbon
3 price policy scenario.In contrast to the economic loss
4 of $183,651,193 for the Combined Projects in the low gas,
5 zero carbon price policy
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24 12 Utah IE Report,Page 68
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E Oregon IE Report,Page 36.
1596 Mullins,Supp-Di -16a
PIIC
1 scenario,the Final Solar short list produced a benefitO2of$216,524,070.The solar bids were also PPA,and thus,
3 less risky from that perspective as well.
4 Q.DID PACIFICORP'S STUDY IDENTIFY MATERIAL
5 BENEFIT OF ACQUIRING BOTH THE WIND AND SOLAR PROJECTS?
6 A.No.If both the solar and the new wind is
7 constructed,the PVRR(d)increased to only
8 (-)$435,346,313 in the medium gas price scenario.This
9 means that the incremental benefit of investing $2.2
10 billion in the Combined Projects was only (-)$11,218,020
11 in the nominal studies.
12 Q.WHAT DO YOU RECOMMEND WITH RESPECT TO THE SOLAR
13 RFP?
14 A.Given the results the Solar RFP resources,it
15 is appropriate for the Commission not to grant the CPCN
16 request because other renewable resources are available
17 that produce higher benefits,even in PacifiCorp's
18 studies.Existence of these cost competitive bids is
19 also reason for PacifiCorp to be held accountable for the
20 modeling assumptions that it has made when developing its
21 resource selection.
22 c.__Pacificorp Made Last Minute Modeling Changes that Had the
Effect of Favoring Utility Ownership
23
24 Q.PLEASE DESCRIBE THE MODELING CHANGES THAT
25 PACIFICORP MADE WHEN MAKING THE FINAL SHORTLIST.
1597 Mullins,Supp-Di -17
PIIC
1 A.PacifiCorp made at least two fundamental
2 modeling changes late in the RFP process,which had the
3 impact of making the utility ownership bids appear more
4 attractive.First,PacifiCorp changed the way that it
5 considered production tax credits in its "levelized"
6 revenue requirement study by considering those benefits
7 on a nominal,rather than a levelized basis,over a 20
8 year study period.The change to the treatment of
9 production tax credits did not impact the "nominal"
10 revenue requirement studies.Second,
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1598 Mullins,Supp-Di -17a
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1 PacifiCorp included a new terminal value calculation that
2 increased the relative benefit of the Combined Projects.
3 Q.WHY DO THE NOMINAL AND LEVELIZED STUDIES
4 PRODUCE SUCH DIFFERENT RESULTS?
5 A.Understanding the difference between the
6 "levelized"studies identified in CORRECTED Table 2-SS
7 and the "nominal"studies identified in CORRECTED Table
8 3-SS is important when considering PacifiCorp's benefits.
9 In my view,the "levelized"studies are not properly
10 considered levelized study at all,since they includes a
11 mismatch of both levelized and nominal costs.In
12 contrast,the nominal study simply considers all costs on
13 a nominal basis,and is a more straight-forward approach.
14 Q.WHICH STUDY IS MORE APPROPRIATE?
15 A.While I do not agree with many of the
16 assumptions that went into the nominal studies,the
17 nominal studies are a more appropriate way to consider
18 the alleged benefits of the Combined Projects.Use of
19 levelized costs might be appropriate when considering the
20 cost of multiple different resources in a capital
21 expansion model and where the study period does not align
22 with the useful life of a resource.In this case,
23 however,PacifiCorp has made a very specific resource
24 proposal,so there is no reason to levelize the costs of
25 the Combined Projects in order to consider the potential
1599 Mullins,Supp-Di -18
PIIC
1 for benefits,other than frontloading nominal benefits
2 that may not be received until the end of the Wind
3 Project's useful life.
4 Q.DO YOU AGREE WITH PACIFICORP'S PROPOSAL TO
5 CONSIDER THE PRODUCTION TAX CREDITS ON A NOMINAL BASIS?
6 A.Conceptually,I don't necessarily disagree that
7 it is appropriate to consider production tax credits on a
8 nominal basis.Notwithstanding,if those benefits are
9 considered on a
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1600 Mullins,Supp-Di -18a
PIIC
1 nominal basis,then then all costs other than production
2 costs,including the cost of the transmission should be
3 considered on a nominal basis.In performing its
4 levelization analysis,the Company performs a bizarre
5 methodology for its transmission investment,which has
6 the effect simply ignoring a great deal of the costs that
7 ratepayers will be responsible for with respect to the
8 transmission investment.If production tax credits are
9 to be considered on a nominal basis,its is more
10 appropriate to consider all costs and benefits not
11 associated with production plant on a nominal basis,
12 rather than mismatching incongruous levelized and
13 nominalization assumptions in the same study.
14 Q.DO YOU AGREE WITH PACIFICORP'S TERMINAL VALUE
15 ASSUMPTION?
16 A.I do not necessarily disagree that there might
17 be some longer term value with respect to a utility owned
18 wind site,in contrast to a power purchase agreement.
19 Notwithstanding,if a longer-term terminal value is to be
20 considered included,the Company needs to consider all of
21 the ongoing capital maintenance and investment that is
22 required with respect to the Combined Projects in order
23 to achieve that terminal value.
24 Q.DOES PACIFICORP'S ANALYSIS INCLUDE ALL ONGOING
25 CAPITAL MAINTENANCE?
1601 Mullins,Supp-Di -19
PIIC
1 A.No.While there was some consideration of
2 capital maintenance with respect to the Wind Projects,in
3 response to PIIC Data Request 24,PacifiCorp stated that
4 its analyses did not consider the ongoing capital
5 maintenance and replacements of the Transmission
6 Projects.Since the ongoing capital was not considered,
7 I do not believe it is appropriate to include a terminal
8 value component in the benefits study PacifiCorp
9 presented.Or in the alternative,the ongoing capital
10 investment in the Transmission Projects needs to be
11 included.The terminal value calculations also do not
12 consider the cost of the
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1602 Mullins,Supp-Di -19a
PIIC
1 Transmission Projects after the 30 year study period,
2 which also need to be considered in the economic
3 analysis.
4 Q.WHAT WAS THE IMPACT OF THE TERMINAL VALUE
5 ASSUMPTION?
6 A.As can be seen in Figure 1,above,the impact
7 of the terminal year revenue requirement ranges from
8 $48.3 million to $58.2 million.
9 Q.HOW DOES THAT COMPARE TO THE COST OF CONGOING
10 CAPITAL MAINTENANCE FOR THE TRANSMISSION PROJECTS?
11 A.The ongoing capital cost of the transmission
12 investment is significant in the study period.
13 PacifiCorp is correct that the rate of replacements
14 associated with the Transmission Projects will be low in
15 the early years of the study period.To address this
16 concern,I estimated replacement costs in the study
17 period assuming a rate of retirement corresponding to a
18 60-R3 survivor curve,which is the current curve used for
19 Account 356,conductors and devices.I also assumed a
20 cost of replacement equal to 100 percent of the original
21 cost of the investment with no adjustment for inflation.
22 I input the resultant capital schedule into PacifiCorp's
23 model and the result was a reduction to the PVRR benefits
24 of approximately $91,951,462 in the 30 year study period.
25 In the terminal period,the increasing level of
1603 Mullins,Supp-Di -20
PIIC
1 capital investment will eventually overtake depreciation
2 expense with respect to the Transmission Projects.Based
3 upon the capital schedule described above,including
4 those terminal costs,further reduces the PVRR in the
5 medium gas case by $18,296,839.
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1604 Mullins,Supp-Di -20a
PIIC
1 IV.OTHER MODELING FLAWS
2 Q.IN YOUR DIRECT TESTIMONY,YOU IDENTIFIED A
3 NUMBER OF PROBLEMATIC ASSUMPTIONS IN PACIFICORP'S
4 ANALYSIS.DO THOSE PROBLEMS PERSIST IN THE MODELING USED
5 TO JUSTIFY THE RFP SHORT-LIST RESOURCES?
6 A.Yes.The RFP selection process continues to be
7 based on a number of unreasonable assumptions,which were
8 identified in my direct testimony.In its Rebuttal
9 Testimony,filed on December 12,2017,PacifiCorp
10 discussed many of these assumptions,but its testimony on
11 the matter not persuasive.In fact,economic benefits
12 studies presented in PacifiCorp's final economic screens
13 in the latest PacifiCorp update contained even more
14 problematic assumptions.
15 Q.WHAT IS THE IMPACT OF THESE PROBLEMATIC
16 MODELING ASSUMPTIONS?
17 A.Table 1 below details the impact of the
18 problematic modeling adjustments that I have identified,
19 including the issue related to ongoing transmission
20 capital investment costs,discussed above.
21
22
23
24
25
1605 Mullins,Supp-Di -21
PIIC
1
2 TABLE 1
3
Impact of Contested Modeling Adjustments
4 NormudPEmg4$
5 Company Purported Net Benefits I (Cost)166,548,587
Modeling Adjustments:
6 Ongoing Transmission Capital (90,175,4%)OATTTransmission Revenues (25,674,149)
7 EIM Unistructed Imbalance (22,925,985)
E[M 300 MW IJnk (43,416,002)
8 Total Modeling Adjustments (182,191,632)
Combined Project Net Benefits /(Cost)(Befom Market Change)(15,643,045}
Approx.Impactof Declining Market Prices (88,313,593)10
CombinedProject Net Benefits /(Cost)After MarketAdjustment (103,956,638)
11
12
O 13 a.PacifiCorg Has Not Considered that Forward Market Prices
Have Declined
14
15 Q.HAS PACIFICORP ADEQUATELY RESPONDED TO CHANGING
16 MARKET CONDITIONS?
17 A.No.While PacifiCorp has made a number of
18 modeling changes to improve the overall economics of its
19 project,it has ignored changing circumstances
20 surrounding market prices,a key driver of the economic
21 case for its proposal.Forward market price projections
22 have declined dramatically relative to the forward prices
23 included in PacifiCorp's economic analysis.
24 Q.HOW DOES PACIFICORP DEVELOP ITS LONG-TERM OFPC?
25 A.The forecasting methodology PacifiCorp uses was
1606 Mullins,Supp-Di -22
PIIC
1 described in detail in PacifiCorp's response to UAE Data
2 Request 3.2.14 Effectively,there are three parts to
3 PacifiCorp's forecast methodology.The first 72 months
4 of the forecast use market forwards based on
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25 14 Mullins Exhibit 306
1607 Mullins,Supp-Di -22a
PIIC
1 quotes from brokers.This initial 72 months is often
2 referred to as the short-term portion of the OFPC.The
3 subsequent 12 months (months 73 through 84)are a
4 transition period that interpolate between market
5 forwards and a third-party fundamentals based forecast.
6 Beginning in month 85,the OFPC relies on a third-party
7 forecast that PacifiCorp receives in one of its ongoing
8 subscription services for multi-client,off-the-shelf,
9 fundamentals-based forecasts.The part of the curve that
10 relies on a third-party forecast is often referred to as
11 the long-term portion of the OFPC.
12 Q.WHAT IS THE TENOR OF THE FORWARD PRICE CURVE
13 PACIFICORP USED IN ITS ECONOMIC ANALYSIS?
14 A.In response to PIIC Data Request 37,PacifiCorp
15 noted that the economic analyses presented in the
16 Corrected Second Supplemental Direct Testimony of Mr.
17 Link used PacifiCorp's December 2017 Official Forward
18 Price Curve ("OFPC").15 That OFPC was issued on January
19 2,2018.Notwithstanding,the long-term portion of the
20 December 2017 OFPC was based on a long-term natural gas
21 forecast dated of November 21,2017 as noted in
22 PacifiCorp's response to UAE Data Request 3.2 in Docket
23 No.17-035-40.16 Thus,the long-term market price
24 projections did not consider the effects of tax reform or
25 the reduction in forward market prices that occurred in
1608 Mullins,Supp-Di -23
PIIC
1 late 2017.
2 Q.HOW HAVE MARKET PRICES CHANGED RELATIVE TO
3 DECEMBER 2017 OFPC?
4 A.While spot prices remained relatively flat,
5 large price reductions were observed in the forward
6 periods in December 2017.In PacifiCorp's December 2017
7 OFPC,these reductions were noted in the short-term
8 portion of the OFPC which were based on broker
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24 15 Id.
16 Id.
25
1609 Mullins,Supp-Di -23a
PIIC
1 quotes as of January 2,2018.For example,the forward
2 market prices for calendar year 2022 declined by
3 approximately 35%in PacifiCorp's December 2017 OFPC,
4 relative to the June 2017 curve used in PacifiCorp's
5 prior economic benefits analysis.
6 Notwithstanding,similar reductions were not
7 observed in the long-term portion of the OFPC.The
8 third party forecast was from November 2017,prior to the
9 passage of the Tax Cuts and Jobs Act,and can be observed
10 in Figure 2,below.
11 FIIGURE2
Rolling 12 Mo Average Henry Hub Forward Price $/MMBtu
12 Source:PacifiCorp Non-Confidential Official Forward Price Curve
O 7.00136.75 --Jtme 2017 OFPC
6.50 ---December 2017 OFPC146.25
6.00
15 s.ys
5.50
16 5.25
5.00
17 4.75 Bemed
4.50
18 4.25 Forward Subscription
4.co Market Forecast
19 3.75 Prices
3.50
20 3.25
3.00
21 2-75
2.50
22 225
23
24 As can be seen in Figure 2,forward prices are
25 basically flat for the first six years of the price
1610 Mullins,Supp-Di -24
PIIC
1 curve,but then rapidly increase by around 50%in the
2 transition period.The reason for the rapid increase is
3 possibly due to the fact that the long-term portion of
4 the curve was based on a stale forecast.
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1611 Mullins,Supp-Di -24a
PIIC
1 Q.RAS PACIFICORP RECEIVED MORE RECENT THIRD-PARTY
2 FORECASTS?
3 A.Yes.In PIIC Data Request 38,PIIC requested
4 that PacifiCorp provided the long-term natural gas price
5 forecasts that PacifiCorp has received through at
6 third-party subscription service over the period January
7 1,2018 through the present.The most recent price
8 forecast of S&P Global Platts,Scenario Planning Service,
9 as well as the prices from PacifiCorp's December 2017
10 OFPC can be seen in Figure 3,below.
11 CONFIDENTIAI.FIGURE 3
12 Henry Hub Forward Price $/NMBtuPacifiCorpDecember2018OFPCversusmostrecent third-party
13 forecast.
14
15
16
17
18
19
20
21
22
23
24
25
1612 Mullins,Supp-Di -25
PIIC
1 As can be seen from the figure,the more recent
2 projections,are more in line with current market forward
3 prices,and conforms better with actual market prices.
4 Q.WHAT IS THE IMPACT OF DECLINING MARKET PRICES
5 ON PACIFICORP'S PROPOSAL?
6 A.I took the $/MWh difference between the
7 long-term prices included in the December 2017 OFPC and
8 the February 2018 prices detailed in Confidential Figure
9 3.To estimate the expected change in power prices as a
10 result of declining gas prices,I then multiplied
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
1613 Mullins,Supp-Di -25a
PIIC
1 that difference by the ratio of Palo Verde electric
2 prices to Henry Hub gas prices in the December 2017 OFPC.
3 Finally,I multiplied the Palo Verde power price delta by
4 the amount of generation from the Wind Projects to
5 estimate the economic impact of the lower curve.The
6 result was a present value revenue requirement reduction
7 to the net benefits calculation of $358,817,934.
8 Such an adjustment would imply a net cost
9 associated with the Wind Projects that is lower than the
10 low market,zero CO2 scenario.Accordingly,I also
11 performed an analysis that interpolated between the low
12 and medium gas price scenario based upon the degree to
13 which the February prices tended towards the low gas,
14 zero CO2 scenario.Based on that analysis,I determined
15 that prices were approximately 25%closer to the low gas,
16 zero CO2 scenario,implying an impact of $88,313,593
17 associated with the lower curve.Since the system will
18 redispatch around the lower market prices,I view this
19 value to be a more reasonable estimate of the lower
20 expected forward prices.
21 These market adjustments are appropriately
22 applied even before considering the largely academic
23 issue of whether a risk premium is embedded in forward
24 prices.Mr.Link is entitled to his opinion,but based
25 on my experience,market prices have consistently been
1614 Mullins,Supp-Di -26
PIIC
1 lower than the utilities'long term forecasts.And,the
2 data presented in my Direct Testimony is evidence of that
3 fact.Whether it's a risk premium,or just bad
4 forecasting,the historical data is a reason to place
5 greater weight on the low gas price scenarios.Since
6 consideration of a risk premium would render the projects
7 more uneconomical to ratepayers,I did not consider that
8 adjustment in Table 1,above.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
1615 Mullins,Supp-Di -26a
PIIC
1 b _PacifiCorg Incorrectly Attributes Wholesale
2
Transmission Revenues to the combined Projects
3 Q.DOES PACIFICORP'S FINAL BENEFITS STUDY CONTINUE
4 TO INCLUDE FAULTY ASSUMPTIONS WITH RESPECT TO WHOLESALE
5 TRANSMISSION REVENUES?
6 A.Yes.As noted in my Direct Testimony,
7 PacifiCorp continues to assume that 12%of the
8 Transmission Projects,and 12%of the associated network
9 upgrades will be funded by PacifiCorp's Open Access
10 Transmission Tariff ("OATT")customers.The 12%amount
11 is based on the portion of transmission revenue
12 requirement that has historically been funded by OATT
13 customers.PacifiCorp has assumed that the portion of
14 transmission revenue requirement allocated to retail
15 customers will not increase as a result of constructing
16 the Combined Projects.
17 Q.WHAT DID PACIFICORP SAY IN REBUTTAL TESTIMONY
18 ON THIS ISSUE?
19 A.Very little.Mr.Vail provided a high-level
20 description of PacifiCorp Transmission's transmission
21 revenue requirement ("ATRR"),and then goes on to state
22 that "[t]he 12 percent figure represents the current
23 level of ATRR funded by OATT customers."O
24 Q.DO YOU AGREE?
25 A.I do not dispute that the 12%figure represents
1616 Mullins,Supp-Di -27
PIIC
1 the current level of ATRR funded by OATT customers.IO2do,however,disagree with PacifiCorp's assumption that
3 the 12%figure will remain constant after the Combined
4 Projects are placed into service.As a result of the way
5 transmission costs get allocated,that percentage will
6 decline as a result of constructing the Combined
7 Projects.Mr.Vail never responded to the concern that
8 the percentage will decline.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24 17 Supplemental Direct and Rebuttal Testimony of Rick Vail,Page
25
27,Line 13-16.
1617 Mullins,Supp-Di -27a
PIIC
1 Q.IS MR.VAIL CORRECT THAT THE PORTION OFO2TRANSMISSIONREVENUEREQUIREMENTFUNDEDBYRETAIL
3 CUSTOMERS WILL NOT INCREASE?
4 A.No.Mr.Vail's description of PacifiCorp's
5 formula rate overlooks the way that costs get allocated
6 between point to point and network integration
7 transmission customers.Because the Combined Projects
8 displace resources delivered through point to point
9 transmission,the allocation of transmission revenue
10 requirement to PacifiCorp's merchant function will
11 increase as a direct result of the construction of the
12 Combined Projects.Thus,the 12%figure cited in Mr.
13 Vail's testimony will decline,making the Combined
14 Projects less beneficial.
15 If PacifiCorp constructs the wind projects,
16 that will have the effect of increasing the load served
17 by network resources and reducing the loads served by
18 front office transactions through point-to-point
19 transmission.While PacifiCorp's network service load
20 will increase,resulting in an increase in allocated
21 cost,PacifiCorp still has to pay for the full capacity
22 of its point-to-point transmission that it uses to
23 deliver front office transactions to load,irrespective
24 of whether it actually acquires those front office
25 transactions.PacifiCorp indicated that it has no
1618 Mullins,Supp-Di -28
PIIC
1 intention of terminating any point-to-point transmission
2 as a result of constructing the Combined Projects,
3 accordingly its allocation will increase.
4 Q.DID MR.VAIL ADEQUATELY RESPOND TO THE RISK
5 THAT THE TRANSMISSION PROJECTS WILL BE DIRECT ASSIGNED TO
6 PACIFICORP MERCHANT?
7 A.No he did not.Further,there continues to be a
8 real risk that third party OATT customers will not be
9 willing to pay for the cost of any of the Transmission
10 Projects,and that the
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
1619 Mullins,Supp-Di -28a
PIIC
1 costs of the economic investment will be directlyO2assignedtoPacifiCorp's merchant function.
3 Q.WHAT IS THE IMPACT OF DECLINING THIRD-PARTY
4 REVENUES?
5 A.They are a key component to PacifiCorp's
6 benefits study.And the impact of the Wind Projects on
7 PacifiCorp Merchant's share of transmission revenue
8 requirement is easily determined under the scenario that
9 the Wind Projects are constructed.Based upon projected
10 2017 net revenue requirement of $438,765,673,
11 construction of the Transmission Projects-
12 (redacted)-will produce an approximate 17.7%transmission
13 rate increase.As a result of the Wind Projects,
14 however,the network load of PacifiCorp's merchant
15 function will increase by approximately 450 MW/mo,the
16 average energy produced by the Wind Projects,with no
17 corresponding reduction to the point to point
18 transmission used deliver front office transactions.As
19 a result,the total billing determinants will increase
20 from 13,875 to 14,325 on a 12 CP basis,but PacifiCorp's
21 share of the billing determinants will also increase by
22 about 450 MW.Based on these values,I estimate that
23 the portion of revenue requirement funded by OATT
24 customers would decline from the 12%value to
25 approximately 11.62%.While the 0.38%difference may
1620 Mullins,Supp-Di -29
PIIC
1 seem small,the impacts are material on the overall
2 benefits alleged by PacifiCorp,since it applies to
3 overall revenue requirement.Based on overall
4 transmission revenue requirements of approximately
5 $516,629,044,the difference equates to approximately
6 $1,9634,190 million per year,which over a 30 year study
7 period results in an additional present value cost of
8 $25,674,149.
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24
25
1621 Mullins,Supp-Di -29a
PIIC
1 Q.IF THE PROJECT IS TO BE APPROVED,WHAT
2 CONDITIONS MIGHT BE IMPOSED TO PROTECT AGAINST THIS RISK?
3 A.PacifiCorp is in control of the assumptions
4 that it is using in its benefits study.To the extent
5 that an assumption is based on a plain misapplication of
6 how the costs get allocated under the formula rate,or
7 based on PacifiCorp's failure to recognize the risk of
8 the Transmission Projects being directly assigned to
9 PacifiCorp's merchant function,it is appropriate to
10 apply a condition to protect against such risk.Given
11 the magnitude of the transmission rate increase involved,
12 I find it probable that OATT customers will contest
13 rolling in the Transmission Projects,since the have been
14 justified plainly on economic benefits realizable by
15 retail customers.From my perspective,a condition,as
16 identified in my summary,requiring PacifiCorp to include
17 transmission revenues in future rate cases in a manner
18 consistent with its assumption in this proceeding would
19 protect ratepayers against these risks.
20 c__Pacificorp Improperly Considered the Costs and Benefits
of the Energy Imbalance Market.
21
22 Q.PLEASE DESCRIBE THE EIM BENEFIT ASSUMPTION
23 INCLUDED IN PACIFICORP'S MODELING
24 A.In response to PIIC Data Request 21,PacifiCorp
25 confirmed that the economic analyses in the Supplemental
1622 Mullins,Supp-Di -30
PIIC
1 Direct Testimony of Rick T.Link included a modeling
2 assumption it refers to as an "Energy Imbalance Market
3 ("EIM")Benefit."le In both the System Optimizer and PaR
4 models,the transmission topology19 includes a new 300 MW
5 transmission link between Jim Bridger and Walla Walla.
6 This new transmission link
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23 18 Mullins Exhibit 305
19 For an illustration of the transmission topology used in the
24 IRP see PacifiCorp,2017 Integrated Resource Plan,Page 147,
25
Figure 7.2.
1623 Mullins,Supp-Di -30a
PIIC
1 does not exist today and PacifiCorp has no plans to build
2 it.Notwithstanding,Pacificorp believes that this
3 incremental 300 MW of transmission capability will be
4 made available when Idaho Power joins the EIM.Within
5 its models,this assumption has the effect of reducing
6 congestion out of Wyoming at Bridger (the terminating end
7 of the proposed Gateway sub-segment D2)and increasing
8 the purported economic benefits of the short list
9 resources identified in the Supplemental Direct Testimony
10 of Rick T.Link.
11 Q.DID YOU EXPRESS CONCERNS WITH THIS 300 MW LINK
12 IN YOUR DIRECT TESTIMONY?
13 A.In Direct Testimony,I testified that the EIM
14 does not operate in a way that allows a utility to
15 effectuate firm transmission of electricity,as
16 PacifiCorp has modeled with respect to its EIM benefit
17 adjustment.2o In contrast,my view was that the EIM is
18 likely to result in a net cost to Wyoming wind resources,
19 since those resource will be subject to uninstructed
20 imbalance charges,which PacifiCorp acknowledged was not
21 considered in its economic analysis.21
22 Q.HOW DID THE COMPANY RESPOND?
23 A.In Rebuttal Testimony,PacifiCorp never
24 actually responded to the propriety of the new 300 MW
25 transmission link between the Jim Bridger and Walla
1624 Mullins,Supp-Di -31
PIIC
1 Walla.Mr.Link apparently disagreed with the way I
2 characterized the Supplemental GRID studies that were
3 prepared as a part of the 2017 IRP.22 He noted that the
4 GRID model studies were only used in the 2017 IRP,and
5 not in subsequent analyses presented in this docket.23
6 I,
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22 20 Direct Testimony of Bradley G.Mullins,page 28,line 1 -page
29,line 2.
23 21 Id.
22 Rebuttal Testimony of Rick Link,page 27,line 19 -page 28,
24 line 1.
23 Id.
25
1625 Mullins,Supp-Di -31a
PIIC
1 however,acknowledged that PacifiCorp only used the
2 Supplemental GRID studies in the 2017 IRP,and that
3 PacifiCorp had since incorporated the adjustments into
4 the SO and PaR models.24 The only reason that the
5 Supplemental GRID studies were considered was due to the
6 fact that,as can be noted in PacifiCorp's response to
7 PIIC Data Request 21,PacifiCorp has been unwilling to
8 isolate the impact of the 300 MW link between Jim Bridger
9 and Walla Walla in economic studies performed using the
10 SO and PaR models.25 Since PacifiCorp has been
11 unresponsive,the Supplemental GRID studies are the best
12 information available estimating the economic impact of
13 the new,300 MW transmission link between Jim Bridger and
14 Walla Walla included in PacifiCorp's economic analyses.
15 Further,in response to the argument that the
16 EIM is likely to represent an additional ancillary
17 service cost through the imposition of instructed
18 imbalance charges,Mr.Vail testified that "there is no
19 basis to assume that uninstructed imbalance will result
20 in a net cost and,in fact,the expectation is that over
21 time there will be no net impact associated with
22 uninstructed imbalance"26 Mr.Vail,however,did not
23 provide any supporting data-such as actual uninstructed
24 imbalance charges for existing Wyoming wind resources-to
25 support his claim that the uninstructed imbalance of
1626 Mullins,Supp-Di -32
PIIC
1 Wyoming wind resources will net to zero.
2 Q.DID PACIFICORP'S CONFIRM THAT IT DID NOT
3 CONSIDER ANY UNINSTRUCTED IMBALANCE CHARGES IN ITS
4 BENEFITS STUDY?
5 A.Yes.Mr.Vail's Supplemental Direct Rebuttal
6 Testimony confirmed that the economic studies presented
7 in the Supplemental Direct Testimony of Mr.Link did not
8 consider any
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24 24 Direct Testimony of Bradley G.Mullins,page 6,lines 7 -10.
25 See Attachment A,page 14 .
25 26 Rebuttal Testimony of Rick Vail,page 23,lines 12 -14
1627 Mullins,Supp-Di -32a
PIIC
1 ancillary services costs associated with acquiring EIM
2 imbalance services applicable to the Wind RFP short list
3 wind resources.
4 Q.WHAT DID PACIFICORP'S RESPONSE TO PIIC DATA
5 REQUEST 34 SHOW?
6 A.It showed that Mr.Vail was wrong.The
7 uninstructed imbalance has tended to be positive for wind
8 resource currently located in the transmission
9 constrained area of Wyoming.Confidential Table 2,
10 below,shows the historical values.
11 CONFIDENTIAL TABLE 2
Uninstructed Tmhal an,..Costs for Wind Projects
12
6 13 Average Monthly Imbalance Cost S
TOTAL
14 2015 26,712
2016 30,533
15 2017 E,949
Average 26,731
16 Annual 320,778
17 Capacity (MW)238
18 $/MW-yr Imbalance Costs 1,351
19 Wind Projects Capacity 1311
20 Estimated Ammal Imbalance Cost of Wind Pmjects 1,770,692
21 '
22 Based on the actual experience of wind resource
23 located in eastern Wyoming,I estimate that the annual
24 imbalance costs associated with the 1,311 MW Wind
O'25 Projects will be material.I estimate that on an annual
1628 Mullins,Supp-Di -33
PIIC
1 basis that cost will be $1,770,692,as detailed in
2 Confidential Table 2,above.
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1629 Mullins,Supp-Di -33a
PIIC
1 Q.BASED ON THIS HISTORICAL DATA,HOW MUCH
2 INSTRUCTED IMBALANCE TO YOU EXPECT FOR THE WIND PROJECTS?
3 A.Based on the average $/MWh of these historical
4 levels,incorporating these imbalance charges will reduce
5 the benefits of the Combined Projects by approximately
6 $22,925,985 over the 30-year study period.
7 Q.WHAT IS THE IMPACT OF THE 300 MW TRANSMISSION
8 LINK?
9 A.I also continue to disagree with the 300 MW
10 transmission link that PacifiCorp has included in its
11 economic analysis.Inclusion of a firm 300 MW
12 transmission link is not consistent with the operation of
13 the EIM,which does not provide a utility with firm
14 transmission rights,as assumed in PacifiCorp's analysis.
15 In Mullins Exhibit No.305,in response to PIIC Data
16 Request 31,PacifiCorp confirmed that "use the EIM to
17 achieve new,firm transmission rights on another EIM
18 participants'system,"as modeled with respect to the 300
19 MW transmission link.Based on the supplemental GRID
20 studies,presented in the IRP,grossed up for the higher
21 level of wind PacifiCorp has proposed through the final
22 short list,I estimate the impact of this 300 MW link to
23 be an approximate $43,416,002 reduction to the net
24 present value revenue requirement benefits PacifiCorp has
25 alleged.
1630 Mullins,Supp-Di -34
PIIC
1 Q.IF THE PROJECT IS TO BE APPROVED,WHAT
2 CONDITIONS MIGHT BE IMPOSED TO PROTECT AGAINST THESE
3 FAULTY ASSUMPTIONS?
4 A.With respect to the uninstructed imbalance,
5 there are plain costs that have been ignored,so it is
6 not appropriate to provide PacifiCorp with any claim to
7 be able to recover those amounts in the future.Applying
8 conditions,requiring PacifiCorp to take on the risk of
9 these assumptions in future ratemaking proceedings is
10 therefore appropriate,both with
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
1631 Mullins,Supp-Di -34a
PIIC
1 respect to instructed imbalance costs and the 300 MW
2 transmission link,as detailed in my summary above.
3 V.PACIFICORP DOES NOT HAVE A NEED FOR NEW RESOURCES
4 Q.ARE THE WIND PROJECTS,AND ASSOCIATED
5 TRANSMISSION,NECESSARY TO PROVIDE ELECTRICAL SERVICES TO
6 IDAHO CUSTOMERS?
7 A.No.Central to this case is whether the
8 constructing combined projects are necessary to provide
9 electrical services to Idaho customers.As noted in my
10 Direct Testimony,nothing presented in this case
11 demonstrates that the combine projects are necessary
12 utility investments.To the contrary,the most resource
13 needs assessment presented on page 91 and 92 of
14 PacifiCorp's 2017 IRP do not show any capacity for the
15 entirety of the ten year period of analysis.
16 Q.HOW DID PACIFICORP RESPOND?
17 A.PacifiCorp argues that because it has yet to
18 execute the front office transactions,that those should
19 not be considered in its resource need.I disagree.
20 Having access to bilateral market is very valuable,and
21 it is not prudent for PacifiCorp to disregard that market
22 access when considering its resource adequacy.Just
23 because the prices are uncertain does not mean that the
24 market should be excluded when considering the adequacy
25 of existing resources.
1632 Mullins,Supp-Di -35
PIIC
1 Q.HAS PACIFICORP UPDATED ITS LOAD FORECAST SINCE
2 THE 2017 IRP?
3 A.Yes.In response to PIIC Data Request 26,
4 PacifiCorp provided its most recent load forecast.
5 PacifiCorp did not,however,identify the tenor of that
6 load forecast.Notwithstanding,the load forecast has
7 declined dramatically since the issuance of the
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
1633 Mullins,Supp-Di -35a
PIIC
1 2017 IRP.In 2026,peak loads are forecast to be down by
2 approximately 14%or 1,525 MW,relative to the 2017 IRP.
3 This can be observed in Table 3,below.
4 CONFIDENTIAL TABLE 3
5 Impact of Most Recent Load Forecast (CoincidentPeak,MW)
6 Year Delta %
7 2017 (341)-3%
2018 (528)-5%
8 2019 (692)-7%
2020 (845)-8%
9 2021 (981)-9%
10 2022 (1,095)-10%
2023 (1,191)-11%
11 2024 (1,301)-12%
2025 (1,429)-13%
12 2026 (1,525)-14%
13
14 Q.HOW DOES THIS DECLINING LOAD IMPACT
15 PACIFICORP'S RESOURCE NEEDS?
16 A.In Mullins Exhibit No.306 (Conf),I update the
17 results of PacifiCorp's resource needs assessment in
18 Table 5.14 from the 2017 IRP,changing nothing but the
19 load forecast to be consistent with PIIC Data Request 26.
20 That exhibit shows,that even before considering front
21 office transactions,PacifiCorp is forecast to be in a
22 capacity surplus position of 526 MW in 2026.With front
23 office transactions that surplus position grows to 2,196
24 MW.Thus,with the declining load forecast,
25 PacifiCorp's concerns about whether front office
1634 Mullins,Supp-Di -36
PIIC
1 transactions should be considered in evaluating resource
2 needs is moot .
3 Q.WHAT DOES THAT MEAN WITH RESPECT TO
4 PACIFICORP'S RESOURCE PROPOSAL?
5 A.Ratepayers are already in a tenuous position of
6 having more resources than needed,and building the
7 Combined Projects will only exacerbate that problem.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25
1635 Mullins,Supp-Di -36a
PIIC
1 Q.HAS THE COMPANY PREPARED AN UPDATED RESOURCE
2 NEED ASSESSMENT WHEN CONSIDERING THE RFP RESOURCES?
3 A.In PIIC Data Request 21,PacifiCorp was
4 requested to confirm that it has not performed an updated
5 resource needs assessment when selecting the RFP
6 resources.In its response,the Company stated that it
7 has not performed an updated needs assessment.Finally,
8 PacifiCorp noted that it planned to issue an IRP update
9 on March 31.
10 Q.DID PACIFICORP FILE ITS IRP UPDATE ON MARCH 31,
11 2018?
12 A.No.Accordingly,the only resource needs
13 assessment available is from the 2017 IRP and that
14 assessment did not show any resource needs in the first
15 ten years of the study period.And,in fact,after
16 updating for the most recent load forecast,it is
17 apparent that PacifiCorp's resource length will grow to
18 uncomfortable levels,even without considering the Wind
19 Projects.Accordingly,I continue to recommend that the
20 CPCN request be denied on the basis that there has not
21 been a clearly demonstrated resource need,with or
22 without wholesale market transactions.
23 Q.DOES THIS CONCLUDE YOUR SUPPLEMENTAL DIRECT
24 TESTIMONY?
25 A.Yes.
1636 Mullins,Supp-Di -37
PIIC
1 (The following proceedings were had in
2 open hearing.)
3
4 DIRECT EXAMINATION
5
6 BY MR.WILLIAMS:(Continued)
7 Q Mr.Mullins,have you reviewed the
8 stipulated settlement entered into between the Company
9 and Staff and reviewed the testimony supporting that
10 settlement?
11 A I have reviewed the testimony.I have not
12 reviewed all of the numbers in that testimony and the
13 workpapers behind those,but I have reviewed the
14 testimony.
15 Q And why did PacifiCorp Idaho Industrial
16 Customers,why do they oppose the settlement?
17 A I think one of the most important things
18 about this settlement is the fact that all customers,
19 customer advocates,are opposed to it,and when you have
20 a project that is justified on providing economic
21 benefits to customers,I think that's a very significant
22 fact,and so as --and,you know,the Company has
23 presented its analyses and it's certainly entitled to,
24 you know,share its view of what the economics might be
25 for these projects and the risk attributes,but the thing
CSB REPORTING 1637 MULLINS (Di)
208.890.5198 PIIC
1 that it can't do is speak for customers and speak for the
2 risk preferences of customers and the views of customers
3 towards those projects,and as we've reviewed them,we've
4 gone through all of the analyses very,very carefully and
5 we've concluded that we do not believe that these will be
6 economic projects.
7 We don't believe that they are needed at
8 this time.You know,we believe that the Company is in a
9 long position for a very long time,and with this latest
10 IRP update,which was issued,I think,earlier this week,
11 or at least I got a copy earlier this week,it shows that
12 the need is even further out than what they had
13 previously projected.You know,you couple that with
14 changes in the market,you know,we have a lot of solar
15 coming on line throughout the region,a lot of
16 renewables.
17 I heard last night that California is
18 adopting some sort of new policy where all new
19 residential-type buildings are going to have to have
20 solar installed as a condition of installing those,so
21 when you consider all of those risks,we do not think
22 that it is appropriate to be making such a large wager
23 with ratepayer dollars at this time.We think the
24 potential for harm vastly outweighs the potential for
25 benefits,so overall,that's why we oppose the
CSB REPORTING 1638 MULLINS (Di)
208.890.5198 PIIC
1 stipulation.
2 Q Mr.Mullins,paragraph 9 of the
3 stipulation is the provision that says the Company and
4 Staff believe that the stipulated projects are a
5 reasonable way to meet the present or future public
6 convenience and necessity,which are magic words out of
7 Idaho.Code 61-526.Do you agree with this?
8 A I do not,so I think there's sort of this
9 distinction about front office transactions and whether
10 those should be considered when you're evaluating whether
11 there's a need or not and the fact is,you know,the
12 Company has invested a lot of money to have access to
13 these markets and the markets are incredibly valuable,
14 and so to just completely disregard that when considering
15 resource adequacy and when considering the utility's
16 need,in my view,is not appropriate.
17 If you were to go into,say,an organized
18 market and tell a utility that they couldn't rely on
19 imports towards their resource adequacy requirements,
20 then I don't think that utility would be too happy,so I
21 think it is appropriate to consider those.
22 Q And do you agree that PacifiCorp has an
23 obligation to respond to changing circumstances
24 regardless of what paragraph 21 of the stipulation
25 says?
CSB REPORTING 1639 MULLINS (Di)
208.890.5198 PIIC
1 A I do,and so that paragraph says that,
2 just paraphrasing,the Company may report to the
3 Commission if circumstances change,but in my view,the
4 standard of prudence requires the Company to respond to
5 changing circumstances irrespective of what that
6 paragraph says,so if it turns out that market prices
7 decline,for example,and they have been declining,then
8 it's my view that the Company has to respond to that and
9 do what it can to mitigate the harm to customers by
10 either halting the projects or whatever actions are
11 necessary.
12 Q And one last question,would you respond
13 to the prefiled testimony of Ms.Carlock regarding the
14 stipulation that the stipulated projects are based on
15 economics rather than a need for the generation and
16 capacity?
17 A Yes;so,you know,I guess I would --
18 first of all,I would disagree that there is an economic
19 case for the projects,but I guess I would agree with
20 Ms.Carlock that it's not based on a need and so in that
21 respect,I agree with her.
22 MR.WILLIAMS:Mr.Chairman,I have no
23 further questions for Mr.Mullins and submit him to
24 cross-examination.
25 COMMISSIONER ANDERSON:Thank you,
CSB REPORTING 1640 MULLINS (Di)
208.890.5198 PIIC
1 Mr.Williams.We'll start with Mr.Olsen.O 2 MR.OLSEN:No questions.
3 COMMISSIONER ANDERSON:Mr.Budge.
4 MR.BUDGE:No questions.
5 COMMISSIONER ANDERSON:We'll go to the
6 Company.
7 MR.LOWNEY:Yes,the Company does have
8 some questions.Before I get started,I'll just
9 circulate a couple of cross-examination exhibits I intend
10 to use so everyone has them before we get started.
11 (Ms.McDowell distributing documents.)
12
13 CROSS-EXAMINATION
14
15 BY MR.LOWNEY:
16 Q Good morning,Mr.Mullins.
17 A Good morning.
18 Q If we could start,if you could turn to
19 your direct testimony,please,page 11,and if I could
20 direct your attention to the question that begins on line
21 15 involving the displacement of front office
22 transactions,do you see that question and the answer
23 that follows?
24 A I do.
25 Q Now,is it true that you acknowledge that
CSB REPORTING 1641 MULLINS (X)
208.890.5198 PIIC
1 the generation from the new wind projects at issue in
2 this case could displace market transactions?
3 A In PacifiCorp's model,they have modeled
4 them to displace front office transactions.
5 Q And you would agree that if the Company
6 were to rely on front office transactions as opposed to
7 the wind projects,they would be exposed to market price
8 risk;correct?
9 A Well,so that's kind of an interesting
10 question and this is an issue that came up in a case in
11 Oregon with Portland General Electric where they wanted
12 to do this sort of long-term gas hedge and,you know,so
13 there's a difference between the customer preferences and
14 the Company's preferences with respect to that risk,so
15 from a customer's perspective,you know,if prices go up,
16 they go up for everybody,and these are companies that
17 are competing in global markets and regional markets and
18 so from their perspective,they would rather be subject
19 to that market price risk rather than locking it in and,
20 you know,potentially be paying less if market prices go
21 up and paying more if market prices go down,because that
22 puts them at a disadvantage relative to their peers.
23 Q Mr.Mullins,I think your answer was yes
24 that there is market price risk?
25 A I think my answer speaks for itself.
CSB REPORTING 1642 MULLINS (X)
208.890.5198 PIIC
1 Q Okay,and let me just direct your
2 attention to a cross-examination exhibit and forgive me,
3 I've lost my numbering --
4 COMMISSIONER RAPER:75.
5 Q BY MR.LOWNEY:--75 and this would be
6 your direct testimony that you filed in front of the Utah
7 Commission.
8 A Correct.
9 Q And I should represent to you this is an
10 excerpt from that testimony and that was filed in the
11 same docket involving the new wind and transmision
12 facilities that's at issue in Utah;correct?
13 A Correct.
14 Q And if I could direct your attention to --
15 it's the second page of the exhibit,but it's page 15 of
16 your Utah testimony,and the very first question at the
17 top of that page is a little different than the question
18 on line 15 of your direct testimony in this case that we
19 were just looking at,but your answer is substantively,
20 if not verbatim,identical;right?
21 A I believe there might have been some edits
22 between the two pieces of testimony,but it should be
23 pretty close.
24 Q And one significant edit is that in your
25 Utah testimony beginning on line 21,you have a question
CSB REPORTING 1643 MULLINS (X)
208.890.5198 PIIC
1 that says,"Is there risk in relying on front office
2 transactions?"In Utah you said,"Reliance on front
3 office transactions is not without risk";right?
4 A I did say that.
5 Q And your testimony in this case,which was
6 filed roughly the same time,doesn't make that same
7 statement,does it?
8 A It does not.
9 Q Now,something that you mentioned in your
10 response this morning to the stipulation was I believe
11 you said that it's appropriate to consider front office
12 transactions when determining if the resource --if the
13 Company has a resource need;correct?
14 A I did.
15 Q Now,you would agree that when making that
16 consideration,price matters;right?In other words,you
17 shouldn't pursue front office transactions regardless of
18 the cost just because you have access to those markets?
19 A Certainly,price matters;however,the
20 current prices for front office transactions are very low
21 and,you know,as I mentioned earlier,based on the
22 things that we are seeing in the market,our expectation
23 is that those will continue to remain low for an extended
24 period of time and just,you know,as an example of what
25 we're seeing in the market today,so towards the
CSB REPORTING 1644 MULLINS ()C
208.890.5198 PIIC
1 beginning of this year,we've seen that gas prices have
2 actually gone backward,meaning that the cost to purchase
3 gas one or two years out into the future is actually less
4 than the cost to purchase gas today,and I think that's
5 pretty significant because it's the markets telling us
6 that they expect gas prices to fall in the future,and
7 we're already beginning to see that,so I had the Wall
8 Street Journal open this morning,and in fact,I have it
9 right here,so Opal gas is --the spot price is $1.70 and
10 so that compares to prices that were close to $2.70 in
11 PacifiCorp's analysis,and so we're really seeing those
12 gas prices start to revert towards the direction of that
13 curve,and I think I noted in one piece of testimony that
14 normally those curves are upsloping and so that change,
15 at least in my experience,I haven't seen that market
16 dynamic before.
17 Q If you could turn to your supplemental
18 direct testimony,please,on page 15.
19 A Okay.
20 Q On line 9 --excuse me,line 10,you
21 testify that the requirement to conduct a solar RFP was a
22 condition imposed by the Utah Public Service Commission
23 when approving the wind RFP.Do you see that
24 testimony?
25 A I do,and I can probably clarify that.
CSB REPORTING 1645 MULLINS (X)
208.890.5198 PIIC
1 Q Because that's not correct;right?
2 A Right;so it wasn't a condition imposed by
3 the Utah Commission;however,it was a condition that
4 PacifiCorp agreed to before the Utah Commission when it
5 submitted its RFP in that docket,so in that case,
6 parties complained that solar was not being considered in
7 the RFP and so PacifiCorp issued a separate RFP for solar
8 as a result of those concerns.
9 Now,there were still a lot of --some
10 concern about that process,about having a separate
11 parallel solar RFP and a separate wind RFP on completely
12 different tracks.Because of that,you can never get a
13 true apples-to-apples comparison between the two resource
14 sets and we've kind of seen that in --
15 Q Mr.Mullins,I'm going to interrupt.My
16 only question was that your testimony was incorrect on
17 that point,correct,and you didn't correct it this
18 morning when you had the opportunity to provide
19 corrections;right?
20 A Fair enough.
21 Q Now,let's move on.If you could turn to
22 page 16 of your supplemental direct testimony,please,
23 and beginning on line 9,again we're talking about the
24 solar sensitivity studies,you testify in the first line
25 that when viewed in PacifiCorp's nominal study,and then
CSB REPORTING 1646 MULLINS (X)
208.890.5198 PIIC
1 you continue to report the results of that nominal study
2 for the solar sensitivities;correct?
3 A Correct.
4 Q And the nominal studies that you're
5 referencing are the studies that extend out through 2050;
6 correct?
7 A They are the nominal studies and those
8 studies that were prepared by PacifiCorp went out to
9 2050.I think if you were to do the same studies over a
10 different time frame,they would produce the same result.
11 I think that Mr.Phillips testified to that.
12 Q Mr.Mullins,I'm just asking you about
13 what's in your testimony,and your testimony is relying
14 on results through 2050;right?
15 A Right,and I was clarifying that the 2050
16 is not significant with respect to these conclusions,
17 because if you were to do the same analysis over a
18 shorter time frame in a nominal study,you'd come up with
19 the same or similar results.
20 Q Now,Mr.Mullins,if I could direct your
21 attention to what will be labeled Cross Exhibit 76,these
22 are the comments that you filed with the Oregon --the
23 Public Utility Commission of Oregon in January of 2017 in
24 Portland General Electric Company's 2016 IRP docket.Do
25 you have those comments in front of you?
CSB REPORTING 1647 MULLINS (X)
208.890.5198 PIIC
1 A I do.O 2 Q And if you could just turn to page 12 of
3 those comments,please,and at the very top of page 12,
4 you have a header identified as "3"and the header says,
5 "A 34-year Planning Period is Too Long,"and then in the
6 following paragraphs you indicate that your analysis of
7 Portland General Electric's IRP was limited to 20 years
8 because a 34-year planning period is too long and puts
9 too much weight on speculative assumptions about the
10 distant future;right?
11 A Yes.
12 Q And you describe that modeling out through
13 a 34-year period is problematic because forecasting
14 conditions that far into the future is inherently
15 speculative;right?
16 A Right.
17 Q And you say finally that for purposes of
18 making resource decisions today,a 20-year planning
19 period is sufficient;right?
20 A Right.
21 Q Now,the Company's analysis in this case
22 demonstrates that over the less speculative 20-year
23 planning horizon,the wind projects provide greater
24 benefits than solar;correct?
25 A So to be clear,these studies presented by
CSB REPORTING 1648 MULLINS (X)
208.890.5198 PIIC
1 Portland General Electric were nominal revenue
2 requirement studies and so the statements that the
3 further you go out in the future the more speculative the
4 results are,those are entirely applicable in this case,
5 but what Portland General didn't do was they didn't
6 monkey around with all the levelization assumptions and
7 kind of form the mixed bag of nominal and levelized
8 assumptions that went into PacifiCorp's 20-year study,
9 and so if you were to look at the solar sensitivities
10 over 20 years or maybe even 10 years,you would come up
11 with a similar result as the longer-term nominal
12 studies.
13 Q And Mr.Mullins,in this case,the
14 Company's less speculative 20-year studies also show that
15 the wind projects provide net benefits under all nine
16 price policy scenarios;correct?
17 A Well,first of all,I would disagree that
18 those are less speculative studies,because they're
19 levelized studies and so what they're effectively doing
20 is taking,you know,benefits that actually won't accrue
21 for,you know,many years beyond the 20-year period and
22 front loading those into the 20-year period and so I
23 would disagree with that.
24 Q Now,Mr.Mullins,the Company's economic
25 analysis in this case did not include any value
CSB REPORTING 1649 MULLINS (X)
208.890.5198 PIIC
1 associated with renewable energy credits or RECs;
2 correct?
3 A That is what the Company represented,
4 yes.
5 Q And would you agree that Mr.Link's
6 testimony indicates that through 2050,there's a $43
7 million increase in net benefits for every dollar
8 assigned to RECs?
9 A I think I would let Mr.Link testify
10 regarding that.
11 Q Okay,and I'll just represent to you
12 that's his testimony;is that fair?You can check it if
13 you'd like.
14 A Yeah,sure.
15 Q Now,let's turn to page 15 of your IRP,
16 your PGE IRP,comments.At the top,the very first
17 paragraph at the top of that page,the last sentence
18 says,"Based on my analysis,the nominal levelized REC
19 price"--excuse me,the second to last sentence,it
20 says,"I assumed that the Company could acquire RECs at a
21 nominal levelized price of $10 per megawatt-hour."Do
22 you see that?
23 A I do.
24 Q Now,taking at face value Mr.Link's
25 analysis that for every dollar of REC value,the net
CSB REPORTING 1650 MULLINS (X)
208.890.5198 PIIC
1 benefits will increase by $43 million and just simply
2 applying your $10 per REC price that you used to analyze
3 PGE's long-term plan would increase the net benefits by
4 $430 million in every price policy scenario;correct?
5 A Well,so I think you have to sort of read
6 this in the context of the case,so the issue in this
7 case was whether PGE should go out and build a new
8 resource or acquire RECs on the market,and the price for
9 RECs have plummeted.In fact,there's practically no
10 market for RECs right now,and so the question that we
11 were trying to answer here,and it was a question that
12 was elicited by John Savage in some previous workshops,
13 is how high would the REC price have to go in order to
14 make acquiring a physical wind resource a better idea,
15 and in this analysis,we determined that it was $32.75,
16 and so when I was doing my analysis,my economic
17 analysis,I assumed that a $10 REC value is a long-term
18 value if PGE were to not go out and build a resource,you
19 know,to show that it is a much better decision to
20 acquire RECs on the market rather than building a new
21 resource,even if the prices go up as high as $10 per
22 megawatt-hour.
23 Q Just to be clear,Mr.Mullins,using the
24 $10 per REC price that you used in your analysis just
25 over a year ago would make the wind projects in this case
CSB REPORTING 1651 MULLINS (X)
208.890.5198 PIIC
1 provide net benefits under all nine price policy
2 scenarios;right?
3 A I haven't done that analysis.
4 Q Well,I think we just established $10 per
5 REC times $43 million is $430 million,if you just add
6 that number to each of the net benefits --
7 A I have not established that and the $10
8 was really an illustrative number in that case.
9 Q An illustrative number that you said PGE
10 could buy RECs for $10 a megawatt-hour which means
11 somebody is selling them for $10 a megawatt-hour;
12 right?
13 A Potentially,yeah.
14 Q All right.One further question and this
15 relates to the testimony you provided this morning about
16 the stipulation between the Company and Staff and do you
17 have that in front of you,the stipulation?I'm going
18 to ask you a question about paragraph 21,which is
19 something that you had mentioned in your comments.
20 A Yeah,if someone has a copy,that would be
21 great.
22 Q It looks like your counsel is going to
23 provide one.
24 UMr.Williams approached the witness.)
25 Q BY MR.LOWNEY:And I just want to clarify
CSB REPORTING 1652 MULLINS CK)
208.890.5198 PIIC
1 something that you had testified to and,again,sorry,O 2 this is paragraph 21,which is on page 8 of the
3 stipulation.
4 A Okay.
5 Q And it talks about sort of what happens if
6 there's a material change in circumstance.
7 A Okay.
8 Q And what the provision says is that if
9 there's a material change,the Company may make a filing
10 with the Commission;right?
11 A Right.
12 Q And what I believe your testimony
13 discussed was whether or not the Company has an
14 obligation to prudently respond to those change in
15 circumstances and I just want to be clear,regardless of
16 what's in this paragraph,the Company always has an
17 obligation to respond prudently to changing
18 circumstances;correct?
19 A That is correct,and the thing that I was
20 pointing out is the language that says the Company may
21 make a filing with the Commission.You know,I think
22 they must make a filing with the Commission if
23 circumstances change.
24 MR.LOWNEY:All right,I have no further
25 questions.Thank you.
CSB REPORTING 1653 MULLINS (X)
208.890.5198 PIIC
1 COMMISSIONER ANDERSON:Thank you.Mr.O 2 Karpen for Staff.
3 MR.KARPEN:Thank you.
4
5 CROSS-EXAMINATION
6
7 BY MR.KARPEN:
8 Q Good morning,Mr.Mullins.
9 A Good morning.
10 Q I just want to talk to you a little bit
11 about the stipulation and actually building on that last
12 conversation with regard to paragraph 21.Would you
13 agree if the Commission imposed a modification in the
14 stipulation that may be changed to will,that would be
15 sufficient to respond to your concerns in paragraph 21?
16 A Well,I think that would still leave some
17 discretion to the Company about what it views to be sort
18 of a material change.
19 Q Let me rephrase it.
20 A It would address some of that concern.
21 Q Okay.Are you familiar with the provision
22 in the stipulation that relates to a hard cap or
23 potential for an overall capital cost cap?
24 A So I was not aware that there was a hard
25 cap in the stipulation.
CSB REPORTING 1654 MULLINS (X
208.890.5198 PIIC
1 Q There is not,so to be clear,that is theO2remainingissue,I'll submit to you the remaining issue,
3 that the Company and Staff have not agreed to in this
4 matter.Are you familiar with the idea of an overall
5 capital cost cap?
6 A I am,and it is certainly not an
7 unprecedented thing,so there are,I think,many examples
8 where utilities when they're constructing projects they
9 agree to hard caps.
10 Q Do you believe --you identified some
11 risks associated with entering the stipulation early on
12 in your testimony from your lawyer,Mr.Williams.You
13 had mentioned market change uncertainty and I think your
14 words were the potential for harm vastly outweighs the
15 potential for benefits to customers.
16 A Right.
17 Q Do you believe if this Commission were to
18 impose an overall capital cost cap that would be
19 responsive to many or perhaps all of those concerns?
20 A No,I do not.I believe that if there's a
21 hard cap that customers will still be harmed.
22 Q Would you agree that the potential for
23 harm would be reduced with an overall project cost cap?
24 A The potential for harm due to construction
25 overruns on the transmision line and wind projects would
CSB REPORTING 1655 MULLINS ()C
208.890.5198 PIIC
1 be mitigated and from my perspective,if the Company isO2confidentinitsestimates,it would be willing to submit
3 to a hard cap,but clearly,it is not.
4 MR.KARPEN:Thank you,I have no further
5 questions for this witness.
6 COMMISSIONER ANDERSON:That completes our
7 questioning,so --
8 MR.BUDGE:No questions.
9 COMMISSIONER ANDERSON:I think we've gone
10 around for questions,haven't we?Sorry,I forgot my
11 friends here.Go ahead.
12
13 EXAMINATION
14
15 BY COMMISSIONER RAPER:
16 Q Good morning.
17 A Good morning.
18 Q So you made a comment I believe in your
19 dialogue with PacifiCorp that customers prefer the risk
20 associated with front office transactions.
21 A Right.
22 Q Upon what do you base that opinion or that
23 assertion?
24 A Based on my interaction with customers,so
25 the issue there is,you know,we have markets and they're
CSB REPORTING 1656 MULLINS (Com)
208.890.5198 PIIC
1 going up and down and,you know,if gas prices go up,
2 that's an increase to all,everyone who is competing in
3 the market and so customers aren't,you know,from a
4 competitive basis,they're not harmed,because all their
5 competitors are being subject to the same price
6 increases,and then on the flip side if prices decline,
7 everyone kind of benefits and it keeps customers on a
8 level playing field.
9 Well,if you construct a project like
10 this,which is effectively a hedge against market prices
11 in some respect,if market prices go down,customers end
12 up paying more,PacifiCorp customers do;whereas,their
13 competitors are reaping the benefits of low cost markets
14 and so that puts them at a disadvantage,and so from my
15 perspective when you're looking at front office
16 transactions,you should look at it more as sort of an
17 overall portfolio of resources.We want,you know,some
18 amount of market transactions,some amount of fixed
19 resources and to just completely disregard those front
20 office transactions,I think,is not an appropriate way
21 to look at it.
22 Q Okay,I appreciate that.I would assert
23 that if customers'rates are going up because of a front
24 office transaction or whatever,just because everyone
25 else's are going,up customers still feel like they're
CSB REPORTING 1657 MULLINS (Com)
208.890.5198 PIIC
1 being harmed when their rates increase.
2 A Certainly,it's never a good thing when
3 rates increase,but from a risk perspective,it's
4 certainly less risky to be subject to that market price
5 risk rather than the fixed price risk --
6 Q I understand that that is your testimony.
7 I understand the assertion that you made for the
8 intervenors that all the intervenors oppose these
9 projects,so subject to check,would you accept that
10 there have been very few public comments filed in this
11 case?I'm not sure if you and your attorney have
12 reviewed that or not,and when we held a public hearing,
13 zero people testified at a public hearing.We did a
14 telephonic public hearing,which would have allowed
15 anyone within the region to call in.Nobody called in to
16 testify,so while the intervenors are of one mind here,
17 it would seem that the general public who the majority of
18 the people in the room understand when they believe that
19 their rates are going to go up substantially and without
20 justification,they let us know.To what would you
21 attribute the lack of public participation in this case
22 based on your assertion that customers would rather be
23 subject to the risk of front office transactions?
24 A Right;so I guess I couldn't speak to the
25 reasons why there haven't been more public comments
CSB REPORTING 1658 MULLINS (Com)
208.890.5198 PIIC
1 filed.You know,it may be just a matter of,you know,
2 this is more of a planning docket and there's no
3 immediate rate impacts,and so customers aren't as much
4 aware of the issues and certainly,I wouldn't expect the
5 run-of-the-mill residential customer to go into the weeds
6 and review all of the economic analyses to form their own
7 opinion of what the risk trade-offs are,but certainly,
8 your point is taken that a residential customer will have
9 a different perspective on risk than industrial or
10 commercial customers.
11 COMMISSIONER RAPER:Thank you.I
12 appreciate that.You would be surprised at how
13 knowledgeable our public comment customers are.I
14 appreciate your testimony.That's all I have.
15 COMMISSIONER ANDERSON:Commissioner
16 Kjellander.
17
18 EXAMINATION
19
20 BY COMMISSIONER KJELLANDER:
21 Q When you talk about front office
22 activities as it relates to the wholesale purchases,were
23 you around working in the industry during the Western
24 energy crisis?
25 A I was not working in the industry at that
CSB REPORTING 1659 MULLINS (Com)
208.890.5198 PIIC
1 time,but I'm aware of the circumstances and I think it'sO2animportantissue,because there was a lot of costs
3 there and market prices did go very high,but the one
4 distinction is that the period of high market prices
5 wasn't necessarily a long period of time.It was a year
6 to a year-and-a-half or so,and so when you look at these
7 projects,you know,there is some protection against
8 those,against high market prices,but there are better
9 ways to mitigate against potential spikes in prices in
10 the future just through the normal course of the
11 Company's hedging policies,so the Company will go out
12 and acquire front office transactions and layer them in
13 over a number of years and so what that does is help to
14 smooth out those peaks.
15 What I don't think the future holds is a
16 scenario where market prices peak to,you know,$100 or,
17 in the case of the energy crisis,thousands of dollars
18 per megawatt-hour and it stays at that level for an
19 extended time.
20 Q While you're right,the time frame in
21 which the actual crisis was being developed took multiple
22 years for some utilities and customers to actually
23 recover from,so it extended well beyond that.
24 A Right.
25 Q The other point,though,too,is it your
CSB REPORTING 1660 MULLINS (Com)
208.890.5198 PIIC
1 estimation in terms of what you've seen that hedging
2 practices are being scrutinized today around the country
3 because so many things are upside down and the concern is
4 whether or not they're going to go upside down again,
5 that all of the things we looked at in terms of natural
6 gas that used to be the leading indicators of where
7 prices would center no longer exists and a lot of concern
8 about what that might look like even in two,three years
9 down the road as those things continue to change?
10 A Right.I think at least from my
11 perspective,the big thing that we've seen is the hedge
12 prices that utilities are entering into are just
13 systematically out of whack with what the ultimate market
14 prices are,and so if you go and look at the gains and
15 losses on these hedging contracts,they're almost
16 uniformly a loss to customers,and so from my
17 perspective,that is a very concerning fact and it's kind
18 of led me to develop some of the analyses that I
19 presented in this case about forward price curves showing
20 that on a systematic basis,those curves are overstating
21 future actual market prices and so that's a very serious
22 concern both for hedging and in the short term,but more
23 so if you're entering into a transaction like this over a
24 50-year period.
25 Q But probably safe to say that regardless
CSB REPORTING 1661 MULLINS (Com)
208.890.5198 PIIC
1 of what you do,there's risk.
2 A Right.
3 Q Walking across the street,there's risk
4 and by the way,be careful --
5 A Right.
6 Q --but the bottom line is there's no way
7 to eliminate the risk.You might be able to sort of
8 levelize that out depending on how you put it together,
9 but those factors are constantly changing,constantly
10 evolving,and what we do today that may look like it's in
11 the greater public interest could be upside down within a
12 year.
13 A Right,absolutely.
14 COMMISSIONER KJELLANDER:Okay.
15 COMMISSIONER ANDERSON:Any redirect?
16 MR.WILLIAMS:I have one question,
17 Mr.Chairman,and it's in response to questions from
18 Commissioner Raper.
19
20 REDIRECT EXAMINATION
21
22 BY MR.WILLIAMS:
23 Q The three intervenors in this case are
24 representing the broad array --the PIIC customers are a
25 broad array of industrial customers,you have Monsanto,
CSB REPORTING 1662 MULLINS (ReDi)
208.890.5198 PIIC
1 and you have the Irrigation Pumpers,which is essentially
2 the farming community.Would you accept,subject to
3 check,that these three intervenor groups that are
4 opposed to the stipulation represent in excess of 70
5 percent of the load of Rocky Mountain Power in Idaho?
6 A I would.
7 MR.WILLIAMS:Thank you very much.No
8 further questions.
9 COMMISSIONER ANDERSON:Thank you very
10 much.
11 THE WITNESS:Thank you.
12 (The witness left the stand.)
13 COMMISSIONER ANDERSON:Next we have the
14 Idaho Irrigation Pumpers.Mr.Olsen,you may call your
15 witness.
16 MS.OLSEN:Yes,thank you,Mr.Chair.
17 I'd like to call to the stand Anthony J.Yankel.
18
19
20
21
22
23
24
25
CSB REPORTING 1663 MULLINS (ReDi)
208.890.5198 PIIC
1 ANTHONY J.YANKEL,O 2 produced as a witness at the instance of the Idaho
3 Irrigation Pumpers Association,having been first duly
4 sworn to tell the truth,was examined and testified as
5 follows:
6
7 DIRECT EXAMINATION
8
9 BY MS.OLSEN:
10 Q Mr.Yankel,could you please state and
11 spell your name for the record and provide your
12 address?
13 A Anthony J.Yankel,A-n-t-h-o-n-y J.
14 Y-a-n-k-e-l.Address is 12700 Lake Avenue,Unit 2505,
15 Lakewood,Ohio,44107.
16 Q Thank you.Are you the same Anthony J.
17 Yankel who filed direct testimony in this case on
18 November 20th,2017,and supplemental testimony on April
19 10th,I think,April 11th or 10th,2018?
20 A Yes,I am.
21 Q Okay,if I were to ask you the same
22 questions that are posed in that direct and supplemental
23 testimony today,would your answers be the same?
24 A Yes.
25 Q So there's no need for any corrections?
CSB REPORTING 1664 YANKEL (Di)
208.890.5198 Irrigators
1 A None of which I'm aware of.
2 MR.OLSEN:Chair Anderson,I'd like to
3 move to have Mr.Yankel's testimony and one exhibit
4 spread upon the record.
5 COMMISSIONER ANDERSON:Without objection,
6 we'll spread Mr.Yankel's testimony across the record,
7 including the exhibit.
8 (IIPA Exhibit No.401 was admitted into
9 evidence.)
10 (The following prefiled direct and
11 supplemental direct testimonies of Mr.Anthony Yankel are
12 spread upon the record.)
13
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING 1665 YANKEL (Di)
208.890.5198 Irrigators
1 Q.PLEASE STATE YOUR NAME,ADDRESS,AND
2 EMPLOYMENT.
3
4 A.I am Anthony J.Yankel.I am President of
5 Yankel and Associates,Inc.My address is 12700 Lake
6 Avenue #2505,Lakewood,Ohio,44107.
7
8 Q.WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL
9 BACKGROUND AND PROFESSIONAL EXPERIENCE?
10
11 A.I received a Bachelor of Science Degree in
12 Electrical Engineering from Carnegie Mellon University in
13 1969 and a Master of Science Degree in Chemical
14 Engineering from the University of Idaho in 1972.From
15 1969 through 1972,I was employed by the Air Correction
16 Division of Universal Oil Products as a product design
17 engineer.My chief responsibilities were in the areas of
18 design,start-up,and repair of new and existing product
19 lines for coal-fired power plants.From 1973 through
20 1977,I was employed by the Bureau of Air Quality for the
21 Idaho Department of Health &Welfare,Division of
22 Environment.As Chief Engineer of the Bureau,my
23 responsibilities covered a wide range of investigative
24 functions.From 1978 through June 1979,I was employed
25 as the Director of the Idaho Electrical Consumers Office.
1666 Yankel,DI -1Irrigators
1 In that capacity,I was responsible for all
2 organizational and technical aspects of advocating a
3 variety of positions before various governmental bodies
4 that represented the interests of the consumers in the
5 State of Idaho.From July 1979 through October 1980,I
6 was a partner in the firm of Yankel,Eddy,and
7 Associates.Since that time,I have been in business for
8 myself.I have been a registered Professional Engineer
9 in the states of Ohio and Idaho.I have presented
10 testimony before the
11 /
12
13 /
14
15 /
16
17
18
19
20
21
22
23
24
25
1667 Yankel,DI -laIrrigators
1 Federal Energy Regulatory Commission (FERC),as well as
2 the State Public Utility Commissions of Idaho,Montana,
3 Ohio,Pennsylvania,Utah,and West Virginia.
4
5 Q.ON WHOSE BEHALF ARE YOU TESTIFYING?
6
7 A.I am testifying on behalf of the Idaho
8 Irrigation Pumpers Association ("IIPA").
9
10 Q.WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
11 PROCEEDING?
12
13 A.My testimony will address Rocky Mountain
14 Power's ("Company")proposal to invest $2 billion in new
15 wind and transmission facilities ("Combined Projects").
16 The economic viability of the Combined Projects is based
17 upon receiving the full benefit of the federal wind
18 production tax credit ("PTC").In order to receive the
19 full benefit of the PTC,all of the Combined Project
20 would need to be operational by December 31,2020.The
21 Company is requesting from the Commission certificates of
22 public convenience and necessity ("CPCN")as well as
23 binding ratemaking treatment.
24 My testimony will address the costs and
25 benefits of the Combined Projects as outlined by the
1668 Yankel,DI -2Irrigators
1 Company.I will address the unique nature of this
2 request for a CPCN,given that there is not an internal
3 need for additional generation facilities for the next
4 10-years.Rather,Company witness Crane bills these
5 Combined Projects as an "exciting opportunity"1 for
6 ratepayers to realize a net present value benefit of $137
7 million spread out between 2020 and 2050.
8 /
9
10 /
11
12 /
13
14
15
16
17
18
19
20
21
22
23
24
25 1 Crane Direct @ 2.
1669 Yankel,DI -2aIrrigators
1 My testimony will also address the balance of
2 interests between the Company/stockholders and the
3 ratepayers.Given the fact that the proposed Combined
4 Projects are not needed to serve internal load,but
5 represent an "exciting"or more properly an economic
6 opportunity,it is important to understand the balance of
7 interests between the Company/stockholder and the
8 ratepayers.
9 Finally,my testimony will address a number of
10 risks associated with the Combined Projects and the
11 impact those risks could have on the economic viability
12 of the Combined Projects for the ratepayers.
13
14 Q.FROM YOUR REVIEW OF THE FILING AND OTHER
15 SOURCES,WHAT ARE YOUR CONCLUSIONS AND RECOMMENDATION?
16
17 A.I have concluded that,as filed,almost the
18 entire benefit of the Combined Projects goes to the
19 Company/stockholders in the form of a guaranteed return
20 on an investment of $2 billion.The Company only
21 forecasts a benefit to the ratepayer of $137 million that
22 will be spread between 2020 and 2050.However,that
23 forecasted benefit of $137 million is dependent upon a
24 host of risk factors resolving favorably for the
25 ratepayers.These risk factors are not trivial and can
1670 Yankel,DI -3Irrigators
1 easily turn the perceived ratepayer benefit of $137
2 million into a significant cost.
3 Because of the clear risk factors that are
4 present and the fact that the impact of these risk
5 factors would fall solely upon the ratepayers and not the
6 Company/stockholders,I recommend that no CPCN or binding
7 ratemaking treatment be given at this time.The Company
8 could refile its case after the Combined Projects are put
9 in service.
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
1671 Yankel,DI -3aIrrigators
1 In addition,because this is an economic
2 opportunity as opposed to a need for $2 billion worth of
3 new generation,a sharing mechanism must be put in place.
4 If the Company requests a rate of return on the Combined
5 Projects,then it would be appropriate that 100%of the
6 benefit go to the ratepayers-as in the filing.However,
7 because the Combined Projects are based upon assumptions
8 and forecasts put together by the Company,the Company
9 should absorb all risks associated with any changes that
10 would otherwise raise the rates to its customers.
11
12 PTC BASED ECONOMIC OPORTUNITY
13
14 Q.WHAT IS THE PURPOSE OF THE COMPANY'S APPLICATION
15 IN THIS CASE?
16
17 A.As stated by Company witness Crane2,the
18 Company's Application:
19 -includes a request for certificates of public
convenience and necessity ("CPCN")for new wind
20 and transmission facilities,and a request for
binding ratemaking treatment for investment in
21 wind and transmission projects -(Emphasis
added)
22
23 Q.WOULD IT BE APPROPRIATE TO AWARD THE COMPANY A
24 CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY FOR THIS
25 PROJECT?
1672 Yankel,DI -4Irrigators
1 A.No.The Company makes no claim that this
2 project is "necessary".Its forecasted need for new
3 resources is at least 10 years out.There is no need or
4 necessity.The Company is proposing to add $2 billion to
5 rate base for a project that was not even contemplated in
6 last year's
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25 2 Crane Direct @ 2
1673 Yankel,DI -4aIrrigators
1 Updated 2015 IRP (filed March 31,2016).Basically,the
2 Company's case rests not on "need",but on a perceived
3 economic benefit/opportunity.As stated by Company
4 witness Crane3:
5 The time-sensitive opportunity presented by the
PTC's allows the Company to provide
6 cost-effective,emission-free generation to
serve Idaho ratepayers,while providing the
7 cost savings necessary to construct therequiredTransmissionProjectsandprovide
8 economic benefits for ratepayers.(Emphasis
added)
9
10 As I will demonstrate later in this testimony,the
11 "economic benefits"suggested by the Company are highly
12 speculative and miniscule compared to the return and
13 depreciation expenses that will be paid by the
14 ratepayers.
15
16 Q.HOW IMPORTANT IS THIS "TIME-SENSITIVE
17 OPPORTUNITY PRESENTED BY THE PTC'S"?
18
19 A.Without the full benefit of the PTC's,the
20 project would not be economical.As stated by Company
21 witness Crane4
22 My testimony details the Company's proposal to
invest $2 billion in new wind and transmission
23 facilities,all of which would be operational
by December 31,2020,as required to leverage
24 the full benefit of the federal wind production
tax credit ("PTC"),the value of which is
25 essential to the combined projects'overall
1674 Yankel,DI -5Irrigators
1 economic viability.(Emphasis added)
2 Company workpapers show a total benefit of the PTC
3 credits over the 10 years of $(redacted)5.Basically,
4 the total PTC's amount to almost (redacted)%of the cost
5 of the entire project.If this "time-sensitive
6 opportunity"is not constructed by December 31,2020,the
7 economic viability of the project will be lost.The
8 Company is making its case based upon an
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22
23
24 3 Crane Direct @ 13
25
4 Crane Direct @ 1
1675 Yankel,DI -5aIrrigators
1 economic opportunity (more for itself than for its
2 ratepayers)and not upon any contention of "necessity".
3
4 BALANCE OF INTERESTS
5
6 Q.THE COMPANY IS ALSO SEEKING APPROVAL OF BINDING
7 RATEMAKING TREATMENT UNDER IDAHO CODE §61-541.WHAT
8 STANDARD DOES THE COMPANY INDICATE MUST BE MET TO OBTAIN
9 BINDING RATEMAKING TREATMENT?
10
11 A.Company witness Crane6 states Rocky Mountain's
12 understanding of the requirements for binding ratemaking
13 treatment:
14 I understand that the Commission must maintain
a "fair,just and reasonable balance of
15 interests between the requesting utility and
the utility's ratepayers,"considering specific
16 factors.(Emphasis added)
17
18 As will be demonstrated later in this testimony,at best
19 this application skews almost all the benefit to the
20 Company and very little to the ratepayers.In addition,
21 it is very possible that the Company could get all the
22 benefit at an overall cost to the ratepayers.
23
24 Q.UPON WHAT DO YOU BASE YOUR STATEMENT THAT ALMOST
25 ALL,IF NOT ALL,THE BENEFIT OF THE COMBINED PROJECTS
1676 Yankel,DI -6Irrigators
1 WOULD GO TO THE COMPANY?
2 /
3
4 /
5
6 /
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24 5 Exhibit 27-29 Workpapers,Tab "NPC and Cost Rollup (Wind)",
Line 11.
25
1677 Yankel,DI -6aIrrigators
1 A.This $2 billion is clearly a major investment in
2 resources.If approved by the Commission,the ratepayers
3 would have a long-term commitment to be responsible to
4 pay for the Combined Projects,despite what happens.For
5 example,assuming a pre-tax Return of 10.681%7,this
6 means that ratepayers would pay $214,000,000 ($2 billion
7 x 0.10681)for a return to the Company for the first
8 year.This figure does not reflect the full cost to the
9 ratepayer because the equity portion needs to be gross up
10 by a factor of 1.6116.
11 Roughly assuming an average depreciation life
12 of 35 yearsS for the project,this would mean that the
13 ratepayers would pay an additional $57,000,000
14 ($2 billion/35)for a total of $271,000,000 plus tax in
15 the first year.The return costs will slowly decrease
16 over the assumed 35 years as rate base is slowly lowered
17 by depreciation but,the cost to the ratepayers will be
18 substantial for many years to come.
19 By contrast,assuming benefits can be
20 accurately forecasted,the present-value savings based
21 upon the Company's medium case (medium natural gas prices
22 and medium CO2 price-policy scenario and through 2050)is
23 only $137,000,000.In other words,the first-year return
24 and depreciation that will be paid to the Company will be
25 approximately double what the ratepayers will receive on
1678 Yankel,DI -7Irrigators
1 a present value basis over the next 34 years.This
2 assumes that all the Company's assumptions/forecasts are
3 accurate.
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21 6 crane Direct @ 13
7 This pre-tax rate of return is based upon the example provided in
22 Larson's Exhibit 28 page 2.This rate of return is for demonstration
purposes only and in no way showing support for the 37.951%tax rate
23 assumed by the Company.
8 Assuming a life of 30 years for the Wind and a 55-year life for the
24 Transmission.Weighting the depreciation heavier on the Wind,
results in a rough depreciation life for the Combined Projects of 35
25 years.
1679 Yankel,DI -7aIrrigators
1 RISKS
2
3 Q.IS THERE ANOTHER WAY TO LOOK AT THE BALANCE OF
4 THE INTERESTS OF THE COMPANY AND THE RATEPAYERS?
5
6 A.Yes.The highly disproportionate amount of
7 money that the Company will be guaranteed from this
8 project,compared to the relatively small amount of money
9 that the ratepayers will get,is only one way to assess
10 the interests of the Company and the ratepayers.
11 Admittedly,the balance is highly skewed in favor of the
12 Company.However,it is risk that makes this proposed
13 balance between the ratepayers and the Company completely
14 unacceptable.
15 Risk is something that completely removes any
16 pretention that there is balance between the ratepayers
17 and the Company with respect to this project.If a CPCN
18 is issued,then the Company will be guaranteed a return
19 on all prudently incurred costs.As shown above,that
20 would be a substantial amount of money.However,the
21 ratepayers bear essentially all the risk of any
22 shortfalls there are in the Company's assumptions.The
23 Company will have essentially no risk.
24
25 Q.IS THE COMPANY WILLING TO ABSORB ANY OF THE
1680 Yankel,DI -8Irrigators
1 RISKS?
2
3 A.Only to a very limited degree.The Company is
4 not willing to absorb any of the risks addressed below.
5 These risks are all associated with assumptions made in
6 this filing to support the Company's case.The Company
7 differentiates between risks that are within its control
8 and those that are not.The Company has stated that it
9 is willing to absorb the risks associated with
10 /
11
12 /
13
14 /
15
16
17
18
19
20
21
22
23
24
25
1681 Yankel,DI -8aIrrigators
1 things that are within its control (meeting the
2 five-percent safe-harbor requirement and the 80/20 test)
3 in order to be eligible for the PTC's.However,it is
4 not willing to take on any risk for the items listed
5 below.This is clearly stated in Company witness Crane's
6 Rebuttal Testimony in the Repowering case in Utah Docket
7 No.17-035-399:
8 Q.If significant portions of the repoweringprojectdonotultimatelyqualifyforPTCsdue
9 to delay,or the project incurs unanticipated
cost increases within the Company's control,is
10 the Company prepared to bear those risks?
11 A.Yes.The Company has taken everyprecautiontoensurethateachrepowered
12 facility will meet the requirements and
timelines of the five-percent safe-harbor
O 13 requirement,as well as the 80/20 test,and has
developed a construction schedule and
14 negotiated contract terms that minimize
schedule risks.While we do not believe it is
15 appropriate for the Company to absorb risks
beyond its control-such as those associated
16 with the actions of the U.S.Congress-we arepreparedtoacceptrisksassociatedwithour
17 performance.(Emphasis added)
18 The risks listed below can be considered beyond the
19 control of the Company.The Combined Projects have been
20 billed as an economic opportunity for ratepayers,but the
21 ratepayers would have to absorb almost all of the risk,
22 while the Company would be making a guaranteed rate of
23 return on a $2 billion project.
24
25 Q.WHAT ARE SOME OF THE RISKS THAT THE RATEPAYERS
1682 Yankel,DI -9Irrigators
1 WILL HAVE TO BEAR IF A CPCN IS ISSUED AT THIS TIME?
2
3 A.There are a host of issues that cause risk that
4 could reduce any economic benefit to the ratepayers from
5 the Combined Projects,and even worse,cause rates to
6 increase because
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25 9 Crane Rebuttal @ 6 in Utah Docket 17-035-39.
1683 Yankel,DI -9aIrrigators
1 circumstances did not work out as forecast by the Company
2 in this case.A brief listing of such risks includes:
3 *Natural gas prices could be less than used in
4 the Company's forecast.
5 *The federal tax rate of 35%may be lowered.
6 *The New Wind may not generate as much energy as
7 forecasted by the Company.
8 *The PTC may not be as valuable as forecasted.
9 *Today there is no policy imposing a carbon
10 emission tax.
11 I will give more detail regarding each of these risks
12 below.
13
14 Natural gas prices could be less that used in the
15 Company's forecast.
16
17 Q.ARE NATURAL GAS FUTURE PRICES IMPORTANT TO THE
18 COMPANY'S FORECAST OF RATEPAYER BENEFITS OF THE COMBINED
19 PROJECTS?
20
21 A.Yes,this is very important.Of the nine
22 scenarios used to evaluate the economic viability of the
23 Combined Projects,two scenarios (low natural gas10,no
24 carbon tax and low natural gas,medium carbon tax11)
25 produced negative results-there was a net cost to the
1684 Yankel,DI -10Irrigators
1 ratepayers from the Combined Projects.However,the
2 Company justifies the Combined Projects primarily based
3 on a net benefit to ratepayers of $137 million assuming a
4 medium natural gas assumption and the medium carbon tax
5 assumption.This suggests that the forecasted price of
6 natural gas is a very important variable.
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23 lo Link Direct @ 32 --low price natural gas price at levelized $3.19
per MMBTU.
24 11 Link Direct @ 32 --medium carbon price at $3.41/ton in 2025
25
growing to $14.40/ton in 2036.
1685 Yankel,DI -10aIrrigators
1 Q.HAS THE COMPANY SHOWN AN ABILITY TO REASONABLY
2 FORECAST NATURAL GAS PRICES?
3
4 A.No.In recent history the Company has
5 forecasted higher gas prices than actually occurred in
6 the near-term.Additionally,the Company's long-term
7 forecasted natural gas prices continue to be high,but
8 are reduced with each subsequent forecast.This pattern
9 of projecting higher natural gas prices and then lowing
10 them in subsequent forecasts,has been consistent since
11 at least 2010.
12
13 Q.WHAT HAVE BEEN THE NATURAL GAS PRICES SINCE
14 2010?
15
16 A.The following data from the U.S.Energy
17 Information Administration shows the annual NYMEX natural
18 gas future prices since 2010.
19 /
20
21 /
22
23 /
24
25
1686 Yankel,DI -11Irrigators
21
Figure 1
3 -5 --------------------------------------
4.5 ------------------
4 4 .
3.553 -------------------
2.56
2 ----------------------LL
7 1.5 -------------------
1 ------------------------
8 o.s
9 2010 2011 2012 2013 2014 2015 2016
o 110series14.382 4.026 2.827 3231 4162 2.627 2.546
11
12
13 Overall,there has been a downward trend in natural gas
14 prices since 2010.
15 /
16
17 /
18
19 /
20
21
22
23
24
25
1687 Yankel,DI -llaIrrigators
1 Q.HOW HAVE THE COMPANY'S HISTORIC FORECASTS
2 COMPARED TO THIS ACTUAL DATA?
3
4 A.The Company's 2013 IRP contains a graph that
5 compares its forecasted natural gas prices from 2010,
6 2011,and 2013.
7
8 Fi¿ywe2
9 Pac-Onap-2013RP Camsit7-urwarna
10 Figure 74-etBase IEmeryHeb GasfriceTerecasts need daremm.«Iggs
11
'13 $5
14
15 &
16 $2
18 -e-aanero.¢aolo
19
20
21 The first thing that should be noticed from
22 this graph is that the forecasts made over each
23 succeeding year (2010,2011,and 2012)drop over the
24 range of the years being forecast.It is also noteworthy
25 to look at the data for the near-term years of eachO
1688 Yankel,DI -12Irrigators
1 forecast.For example,overall for a given year,the
2 prices forecasted in 2012 are generally $1-$2 per MMBTU
3 lower than what was forecasted for the same future years
4 made in the 2010 and 2011 forecasts.
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1689 Yankel,DI -12a
Irrigators
1 The forecasted prices on this graph start at
2 2013.The actual natural gas Henry Hub prices in 2013
3 was $3.73 per MMBTU.The 2012 (the forecast nearest in
4 time to 2013)came closest to the actual price at just
5 under $4.00/MMBTU.The 2011 forecasted natural gas price
6 for 2013 came in at approximately $5.00/MMBTU.The 2010
7 forecasted natural gas price for 2013 came in at
8 approximately $5.25/MMBTU.In keeping with the general
9 shapes of the graphs for these three forecasts,each
10 succeeding forecasted price was lower and each succeeding
11 lower forecast moved (slowly)in the direction of the
12 actual price that was ultimately realized.
13 A similar pattern can be seen for the prices
14 forecasted for 2016.The actual futures price for 2016
15 was $2.546/MMBTU.None of the three forecasts shown
16 above are anywhere near this actual price for 2016.The
17 2010 forecasted price for 2016 (six years out)was
18 approximately $7.50/MMBTU-approximately 3 times the price
19 that was realized.The 2011 forecasted price for 2016
20 (five years out)was approximately $5.70/MMBTU-a little
21 more than 2 times the price that was realized.The 2012
22 forecasted price for 2016 (four years out)was
23 approximately $4.70/MMBTU-a little less than 2 times the
24 price that was realized.
25 Clearly,Rocky Mountain's forecasted natural
1690 Yankel,DI -13Irrigators
1 gas prices are not accurately reflecting future prices.
2 This is not necessarily the fault of the Company,but is
3 reflective of the nature of the beast.The problem is
4 that the Company is taking these very volatile future
5 natural gas prices and using them in its model to
6 forecast whether the Combined Projects will have a
7 positive or negative impact upon ratepayers.Given the
8 fact that the Company's natural gas forecasts have been
9 predicting prices higher than realized,the benefit of
10 the Combined Projects to the ratepayers could be
11 significantly less than the Company's projections and
12 could even result in a net cost.In any event,the
13 upshot of this great volatility in the future price of
14 natural gas renders any attempt to forecast the economic
15 value of the Combined Projects meaningless.Because the
16 /
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18 /
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20 /
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22
23
24
25
1691 Yankel,DI -13aIrrigators
1 Combined Projects are not needed facilities,but are
2 being proposed for economic reasons,it is inappropriate
3 for the ratepayers to bear the risk of natural gas prices
4 not being as low as the Company forecast in its medium
5 natural gas scenario.
6
7 Q.DID THE NATURAL GAS FORECAST CONTAINED IN THE
8 2015 IRP DEMONSTRATE BETTER ABILITY TO PREDICT THE FUTURE
9 PRICE OF NATURAL GAS?
10
11 A.No.The graph below of Henry Hub NYMEX Futures
12 comes from Figure 3.5 of the Company's 2015 IRP.
13
Figure 314&cmcDRP-20151RP CH TR$THEPImamioEnvmómm
15
Hgare3.5 -Henry Hab NYMEX Futures
16 5.00
17 4.50
18
19 3.00
2 2.50
20 Ey 2.00
21 1.50
1.00
22 0.50
24
--Annual Strip as of Jan 27,2015
25
1692 Yankel,DI -14Irrigators
1 The shape of the curve is certainly smoother
2 than the forecasts that are shown in Figure 2.The
3 forecast in Figure 3 does not try to predict every
4 nook-and-cranny over the 20-year planning horizon.The
5 forecasted prices for natural gas in this 2015 forecast
6 are even lower than the forecasts from 2010,2011,and
7 2012.In fact,the 2015 forecast shows a dramatic
8 reduction in future natural gas prices compared to 2010,
9 2011,and 2012.For example,the forecasted 2027 price
10 for natural gas in the 2011 forecast was approximately
11 $9.25/MMBTU,while the 2015 forecast for 2027 was half of
12 that at approximately $4.60/MMBTU.The long-term
13 forecasts are quite volatile.
14 However,the January 2015 short-term forecast
15 in Figure 3 is also not reliable.The forecasted price
16 for 2016 (one year out)in Figure 3 is approximately
17 $3.40/MMBTU.As demonstrated in Figure 1 above,the
18 actual 2016 natural gas futures price was $2.546/MMBTU.
19 Even the short-term forecasts are proving to be very
20 inaccurate.
21
22 Q.HOW DO THE HENRY HUB NYMEX FUTURES IN THE 2017
23 IRP COMPARE WITH THOSE FOUND IN THE 2013 AND 2015 IRP'S?
24 A.The future natural gas prices look very
25 different in the 2017 IPR as seen below:
1693 Yankel,DI -15Irrigators
21
Figure4
3
4 PacreicORP-2017 IRP CHAPTER3-Tim PLANNING ENVaubibíENT
5 Ngure3.5 -Henry Hub NYMEX Futures
4.co
3.50
3.00
8 y 2.50
I 2.00
9 1.50
10 1.00
11
0.00
13 --Ammaal Strip as of Jan 20,2017
14 -
15
16
17 The prices in the 2017 IRP are substantially lower than
18 the forecasted prices in both the 2013 and the 2015
19 IRP's.Instead of forecasting rising prices,the 2017
20 IRP shows lowering prices over the next couple of years
21 and then gently rising prices after that.Because this
22 forecast is "current"there is no actual data with which
23 to judge its accuracy for the near-term,let alone the
24 long-term.
25
1694 Yankel,DI -16Irrigators
1 Q.DOES THE COMPANY CLAIM THAT ITS FORECASTED
2 NATURAL GAS PRICES ARE BETTER IN THIS CASE THAN IN THE
3 PAST?
4 A.No.The Company recognizes that there can be
5 great deviation between forecasted prices and realized
6 prices.Because of this,the Company offers three
7 natural gas price scenarios
8 /
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18
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21
22
23
24
25
1695 Yankel,DI -16aIrrigators
1 for use in its analysis of the economic value of the
2 Combined Projects on its ratepayers (the ones that are to
3 absorb the risk).On a nominal levelized basis the
4 prices at Henry Hub for 2018-2036 used by the Company12
5 range from:
6 Low Gas $3.19/MMBTU
7 Medium Gas $4.07/MMBTU
8 High Gas $5.83/MMBTU
9 There is certainly a great deal of variability in the
10 scenarios being used to develop the economic analysis of
11 the Combined Projects for which the ratepayers are being
12 asked to absorb the risk.
13
14 Q.ARE THERE ANY OTHER FORECASTS THAT DEMONSTRATE
15 THE VOLATILITY OF THE NATURAL GAS PRICES BEING USED BY
16 THE COMPANY?
17
18 A.Yes.In the rebuttal testimony filed by the
19 Company in the Repowering case in Utah that I mentioned
20 above (Docket No.17-035-39),there was a comparison of
21 the future natural gas prices taken from the April 26,
22 2017 with natural gas prices from September 30,2017.
23 Mr.Link's Rebuttal Testimony stated13:
24 Over the period 2018 through 2036,the nominal
levelized price for Henry Hub natural-gas
25 prices has dropped by approximately 2.6 percent
1696 Yankel,DI -17Irrigators
1 from $4.07/MMBtu to $3.97/MMBtu.The reduction
in levelized prices is primarily driven by
2 reductions in the 2023 and 2024 time frame.
3 These reductions,although seemingly small,took place
4 within a 6-month period.Additionally,the fact that the
5 primary reductions took place in the near-term
6 (2023-2024)demonstrates how difficult it is to
7 accurately forecast natural gas prices.
8 /
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12 /
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14
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18
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20
21
22
23
24 12 Link Direct @ 32.
13 Link Rebuttal @ 6 in Utah Docket 17-035-39.
25
1697 Yankel,DI -17aIrrigators
1 The federal tax rate of 35%may be lowered.
2
3 Q.WHAT IS THE CONCERN WITH THE COMPANY'S TREATMENT
4 OF THE FEDERAL TAX RATE AS IT APPLIES TO THE ECONOMIC
5 ANALYSIS OF THE COMBINED PROJECTS?
6
7 A.In its analysis the Company used a corporate
8 federal income tax rate of 35%.This rate was in place
9 when the Company filed its case (and is still in place at
10 this writing).However,since the Company filed its
11 case,there has been a proposal in Congress to reduce the
12 corporate federal income tax rate down to 20%.This is
13 only a proposal and there is no telling if the rate will
14 be changed or,if changed,to what level.However,there
15 is a mood in Washington to reduce taxes and any such
16 change could greatly impact the economic analysis of the
17 Combined Projects.A lowering of the federal income tax
18 rate would have a negative impact on the economic
19 -viability of the Combined Projects and the ratepayers
20 who would bear the risk of such change.
21
22 Q.HAS THERE BEEN ANY ANALYSIS BY THE COMPANY IN
23 THIS CASE THAT ASSESSES THE IMPACT OF A CHANGE IN TAX
24 RATE?
25
1698 Yankel,DI -18Irrigators
1 A.Not to my knowledge.However,the Company has
2 performed such an analysis in its rebuttal case in its
3 Repowering case before the Public Service Commission of
4 Utah (filed October 2017).The analysis performed by the
5 Company on the sensitivity of a change in the federal tax
6 rate was based upon an assumed new rate of 25%-not the
7 20%rate presently proposed in Congress.The size of the
8 wind facilities and primarily the PTC's (which are highly
9 /
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1699 Yankel,DI -18a
Irrigators
1 impacted by the federal income tax rate)in the
2 Repowering case are similar in magnitude to the PCT's in
3 the Combined Projects case.Likewise,the rate base
4 additions for the two cases are in the general ballpark
5 of each other ($2 billion in this case14 and $1.13 billion
6 in the repowering case15).Therefore,I assume that the
7 Company's analysis in the Utah Repowering case will give
8 a ballpark figure of what a change to a 25%federal tax
9 rate would do to the economic viability of the Combined
10 Projects.
11 In its rebuttal case in the Utah Repowering
12 case,the Company calculated a reduction in the economic
13 value of such a change at $93 million to $97 million.16
14 This singular change in the federal tax rate could be
15 very detrimental to any ratepayer savings.
16
17 The New Wind may not generate as much energy as
18 forecasted by the Company.
19
20 Q.WHAT WOULD THE MAGNITUDE OF THE RISK BE IF THE
21 COMBINED PROJECTS DID NOT GENERATE AS MUCH ENERGY AS
22 FORECASTED BY THE COMPANY?
23
24 A.The Company made assumptions about the capacity
25 factor of the New Wind,like it had to make hundreds of
1700 Yankel,DI -19Irrigators
1 other assumptions.Only time will tell if those
2 assumptions/forecasts are accurate.Company witness Link
3 indicated that the Company reviewed its New Wind cost and
4 performance criteria and lowered its capacity factor
5 assumptions from 43.0%to 41.2%when
6 /
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24 14 crane Direct @ 1.
25
CL nkeReDedal @23n a aPACD-Ec
17-035-39.
1701 Yankel,DI -19aIrrigators
1 it did its sensitivity analysis of
2 Aeolus-to-Bridger/Anticline Line.1 This 1.8 percentage
3 point drop gives an order of magnitude of possible
4 changes in capacity factors.
5 In order to quantify the impact of possible
6 fluctuations in capacity factor,I will assume that the
7 PTC's are based upon a capacity factor of 41.2%.A 1.0
8 percentage point decrease in the capacity factor from
9 41.2%down to 40.2%would be well within the range of
10 change that the Company used in its sensitivity analysis.
11 As pointed out previously,the Company calculated a total
12 PTC credit over 10 years of $(redacted)
13 (redacted)
14 (redacted)
15 (redacted)
16 Comparing this possible loss of the PTC credit to the
17 Company's suggested present value benefit to the
18 ratepayers of $137 million indicates how volatile the
19 ratepayer's suggested benefit is.
20
21 The PTC credit may not be as valuable as forecasted
22
23 Q.PLEASE EXPLAIN WHY THE PTC CREDITS MAY NOT BE AS
24 VALUABLE AS FORECASTED BY THE COMPANY.
25
1702 Yankel,DI -20Irrigators
1 A.In establishing the PTC,the Company stated
2 that:
3 The current value of federal PTC's which isadjustedannuallyforinflationbytheInternal
4 Revenue Service,is $24 per megawatt-hour
("MWH").At a federal and state effective tax
5 rate of 37.95 percent,the current PTC equates
to a $38.68 per MWh reduction in revenue
6 requirement that can be passed through to
consumers.(Emphasis added)
7 /
8
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11 /
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24 17 Link Direct @ 8.
25
18 Link Direct @ 10.
1703 Yankel,DI -20aIrrigators
1 This statement is true-for now.However,the level ofO2theannualadjustmentmaybelessthanusedinthe
3 Company's forecast.
4 Given the regulatory environment in Washington,
5 the status quo may not reflect the future.The future
6 value of the PTC's may not get the same-inflationary
7 adjustment as is now given.In fact,if the IRS stops
8 this inflationary adjustment completely,the Company's
9 forecasted value of the PTC's could drop in the range of
10 $100,000,000.This is almost equivalent to the projected
11 ratepayer benefit through 2050 for the entire project.
12 Another risk is that the Company may not get
13 the full value of the PTC's as it forecasted.The
14 Company forecasted getting the full 100%of the PTC's
15 value.However,this will only happen if the entire
16 projects'commercial operation date is no later than
17 December 31,2020.If commercial operation takes place
18 after December 31,2020,the Company will not get the
19 full 100%value of the PTC's.Assuming that the Company
20 contends that this delay was outside of its control,the
21 risk will fall upon the ratepayers.The impact of such a
22 delay could be catastrophic as outlined by Company
23 witness Crane19:
24 Each of the Wind Projects are eligible for 100
percent of the PTC benefits if the Wind
25 Projects and the Transmission Projects are
1704 Yankel,DI -21Irrigators
1 commercially operational by December 31,2020.Failing to meet the 2020 deadline puts the
2 company at risk of lose of PTC benefits,andjeopardizestheoveralleconomicsofthe
3 Combined Projects.
4 If the Commission were to grant certificates of
5 public convenience and necessity for the Combined
6 Projects as well as the requested binding ratemaking
7 treatment for the investment in the Combined Projects,
8 all the risk2o of loss of PTC benefits could fall on the
9 ratepayers.This
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16
17
18
19
20
21
22 19 crane Direct e 10.
20 It is assumed that the Company will argue that it has taken every
23 precaution to ensure that the Decerder 31,2020 deadline is met,and
thus,it follows that any loss of PTC benefits because the December
24 31,2020 date is not met would have been "out of the Company's
25
controi"
1705 Yankel,DI -21aIrrigators
1 risk can be avoided simply by not obligating the
2 ratepayers to be responsible for the cost of the Combined
3 Projects,until after they have been completed and the
4 disposition of the PTC benefits are known.
5
6 Today there is no policy imposing a carbon emission tax.
7
8 Q.WHAT ARE THE CONCERNS WITH THE COMPANY'S
9 TREATMENT OF A CARBON TAX?
10
11 A.The Company has taken all its assumptions
12 regarding load growth,plant availability,regional
13 loads,regional generation available,regional electric
14 prices,etc.and combined them into one package and then
15 ran nine different scenarios on this package to assess
16 the economic impact of the Combined Projects upon the
17 ratepayers who are being asked to bear the risk.The
18 nine different scenarios were based upon a combination of
19 three different Carbon Tax assumptions (zero,medium,and
20 high)and three different natural gas price forecasts
21 (low,medium,and high).
22 The Company's "preferred"scenario is based
23 upon forecasted medium Carbon Tax assumptions and medium
24 natural gas prices.None of us have a crystal ball,so
25 it is impossible to say what Carbon Tax and/or natural
1706 Yankel,DI -22Irrigators
1 gas price assumptions/forecasts are accurate.The best
2 we can do is to judge the viability of the various
3 assumptions based upon past experience and present
4 knowledge.There is no Carbon Tax policy now.The
5 earliest the Company forecasts a Carbon Tax being in
6 place is 2025 under its medium scenario.However,the
7 present political climate suggests that there may never
8 be a Carbon Tax within the timeframe of the Company's
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1707 Yankel,DI -22aIrrigators
1 analysis.At this time,the Company scenarios with
2 medium and high Carbon Taxes should be given little
3 weight.If the Carbon Tax remains at zero (as opposed to
4 the medium scenario suggested by the Company),the
5 ratepayer benefits of the Combined Projects would be
6 lower than the $137 million benefit upon which the
7 Company's case is based.
8
9 Q.DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
10
11 A.Yes.
12
13
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25
1708 Yankel,DI -23Irrigators
1 Q.PLEASE STATE YOUR NAME,ADDRESS,AND
2 EMPLOYMENT.
3 A.I am Anthony J.Yankel.I am President of
4 Yankel and Associates,Inc.My address is 12700 Lake
5 Ave.,Suite 2505,Lakewood,Ohio,44107.
6 Q.ARE YOU THE SAME ANTHONY J.YANKEL THAT FILED
7 TESTIMONY ON NOVEMBER 20,2017 IN THIS CASE?
8 A.Yes.
9 Q.ON WHOSE BEHALF ARE YOU TESTIFYING?
10 A.I am testifying on behalf of the Idaho
11 Irrigation Pumpers Association (IIPA).
12 Q.WHAT CONCLUSION HAVE YOU DRAWN FROM YOUR REBUTTAL
13 TESTIMONY.
14 A.A number of variables have changed since the
15 Company filed its original request for approval of the
16 Combined Projects in July 2017.At that time,PacifiCorp
17 billed its proposal as an "exciting opportunity"1 and
18 admitted that it had no internal need for the generation
19 for 10 years.PacifiCorp's need for more internal
20 generation has moved back further than the 10 years
21 originally mentioned in the original filing.
22
23
24
25 1 Direct Testimony of Crane page 2 line 4 filed July 5,2017.
1709 Yankel,Supp-Di -1Irrigators
1 Under all three sets of forecasts that have
2 been filed between July 2017 and February 2018,there
3 have been 2 out of the 9 scenarios that have consistently
4 indicated that the customers would be worse off under the
5 Combined Projects.Additionally,the two scenarios where
6 the customers would be worse off,have the most
7 likelihood of occurring.Utility regulation was not
8 meant to take gambles on "exciting opportunities".If
9 the Combined Projects were needed to serve internal load,
10 then a choice would need to be made regarding what
11 appeared to be the best and cheapest way to meet that
12 need.However,when there is no internal need,the
13 Commission should not be taking chances with ratepayer
14 funds that may or may not yield a customer benefit.
15 The Company's most recent filing in Wyoming
16 points out that it needed to adjust/reduce its modeled
17 market price projections for solar because of the impact
18 solar could have upon the market.Thus,PacifiCorp's
19 projects for the benefits of solar were reduce from what
20 it would have been if the same price projections were
21 employed as those used for the Combined Projects.The
22 same adjustment should have been made for the Combined
23 Projects as they will be built to operate in the same
24 future markets/prices that the Company is now using for a
25 possible solar project.Additionally,the Combined
1710 Yankel,Supp-Di -2Irrigators
1 Projects and other wind projects in the region would have
2 their own impact on market prices as would the solar
3 projects modelled by the Company.Without these changes
4 to the modelling of the impact of solar and wind projects
5 in the region,all of PacifiCorp's nine scenarios of the
6 Combined Projects are over-optimistic.
7 The Combined Projects are not standard
8 regulatory projects,and as an "exciting opportunity",
9 should be rejected by the Commission.If the Commission
10 were to approve the Combined Projects,it should put
11 sufficient caps and/or safeguards to insure that there
12 will be no negative benefit to the customers during the
13 30-year life of the project.
14 /
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18 /
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1711 Yankel,Supp-Di -2a
Irrigators
1 Q.PLEASE GIVE A BRIEF OVERVIEW OF PACIFICORP'SO2FORECASTSOFTHEBENEFITSOFITSNEWWINDAND
3 TRANSMISSION IN THIS CASE.
4 A.PacifiCorp has filed testimony three times in
5 this case (plus one set of corrections).The focus of
6 these filings has been the forecast of the financial
7 benefits to customers of the Combined Projects over a
8 20-year and a 30-year timeframe.In each of the filings,
9 nine scenarios were run to predict the possible financial
10 benefit to customers from this multi-billion-dollar
11 project.The nine scenarios consisted of a high,medium,
12 and low estimate for natural gas prices and the
13 possibility of a carbon tax.These were the only
14 variables that were changed in order to calculate
15 possible outcomes (benefits).The 30-year forecasted
16 present value benefit to the customers of each of these
17 forecasts,for each scenario,are listed in Table 1
18 below:
19 /
20
21 /
22
23 /
24
25
1712 Yankel,Supp-Di -3Irrigators
1
2 Ngniinal R&mue RequirementPYRR(d)
3 (Benefitydest ofcombined Frojects(S million)
ILas Domin Decembe February4
5
6 ow Gaw Zero 00:*W4 $149 8195 $15$
Low Gas,MediumCO2 $93 $133 $159 598
7 Low IIIghCO2 -8194 -8105 -879 4114
Medima Gas,Zero 004 -$53 -$60 4834 $121
Medimag Medium CO2 4131 -SITY 401 -8196
9 Medum Gas,Inghcom -510 -Slot -5215 -8335
gh 2ierg COi -$341 4437 4411 7710IHghGas,Medimn CO2 4351 4479 4453 $528
11 gBas,Ë¢06 495 -$50
12
13
14 /
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16 /
17
18 /
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20
21
22
23
24
25
1713 Yankel,Supp-Di -3aIrrigators
1 These forecasts were made over a 9-monthO2period.There has been a fair amount of variation in the
3 results,but some things have remained constant.There
4 were some major changes in circumstances between the July
5 2017 filing and the February 2018 filings.Specifically,
6 bid prices had been received for the wind turbine
7 installations,and the maximum corporate federal income
8 tax rate dropped from 35%to 21%.Continuing the trend,
9 I pointed out in my Direct Testimony,the forecasted
10 prices of natural gas dropped approximately three
11 percent2 from those used in the Company's July 2017
12 filing.Additionally,the Company's new load forecast
13 lowered system energy requirements in 2036 by 6.3%and
14 summer peak requirements by 7.2%3 -reducing the need for
15 generation for system load even further than that used in
16 the July 2017 filing.
17 Q.WHAT IS THE SIGNIFICANCE OF A DROP OF 7.2%IN
18 THE SYSTEM SUMMER PEAK REQUIREMENT?
19 A.The Company's 2017 IRP projects an 886 MW
20 (8.7%)increase in summer peak over the 10-year period
21 2017-2026.4 This is on the same order of magnitude as
22 the 7.2%decrease in forecasted in load used the February
23 2018 filing.Although the capacity of the Combined
24 Projects is now listed as 1,311 MWS,this is far more
25 than the capacity that can be expected to be delivered at
1714 Yankel,Supp-Di -4
Irrigators
1 the time of the summer peak.On an historical basis,the
2 Company owned wind resources (1,032 MW)and the Company
3 non-owned wind resources (1,301 MW)
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
20
21
22 2 Supplemental Direct Testimony of Link page 20 line 5 filed January
18,2018.
23 3 Supplemental Direct Testimony of Link page 18 lines 19-21 filed
January 18,2018.
24 4 2017 IRP page 76.
5 Second Supplemental Direct Testimony of Link page 1 line 15 filed
25 February 16,2018.
1715 Yankel,Supp-Di -4aIrrigators
1 are only delivering 339 MW at summer peak.6 This
2 translates into only 14.5%output at time of summer
3 system peak (339 /(1,032 +1,301)).For the 1,311 MW of
4 new wind capacity,this translates into 190 MW (1,311 x
5 0.145).The impact of the Combined Projects on meeting
6 future summer peaks is minuscule compared to the
7 Company's changes in forecasted internal peak load that
8 that has been made during the July 2017-February 2018
9 timeframe.
10 In the Company's July 2017 filing,it was
11 admitted that PacifiCorp would not require incremental
12 system capacity until 2028.7 Assuming that most of the
13 2017 IPR projected increase in internal load (in the
14 range of 800-1,000 MW)does not occur,as now forecast in
15 the Company's January 2018 testimony,there is no need
16 for the peaking capacity of 190 MW of the new wind (1311
17 MW capacity)until well into the future.The Combined
18 Projects should only be viewed as an "exciting
19 opportunity"as opposed to a traditional regulatory
20 addition of plant to satisfy internal load.
21 Q.WHAT HAS STAYED THE SAME BETWEEN THE THREE
22 FORECASTS THAT WERE FILED BETWEEN JULY 2017 AND FEBRUARY
23 2018?
24 A.Despite all the differences in input data
25 between July 2017 and February 2018,two of the scenarios
1716 Yankel,Supp-Di -5Irrigators
1 always forecast that the ratepayers would be worse off
2 with the Combined Projects-the low gas/zero carbon and
3 the low gas/medium carbon.It should be noted that this
4 is for the 30-year life of the project.The Company
5 points to the fact that for its 20-year forecast period,
6 the Combined Projects are beneficial to the
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24 6 2017 IRP at page 78.
25
7 Direct Testimony of Link at page 6 line 7-8 filed July 5,2017.
1717 Yankel,Supp-Di -5aIrrigators
1 ratepayers under all nine scenarios.However,this is a
2 red herring as the expected life of the project is 30
3 years and it is upon 30 years that the depreciation rate
4 is calculated.
5 Q.GIVEN THE FACT THAT TWO OF THE NINE SCENARIOS
6 THAT WERE USED TO FORECAST RATEPAYER BENEFIT,SHOW A
7 NEGATIVE IMPACT ON RATE PAYERS,HOW SHOULD THE COMMISSION
8 VIEW THESE RESULTS IN LIGHT OF THE COMPANY'S REQUEST FOR
9 REGULATORY TREATMENT OF THE COMBINED PROJECTS?
10 A.The Combined Projects are not needed in the
11 regulatory sense and,only provide a unique "economic
12 opportunity"as the Company claims.Utility regulation
13 was never meant to address "exciting opportunities".On
14 its face,utility customers should never be given a 7 out
15 of 9 chance that an unneeded project will be economically
16 beneficial.If ratepayers were gamble's,they could
17 choose to put their money in the stock market or go to
18 Vegas.The Commission should never make such a decision
19 for the customers.
20 Q.DO YOU BELIEVE THAT EACH OF THE NINE SCENARIOS
21 USED BY THE COMPANY HAVE AN EQUAL CHANCE OF OCCURRING?
22 A.Absolutely not.With each passing day,the six
23 scenarios that are not based on "Low Gas"prices become
24 less and less likely.This is suggested by the ever
O 25 decreasing forecasted prices of natural gas that the
Company has been using over recent
1718 Yankel,Supp-Di -6
Irrigators
1 years.The fact that the forecasted prices of natural
2 gas in the January 2018 filing dropped approximately
3 three percent from those used in the Company's July 2017
4 filing (6 months earlier)attests to the appropriateness
5 of assuming low future prices of natural gas will be the
6 norm as opposed to the Company's Medium Gas and High Gas
7 scenarios (6 out of the 9 scenarios).
8 Q.WHY HAVE THE FORECASTED PRICES OF NATURAL GAS
9 BEEN DROPPING AND WHY WOULD THEY CONTINUE TO BE LOW IN
10 THE FUTURE?
11 A.Natural gas future prices,like any commodity,
12 depend upon expectations of future supply and demand.In
13 turn,expectations of future supply and demand depend
14 upon past performance and how the historical patterns are
15 expected to change in the future.Natural gas supplies
16 and demands have undergone unprecedented changes in
17 recent years.During the last decade,the demand for
18 natural gas has radically increased because of the use of
19 gas turbine generators and the decisions to increase
20 exports including the liquification of natural gas for
21 export.Such radical increases in the use,and thus
22 demand,for natural gas should have driven prices much
23 higher than historic trends.However,prices have been
24 decreasing and not increasing.It has been the
25 decreasing of prices that made the use of gas turbines
1719 Yankel,Supp-Di -7Irrigators
1 and export of natural gas possible.
2 Q.WHAT HAS CAUSED THE DECREASES IN THE PRICE OF
3 NATURAL GAS?
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1720 Yankel,Supp-Di -7aIrrigators
1 A.The price of natural gas has been driven down
2 by a combination of new technology and new finds of
3 natural gas reserves.The region in which I live has
4 always produced natural gas,but its production was pale
5 in comparison to that coming out of the Gulf and Texas
6 area.I cannot speak from personal knowledge of other
7 regions,but the natural gas production in my region has
8 changed dramatically.
9 By way of example,I was recently told by a
10 local Congressman that:If Ohio,Pennsylvania,and West
11 Virginia were to become their own county,then that "new
12 nation"would be the third largest producer of natural
13 gas in the world.The only thing keeping supply
14 increases from going through the roof is the low price of
15 natural gas.
16 Q.CAN YOU POINT TO ANY SOURCES THAT ADDRESS THE
17 GROWING GLUT OF NATURAL GAS IN THE COUNTRY?
18 A.Yes.Less than a month ago there was a
19 detailed article in the Wall Street Journal that
20 addressed changes that are taking place and the glut of
21 natural gas in this Country.8 A copy of this article is
22 contained as Exhibit 401.There are several things that
23 can be gleaned from this article:
24 *This winter heating season has been
25 robust,domestic demand is up,and record
1721 Yankel,Supp-Di -8Irrigators
1 volumes are being sold abroad.Even with thisO2unprecedentedgrowthindemand,the price of
3 natural gas has dropped.
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24 8 Walls Street Journal,"Two Wells Help Explain Natural-Gas Glut"
25
March 22,2018,page B-14.
1722 Yankel,Supp-Di -8aIrrigators
1 *Two "supersized"wells in southwestern Wyoming
2 were the featured in the article.These "
3 supersized"wells deliver far more than normal
4 wells and the cost of the wells per unit of
5 output is less than for traditional wells.
6 *Ultra Petroleum,the owner of the two wells,
7 claims to have 700 locations on its land where
8 it believes it can drill similarly designed
9 wells.
10 *Natural gas is surging out of West Texas as a
11 byproduct of frenzied oil drilling.
12 *In Louisiana,producers have been
13 "supersizing"wells.
14 *New pipelines are being built in Appalachia to
15 bring this output to market.
16
17 A paradigm shift began in the natural gas industry about
18 a decade ago,and this news article speaks of yet another
19 paradigm shift that is beginning to take place.This
20 further supports the fact that the Low Gas scenarios in
21 PacifiCorp's forecasts are far more likely to occur than
22 the Medium Gas or High Gas scenarios.
23 Q.THERE HAS BEEN RECENT DISCUSSION IN OTHER
24 STATES THAT PACIFICORP SHOULD BE PROPOSING TO BUILD SOLAR
25 GENERATION AS A BETTER ALTERNATIVE THAN THE COMBINED
1723 Yankel,Supp-Di -9Irrigators
1 PROJECTS THAT ARE NOW BEFORE THE COMMISSION.WHAT HAVE
2 YOU GLEANED FROM OTHER STATES REGARDING THE PROPOSAL TO
3 SUBSTITUTE NEW SOLAR GENERATION FOR THE COMBINED
4 PROJECTS?
5 A.I have not gotten into the specifics of the
6 solar verse wind discussion,however there are two things
7 that I came away with after reading the Company's
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1724 Yankel,Supp-Di -9aIrrigators
1 Supplemental Rebuttal Testimony filed in Wyoming a month
2 ago on March 14,2018.First,the Company does not see
3 solar as a substitute for wind at this time,but that a
4 combination of wind and solar should be considered.9
5 The Company suggests that 1,320 MW of solar may be
6 beneficial to the customers-in addition to the 1,311 MW
7 of wind that is not needed to serve internal load for
8 well over a decade.Although the Company admits that
9 solar resource "costs are expected to continue to fall"
10 and that it "does not need to act now in order to capture
11 these tax savings"1o it still wants to move forward now
12 with the Combined Projects.
13 Q.WHAT IS THE SECOND THING THAT YOU CAME AWAY
14 WITH AFTER READING THE COMPANY'S SUPPLEMENTAL REBUTTAL
15 TESTIMONY FILED IN WYOMING LAST MONTH?
16 A.For its analysis of solar benefits PacifiCorp
17 "refined how it converts its forward market prices into.
18 Hourly prices to more accurately reflect hourly
19 market-price variation in those hours when solar
20 resources are producing energy."11 (Emphasis added)
21 Although this sounds highly technical,what it means is
22 that the Company discounted/reduced the future market
23 price it has used during hours of solar generation-
24 discounting the value of solar energy.The theory is
25 simply that as more solar facilities
1725 Yankel,Supp-Di -10Irrigators
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22 9 Supplemental Rebuttal of Link page 30 lines 1-6 filed in Wyoming
Docket No.2000-520-EA-17 on March 14,2018.
23 10 Supplemental Rebuttal of Crane page 2 line 9 filed in Wyoming
Docket No.2000-520-EA-17 on March 14,2018.
24 11 Supplemental Rebuttal of Link page 32 lines 6-8 filed in Wyoming
25
Docket No.2000-520-EA-17 on March 14,2018.
1726 Yankel,Supp-Di -10aIrrigators
1 come on line,the price of energy during hours of solar
2 generation will be lowered.Basically,as supply goes up
3 during certain hours,the price will drop.
4 This theory (ignoring the calculations)has
5 credibility,but it begs the question;Shouldn't a
6 similar price sensitivity be used to calculate the
7 benefits of the Combined Projects?PacifiCorp did not
8 use these devalued market prices for the Combined
9 Projects.
10 There is a lot of wind generation that is going
11 to be placed in service which is not reflected in the
12 five years of hourly data presently used by PacifiCorp to
13 develop the forward price curves it used to analyze the
14 benefits of the Combined Projects.The idea of
15 discounting prices because of increased solar generation
16 also can apply to wind generation.The fact is that
17 relative wind speeds do not vary greatly over large
18 regions.When wind speeds are high in one area,they are
19 likely to be high in other areas and if wind speeds are
20 low in one area,they are likely to be low in other areas
21 as well.The Company's modeling needs to vary its output
22 from the Combined Projects so as to reflect the day to
23 day changes in wind speed that actually occur.
24 Additionally,if the Company is going to vary its market
25 prices for its solar calculations,it should also vary
1727 Yankel,Supp-Di -11Irrigators
1 its prices for wind energy to reflect when wind
2 generation is higher,causing market prices to be lower
3 and when wind generation is lower,causing market prices
4 would be higher.If similar adjustments made to solar
5 market prices were made to the modeling of the Combined
6 Projects,the customer benefits under all scenarios would
7 have been lower.
8 Q.Does this conclude your rebuttal testimony?
9 A.Yes.
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1728 Yankel,Supp-Di -llaIrrigators
1 (The following proceedings were had in
2 open hearing.)
3 MS.OLSEN:And then Chair Anderson,I
4 just have a couple of questions as it relates to the
5 recent filing of the stipulation between Rocky Mountain
6 Power and Staff and then should be able to tender him for
7 cross-examination.
8 COMMISSIONER ANDERSON:Please proceed.
9
10 DIRECT EXAMINATION
11
12 BY MR.OLSEN:(Continued)
13 Q Mr.Yankel,why didn't the Pumpers agree
14 and join the stipulation between Staff and the Company?
15 A I think there are basically seven reasons,
16 summary reasons,why the Pumpers didn't agree with the
17 stipulation.The first is the stipulation as filed
18 doesn't protect the customers from rate increases.The
19 customers need to be held harmless.
20 Two,the hard cap that the Staff has
21 pushed for is only a minor step in keeping the customers
22 harmless from the combined projects.Customers need to
23 be fully protected from any rate increase that could
24 result from the projects.
25 Three,the Company claims the combined
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1 projects are a benefit to the customers,but it does not
2 guarantee that.The Company would be given a guaranteed
3 return,but no guarantee to the customers.At the
4 Company's best,seven out of the nine scenarios show a
5 positive benefit to the customers,but two scenarios show
6 a negative benefit to the customers.That assumes that
7 all the Company's assumptions come true.At worst,there
8 are many risks that could reduce or eliminate the
9 benefits of the other seven scenarios.
10 Four,it has been stated that these costs
11 represent zero fuel costs.That does not make this a
12 zero cost proposition.The fact that the customers will
13 be paying return,depreciation,taxes,and O&M cites to
14 the fact that there are a lot of costs to this project.
15 That is why even though it is a zero fuel cost scenario,
16 there are still two scenarios that the Company has
17 presented where the customers are worse off with this
18 project than without it.
19 Five,the stipulated projects are claimed
20 to be a reasonable way of meeting public convenience and
21 necessity.The need claimed by the Company is only an
22 economic need and not a capacity need;however,the
23 economic need is only a need if the projects produce a
24 benefit.A project that increases costs to the customers
25 is not needed.The Company admits that it may not reduce
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1 costs and we think that the Company's estimates are very
2 optimistic.Customers do not need a project that
3 increases costs.
4 Six,a capacity addition is not needed
5 until 2028.That is not only made clear in the Company's
6 2017 IRP,but in its testimony in this very case.
7 Seven,if the Commission rejects the
8 Company's filing in this case,it does not mean that the
9 combined projects can't go forward.The Company can
10 build the combined projects.The Company could then come
11 in and ask for rate base treatment of the projects.
12 That's all I have.
13 MS.OLSEN:Chair Anderson,I tender
14 Mr.Yankel for cross-examination.
15 COMMISSIONER ANDERSON:Thank you.Let's
16 begin with Monsanto.
17 MR.BUDGE:Thank you.No questions.
18 COMMISSIONER ANDERSON:Mr.Williams.
19 MR.WILLIAMS:No questions.
20 COMMISSIONER ANDERSON:The Company?
21 MR.LOWNEY:The Company does have some
22 questions and we'll circulate a cross-examination exhibit
23 as well.It's 77,I believe,unless I'm losing count
24 again,which is quite possible.
25 (Ms.McDowell distributing documents.)
CSB REPORTING 1731 YANKEL (Di)
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1 CROSS-EXAMINATIONO2
3 BY MR.LOWNEY:
4 Q Good morning,Mr.Yankel.
5 A Good morning.
6 Q If I could direct your attention first to
7 your supplemental testimony,that would be the testimony
8 that was filed in April of this year.
9 A Yes.
10 Q On page 5,beginning on line 20 --
11 A Yes.
12 Q --and in this testimony that begins on
13 line 20 on page 5 and continues on to the first line on
14 the second page,you acknowledge that the combined
15 projects --that the Company's analysis shows that in the
16 20-year forecast period,the combined projects are
17 beneficial under all nine price policy scenarios;
18 right?
19 A Yes,I stated that.
20 Q And then on the next line,so line 1 and 2
21 on page 6,you say that's a red herring because the
22 expected life of the project is 30 years,not 20;
23 correct?
24 A Correct.
25 Q Now,you would agree that the IRP planning
CSB REPORTING 1732 YANKEL (X)
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1 horizon uses a 20-year period;correct?
2 A Yes,and that's the planning horizon,
3 yes.
4 Q And you would agree that many of the
5 resources that are considered in an IRP have useful lives
6 that extend beyond that 20-year period;right?
7 A Yes.
8 Q And are you also aware that the Commission
9 has relied on 20-year planning studies when issuing prior
10 CPCNs even for resources that have longer than 20-year
11 useful lives?
12 A I can't say that I'm aware of that.I'm
13 not arguing against that.I just can't say I'm aware of
14 that,that's all.
15 Q All right,if I could direct your
16 attention to Commission Order 30892,which is Rocky
17 Mountain Power Cross Exhibit 77.
18 A Yes.
19 Q And this is the Commission's Order where
20 they granted a CPCN for the Langley Gulch project.
21 A Yes.
22 Q And Mr.Yankel,you were a witness in that
23 case;correct?
24 A Yes,I was.
25 Q And if I could direct your attention to
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1 page 27,in the first sentence on the second paragraph
2 from the bottom begins with,"Even under conservative
3 assumptions"--
4 A Excuse me,where?
5 Q Page 27 of the Order.
6 A Yes.
7 Q And it's the sentence that begins,"Even
8 under conservative assumptions."
9 A I see it.
10 Q It's the first sentence.
11 A I see it.
12 Q It says,"the net present value of the
13 benchmark resource's 20-year revenue requirement,the
14 Company contends,is $95 million less than the next
15 closest combined cycle project."Do you see that?
16 A Yes.
17 Q So in that case,Idaho Power was using an
18 NPV calculation over a 20-year period even though the
19 Langley Gulch plant did not have a 20-year useful life;
20 right?
21 A Yes.
22 Q And if I could direct your attention to
23 page 14 of that Order,please,the very first bullet at
24 the top of that page,so it's line 3,states that relying
25 on the market as an alternative to building new
CSB REPORTING 1734 YANKEL (X)
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1 generation,Staff contends,carries greater risk and the
2 potential for price volatility.Do you see that?
3 A Yes,I see that.
4 Q Now,something that you said in your live
5 testimony a few moments ago is that in order to approve
6 the combined projects,I believe your words were that
7 customers must be held harmless.
8 A Yes.
9 Q Is that a fair characterization of your
10 testimony?
11 A Yes.
12 Q Now,if customers --if the combined
13 projects were not constructed and the Company instead
14 relied on the volatile market,customers would not be
15 held harmless in that situation,would they?
16 A They would be subject to risk as they
17 would be subject to risk in this case as well,but in
18 this case,the proposal put forth by the Company,which
19 is essentially the combined projects,it does not take
20 away hardly any of that risk.The Company's IRP shows
21 numbers between 100 --no,excuse me,1,000,2,000,3,000
22 megawatt deficits and we're talking about something that
23 has a capacity of 180 megawatts,I believe,so we're
24 really not dealing with removing much of what's already
25 existing as far as front office transactions goes and
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1 this project is very speculative.
2 Q Now,if I could direct your attention back
3 to your supplemental direct testimony on page 6,the
4 question and answer that begins on line 4 and extends
5 down to line 16,you're describing something that you
6 also mentioned this morning in your live testimony and
7 that is that the Company's economic analysis that extends
8 through 2050 shows net customer benefits in seven out of
9 nine scenarios;correct?
10 A Yes.
11 Q And you testify on line 12 that utility
12 customers should never be given a seven out of nine
13 chance that a project will be economically beneficial.
14 Do you see that?
15 A I see that.
16 Q Now,your recommended course of action
17 here is to reject the combined projects and under that
18 course of action,customers are expected to experience
19 higher costs in seven out of nine scenarios,right,
20 through 2050?
21 A Two thoughts on that.One is seven out of
22 nine scenarios as the Company has made the assumptions
23 under those,so that's not necessarily the high
24 percentage that it looks like.Second of all,I do not
25 propose that the combined projects not be built.I just
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1 propose that the Commission does not give permission for
2 them to be built at this time,and once they're built,
3 just take a look at them and see what the economics
4 are.
5 Q So you want the projects to be built,you
6 just don't want them to receive a certificate of public
7 convenience and necessity?
8 A I don't either want them to be built or
9 not want them to be built.I think that's the Company's
10 choice.If the Company thinks that their numbers are
11 very valid,if they have faith in those numbers that the
12 customers will be better off and we'll happen to hit one
13 of those seven out of nine scenarios,then the Company
14 should build it.That's up to the Company.I don't
15 think the Company has got that much faith in their
16 numbers or the belief that we're going to end up being
17 better off with the projects.
18 Q Going back to the scenarios,I think we
19 already established that in addition to the nine price
20 policy scenarios that were studied through 2050,the
21 Company also conducted studies through 2036 using the IRP
22 planning horizon;correct?
23 A That's correct.
24 Q So in total,there's 19 studies over --
25 excuse me,18 studies over nine price policy scenarios
CSB REPORTING 1737 YANKEL (X)
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1 over two different time horizons;right?
2 A There are 18 scenarios.I think that
3 certainly the scenarios through 2050 are much more valid
4 because that's the life of the plant,but,also,if you
5 look at the difference between those two groups of
6 scenarios,the '36 versus the '50,in all cases the '36
7 has much higher benefit to the customers than does in the
8 final year 2050,which means that effectively for the
9 next 14 years,the last 14 years,we're losing money.I
10 mean,supposedly we are going to gain a lot of money if
11 the Company is right for the first --up until 2036,but
12 that benefit is going to be going away for the next 14
13 years,so it does not look very favorable.
14 Q Well,and just to be clear,then,of the
15 18 studies that are included,that the Company has
16 performed in this case,customers are better off under 16
17 of those studies;correct?
18 A Correct,but the Company could have
19 produced a whole lot of other studies,you know,some
20 later,some earlier,and we would have had different
21 numbers,different ratios.
22 Q And just to be clear,even in the
23 scenarios,even in the limited low gas case scenarios,
24 where there are net customer costs through 2050,
25 customers would still receive over 1,000 megawatts of new
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1 wind resources and a new transmission line at a steeply
2 discounted cost;correct?
3 A It would be at a cost.
4 Q Less than the cost to build those
5 projects,though;correct?
6 A Less than the cost to build the projects,
7 but still at a negative benefit to the customers,so yes,
8 it's a cost,but the customers are going to be paying,
9 again,return,depreciation,all that.I mean,that's
10 going to be a cost to the customers,but the net impact
11 is that we would pay more than if we had not built the
12 projects.That's the difference that I'm seeing.
13 Q Well,and just to be clear,if the Company
14 builds the transmision line at a later date,it's not
15 going to be as inexpensive as it will be under this
16 scenario;correct?
17 A That's if the Company builds it,the
18 combined projects,yes.It would be cheaper if the
19 combined projects were built today as the Company is
20 proposing than if they waited five years to build it,
21 yes.I mean,that's because of the tax credits.There's
22 no question about that.
23 Q And I just have one more question on this
24 line regarding those tax credits.Something you said in
25 your live testimony this morning was that even though
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1 these projects,the wind projects,will produce zero fuel
2 cost energy,you indicated there's still a lot of costs
3 involved;correct?
4 A Correct.
5 Q If I could just direct your attention to
6 your direct testimony on page 5,on lines 25 and 26 at
7 the bottom of that page,your testimony states,
8 "Basically,the total PTCs amount to almost 75 percent of
9 the cost of the entire project."Do you see that?
10 A Yes,I do see that.
11 Q So effectively,we're getting 75 percent
12 off these projects if they're constructed now that we
13 would not get if they're constructed in a couple of
14 years;right?
15 A Yes,but they can still be constructed now
16 without the Commission issuing an Order in your favor in
17 this case.The Company can still build it.Assuming
18 that those numbers are valid that the Company has
19 calculated,the benefits will be there and we can rate
20 base them two,three years from now.
21 Q All right,just a few more questions.If
22 you could turn to your direct,supplemental direct,
23 testimony,please,the April testimony,and page 2 of
24 that on the very bottom line,19 to 22,and I guess I'll
25 direct your attention specifically to line 21 where you
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1 recommend the Commission put sufficient caps or
2 safeguards on these projects if they're approved.Do you
3 see that testimony?
4 A Yes,I do.
5 Q Now,going back to the Langley Gulch case
6 that we discussed earlier,is it your recollection that
7 Staff proposed a hard cap in that case?
8 A That was 15 years ago.I don't
9 remember.
10 Q All right.Well,here,I'll help you out.
11 If we turn to page 32 of that Order --
12 A Okay.
13 Q --and the first sentence of the first
14 full paragraph at the top of the page says,"Staff
15 believes the Commission should establish an absolute 'not
16 to exceed'amount or hard cap to protect ratepayers."Do
17 you see that?
18 A Yes.
19 Q And then if we turn to page 39 of that
20 Order,the very last sentence in the last full paragraph
21 states,"The Commission declines to adopt the Staff's
22 recommendation to establish an absolute 'not to exceed'
23 amount or hard cap."Do you see that?
24 A Yes,I do,but I don't know what it says
25 in between.
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1 MR.LOWNEY:Fair enough.I have no
2 further questions.Thank you,Mr.Yankel.
3 COMMISSIONER ANDERSON:Mr.Karpen.
4
5 CROSS-EXAMINATION
6
7 BY MR.KARPEN:
8 Q Yes,Mr.Yankel,can you please turn to
9 page 16 of that Order under Load Forecast/Timing?The
10 second full sentence --
11 A Excuse me,I'm a little slow.Okay,I'm
12 there on 16.
13 Q The second full sentence says the primary
14 driver of the need for the resource,according to the
15 Company --
16 A Stop,sorry,I was at the page.
17 Q Page 16.
18 A Now give me the location on the page.
19 Q Under Load Forecast/Timing.
20 A Yes.
21 Q The second full sentence starting with,
22 "The primary."
23 A I see it now.
24 Q It states,"The primary driver of the need
25 for the resource,the Company states,is load growth."
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1 You're familiar with the Company proposal in this case,
2 is it your understanding that there is load growth going
3 on under the proposed projects by the Company here?
4 A There is probably load growth,but I would
5 not call it growth.It's creeping.It may be decreasing
6 at this point in time for the next few years.There's
7 minimal growth taking place at this point in time.
8 Q The justification for this project here is
9 not immediate load growth,is it?
10 A That is correct.
11 MR.KARPEN:I have no further questions
12 for this witness.
13 COMMISSIONER ANDERSON:Thank you.
14 Commissioner Kjellander.
15
16 EXAMINATION
i7
18 BY COMMISSIONER KJELLANDER:
19 Q Mr.Yankel,just a quick question
20 referring to the Exhibit 77 that was given to you,which
21 is the Order from quite a few years back,could you turn
22 to page 48 on that?That's the signature page.Do you
23 see any of those Commissioners sitting here today?
24 A No,I do not.
25 COMMISSIONER KJELLANDER:Thank you.
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1 COMMISSIONER ANDERSON:Mr.Olsen,any
2 redirect?
3 MS.OLSEN:Yes,a couple of questions,
4 Your Honor.
5
6 REDIRECT EXAMINATION
7
8 BY MR.OLSEN:
9 Q Just looking at the Cross Exhibit 77,as
10 counsel pointed out,you participated in that case,
11 didn't you,Mr.Yankel?
12 A Yes,I did.
13 Q Okay,and that was for a combined cycle
14 kind of base load resource;isn't that correct?
15 A That's correct.
16 Q And that has a pretty long lead time for
17 construction?
18 A I don't recall.Actually,I think the
19 lead time on this was more like three years,and let me
20 make a correction on my previous answer.It really
21 wasn't for a base load unit.It was really more for a
22 peaking-type unit.It certainly could serve base load
23 functions,so it could go either way.Since it's been
24 constructed and since the gas prices have changed like
25 they have,it's really turned into much more of a base
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1 load unit than the peaking that it was really thought of
2 as being.
3 Q Okay,but with respect to the timing
4 between the projected need and the decision to build that
5 plant,it was much closer in time,wasn't it,than
6 projected need that the Company's IRP is 2028?
7 A Oh,yes,certainly.Yes,I misunderstood
8 your question,yes.
9 Q Okay.
10 A The need was much more immediate as far as
11 that goes.The timing was about the same as I would
12 think in this case.It was like,say,about three years
13 as far as when the unit would come on-line,but the need
14 for the capacity was much more immediate as opposed to 10
15 years out and/or beyond 10 years out.
16 Q Now,if you're closer in time when you
17 start or ask for permission to acquire the resource and
18 when it's going to be needed,don't you have more
19 certainty as to the known factors that will affect the
20 overall project and its economics?
21 A Yes,but more important,I think,is the
22 fact that it was a capacity need at that time.It wasn't
23 an economic need.It wasn't like this proposal we have
24 here today.It was a need because of growth,that they
25 needed more generation someplace.
CSB REPORTING 1745 YANKEL (ReDi)
208.890.5198 IIPA
1 MS.OLSEN:I have no further questions,
2 Chair Anderson.
3 COMMISSIONER ANDERSON:Thank you,Mr.
4 Olsen.Thank you,Mr.Yankel.
5 THE WITNESS:Thank you.
6 (The witness left the stand.)
7 COMMISSIONER ANDERSON:We'll take a
8 10-minute break.
9 (Recess.)
10 COMMISSIONER ANDERSON:We'll come back to
11 order.We're going to go a little bit out of order right
12 here and we'll continue with Staff in a moment,but we do
13 have one more witness that the Company has,so if you
14 would like to proceed,Mr.Lowney,that would be great.
15 MR.LOWNEY:Thank you.The Company calls
16 Nikki Kobliha.
17
18
19
20
21
22
23
24
25
CSB REPORTING 1746 YANKEL (ReDi)
208.890.5198 IIPA
1 NIKKI KOBLIHA,
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 Ms.Kobliha,could you please state and
10 spell your name for the record?
11 A Yes,Nikki Kobliha,N-i-k-k-i
12 K-o-b-l-i-h-a.
13 Q And how are you employed?
14 A I'm the chief financial officer and
15 treasurer for PacifiCorp.
16 Q And are you the same Nikki Kobliha who
17 filed supplemental direct testimony on January 16th,
18 2018,in this case?
19 A Yes.
20 Q And do you have any additions or
21 corrections that you wish to make to that prefiled
22 testimony today?
23 A No,I do not.
24 Q If I were to ask you the questions that
25 are set forth in that testimony,would your answers be
CSB REPORTING 1747 KOBLIHA (Di)
208.890.5198 Rocky Mountain Power
1 the same?
2 A Yes,they would.
3 MR.LOWNEY:Commissioner Anderson,I
4 would move that Ms.Kobliha's prefiled testimony be
5 spread upon the record as if read.
6 COMMISSIONER ANDERSON:Thank you.
7 Without objection,we will spread Ms.Kobliha's testimony
8 across the record as if read.
9 (The following prefiled supplemental
10 direct testimony of Ms.Nikki Kobliha is spread upon the
11 record.)
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING 1748 KOBLIHA (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 Nikki L.Kobliha and my business
4 address is 825 NE Multnomah Street,Suite 2000,Portland,
5 Oregon 97232.My present position is Vice President,
6 Chief Financial Officer and Treasurer for PacifiCorp.I
7 am testifying on behalf of Rocky Mountain Power
8 ("Company"),a division of PacifiCorp.
9 QUALIFICATIONS
10 Q.Briefly describe your educational and
11 professional background.
12 A.I received a Bachelor of Business
13 Administration with a concentration in Accounting from
14 the University of Portland in 1994.I became a certified
15 public accountant in 1996.I joined the Company in 1997
16 and have taken on roles of increasing responsibility
17 before being appointed Chief Financial Officer in 2015.
18 Q.What are your responsibilities as Vice
19 President,Chief Financial Officer and Treasurer?
20 A.I am responsible for all aspects of the
21 Company's finance,accounting,income tax,internal
22 audit,Securities and Exchange Commission reporting,
23 treasury,credit risk management,pension,and other
24 investment management activities.
25 PURPOSE AND SUMMARY OF TESTIMONY
1749 Kobliha,Di-Supp -1
Rocky Mountain Power
1 Q.What is the purpose of your supplemental direct
2 testimony in this proceeding?
3 A.In my testimony,I support the Company's
4 Application for Certificates of Public Convenience and
5 Necessity and Binding Ratemaking before the Idaho Public
6 Utilities Commission ("Commission")for construction of
7 new wind resources ("Wind Projects")and for construction
8 of the Aeolus-to-Bridger/Anticline line and network
9 upgrades ("Transmission Projects")(collectively,the
10 "Combined Projects").I outline
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16
17
18
19
20
21
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23
24
25
1750 Kobliha,Di-Supp -la
Rocky Mountain Power
1 relevant provisions in the federal income tax reformO2enactedinDecember2017.I confirm that there are no
3 changes to current federal income tax law on production
4 tax credits ("PTCs")which provide significant value to
5 the Combined Projects.
6 Q.Please summarize your testimony.
7 A.In December 2017,the U.S.Congress passed,and
8 the President signed,H.R 1 ("Tax Act"),which included
9 significant federal income tax reforms.The passage of
10 the Tax Act resolved any risk that federal tax reform
11 posed to the Combined Projects.The Tax Act sets a new
12 corporate income tax rate,now incorporated in the
13 Company's updated economic analysis presented by Company
14 witness Mr.Rick T.Link.It also confirms the continued
15 availability of PTCs for the Combined Projects,from
16 which much of their economic benefit is derived.The
17 enactment of the Tax Act therefore resolves the concerns
18 on this issue since the impacts are now known and
19 incorporated in the economic analysis.
20 SUPPLEMENTAL DIRECT TESTIMONY
21 Q.When was the Tax Act enacted?
22 A.The Tax Act was signed into law by the
23 President on December 22,2017.
24 Q.When does the Tax Act become effective?
25 A.The Tax Act generally becomes effective for
1751 Kobliha,Di-Supp -2
Rocky Mountain Power
1 years beginning after December 31,2017.
2 Q.Does the Tax Act reduce the Company's federal
3 income tax rate?
4 A.Yes,the Tax Act reduces the Company's federal
5 income tax rate from 35 percent to 21 percent.
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25
1752 Kobliha,Di-Supp -2a
Rocky Mountain Power
1 Q.Is there a difference between the Company's
2 federal statutory income tax rate and effective tax rate
3 under the Tax Act?
4 A.No.
5 Q.Does the reduction in the corporate tax rate
6 directly affect the value of PTCs?
7 A.No.The reduction in the corporate income tax
8 rate does not directly impact the value of the PTCs.It
9 does,however,impact the tax gross-up value of the PTCs
10 to customers.
11 Q.Does the Tax Act change any aspect of federal
12 income tax law related to PTCs?
13 A.No.There were no modifications to the federal
14 income tax code or any Internal Revenue Service ("IRS")
15 guidance relating to the PTCs.
16 Q.Please describe how a PTC is generated.
17 A.The Internal Revenue Code ("IRC")provides that
18 a wind facility will generate a PTC equal to an
19 inflation-adjusted 1.5 cents per kilowatt hour of
20 electricity that is produced and sold to a third-party
21 for a period of 10 years beginning on the date the
22 facility is placed in service for income tax purposes.1
23 The current inflation-adjusted PTC rate for electricity
24 generated in 2017 is 2.4 cents per kilowatt hour.2
25 Q.Under current income tax law,the PTC is being
1753 Kobliha,Di-Supp -3
Rocky Mountain Power
1 phased out.Please explain the phase-out process.
2 A.The Protecting Americans from Tax Hikes Act of
3 2015 ("PATH Act")was signed into law on December 18,
4 2015,and retroactively extended and phased out the PTC
5 for wind facilities that began construction before
6 January 1,2020.For a wind facility that began
7 construction before January 1,2017,the credit generated
8 by the wind facility is a full 100 percent of the PTC.
9 For a wind facility that begins construction in 2017,the
10 /
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16
17
18
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20
21
22
23
24 1 IRC section 45(a).
2 IRS Notice 2017-33.
25
1754 Kobliha,Di-Supp -3a
Rocky Mountain Power
1 credit is reduced by 20 percent (i.e.,the facilityO2receives80percentofthefullPTC).For a wind facility
3 that begins construction in 2018,the credit is reduced
4 by 40 percent (i.e.,the facility receives 60 percent of
5 the full PTC).For a wind facility that begins
6 construction in 2019,the credit is reduced by 60 percent
7 (i.e.,the facility receives 40 percent of the full
8 PTC).3 No PTC is available for a wind facility that
9 begins construction after December 31,2019.
10 Q.When does "construction"begin for a wind
11 facility?
12 A.IRS Notice 2013-29 provides a taxpayer with two
13 methods to establish that construction of a wind facility
14 has begun.First,the taxpayer can begin physical work of
15 a significant nature.Physical work can include both
16 on-site and off-site work,either performed by the
17 taxpayer or by another person subject to a binding
18 contract.
19 Second,a taxpayer can pay or incur five
20 percent or more of the eventual total cost of the
21 qualified wind facility.4 This is known as the
22 five-percent safe harbor.The Company is using the
23 five-percent safe-harbor method to qualify for 100
24 percent of the PTC for the benchmark resource selected in
25 the final shortlist.In addition to the requirement that
1755 Kobliha,Di-Supp -4
Rocky Mountain Power
1 the wind facility begin construction before January 1,
2 2017,to qualify for 100 percent of the PTC,the wind
3 facility must also satisfy the continuity-of-construction
4 requirement
5 Q.Please explain the continuity-of-construction
6 requirement.
7 A.The wind facility must be under continuous
8 construction from the time physical construction begins
9 until the wind facility is placed in service.S Whether a
10 taxpayer
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16
17
18
19
20
21
22
23
24 3 IRC section 42(b)(5).
3 IRS Notice 2013-29 Section 5.01.
25 3 IRS Notice 2016-31 Section 4.
1756 Kobliha,Di-Supp -4a
Rocky Mountain Power
1 satisfies the continuity-of-construction requirement is
2 determined based on the relevant facts and circumstances
3 surrounding the timing of the physical work to be
4 performed on the wind facility.6 The IRS has issued
5 limited guidance on what facts and circumstances might be
6 considered to meet this requirement.For example,the IRS
7 has provided a list of non-exclusive "excusable"
8 disruptions and delays deemed to be beyond the control of
9 the taxpayer and therefore acceptable reasons that would
10 support the taxpayer's contention that it has maintained
11 a continuous program of construction.These acceptable
12 delays include weather-caused delays,permit delays
13 outside of the control of the taxpayer,and supply
14 shortages,among others.7
15 The IRS has,however,also created a
16 continuity-of-construction safe harbor (the "calendar
17 safe harbor").8 If a taxpayer places a facility in
18 service by end of a calendar year that is not more than
19 four calendar years after the calendar year during which
20 construction of the wind facility began,the facility
21 will satisfy the continuity-of-construction requirement
22 by virtue of the calendar safe harbor.9 Accordingly,if
23 construction of a wind facility began in December 2016,
24 the facility will meet the continuity-of-construction
25 requirement as long as the facility is placed in service
1757 Kobliha,Di-Supp -5
Rocky Mountain Power
1 by December 31,2020.
2 The Company plans to have the Wind Projects
3 placed in service by December 31,2020,and therefore,
4 the Company will qualify for 100 percent of the PTCs
5 under the four-year calendar safe harbor.
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12
13
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18
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22
23 6 IRS Notice 2016-31 Section 4.02(1).
7 IRS Notice 2016-31 Section 4.06(2).
24 6 IRS Notice 2016-31;IRS Notice 2017-4.
25
9 IRS Notice 2016-31 Section 3.
1758 Kobliha,Di-Supp -5a
Rocky Mountain Power
1 Q.If the Transmission Projects are not completed
2 by December 31,2020,can the Wind Projects still qualify
3 for the PTCs?
4 A.Yes.As discussed by Company witness Mr.Rick
5 A.Vail in his rebuttal testimony,the Wind Projects
6 would still qualify if the Transmission Projects have
7 facilitated synchronization to the transmission grid and
8 commissioning of individual wind turbines in accordance
9 with IRS guidance.In Private Letter Ruling ("PLR")
10 20033403,the IRS ruled that a wind turbine has been
11 placed in service for the purposes of PTC qualification
12 if:(1)the turbine has all necessary operating permits
13 and licenses;(2)the turbine has been synchronized to
14 the power grid;(3)the critical tests for the components
15 of the wind turbine have been completed;(4)the wind
16 turbine has been placed in the control of the taxpayer by
17 the contractor;(5)the taxpayer has sold electricity
18 that has been produced by the wind turbine;and (6)the
19 wind turbine is putting power onto the grid on a regular
20 basis.This IRS guidance applies even if the wind project
21 is not producing transmission-level electricity due to a
22 delay in a transmission project and has not been deemed
23 to be under commercial operation by a regulatory
24 commission.A PLR may not be relied on as precedent by
25 other taxpayers;however,it is indicative of the IRS
1759 Kobliha,Di-Supp -6RockyMountainPower
1 position on certain matters.
2 Q.Are there any other provisions of the Tax Act
3 that affect the Combined Projects?
4 A.Yes.There are two other impacts associated
5 with the reduction in the corporate income tax rate.A
6 reduction to the corporate income tax rate reduces the
7 tax gross-up,lowering the Company's overall rate of
8 return on the Combined Projects.The lower tax rate also
9 reduces the accumulated deferred income tax liability
10 related to the use of
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25
1760 Kobliha,Di-Supp -6a
Rocky Mountain Power
1 Modified Accelerated Cost Recovery System ("MACRS")
2 accelerated depreciation for the five-year tax life of
3 the Wind Projects,which will increase the net rate-base
4 balance.
5 Bonus depreciation rules have also changed.
6 Under prior income tax law,wind projects placed in
7 service in 2019 by the Company would have received
8 30-percent bonus depreciation.Wind projects placed in
9 service in 2020 would have received no bonus
10 depreciation.The new tax reform legislation generally
11 provides that regulated utilities such as the Company
12 will not be allowed to use bonus depreciation on projects
13 placed in service after September 27,2017.The Wind
14 Projects,however,remain subject to the five-year MACRS
15 accelerated depreciation.The impacts of the reduction in
16 the corporate income tax rate and the elimination of
17 bonus deprecation for regulated utilities has been fully
18 reflected in the updated economic analysis prepared by
19 Mr.Link.
20 Q.Does the reduction in the Company's federal
21 income tax rate make the Combined Projects uneconomic?
22 A.No,as demonstrated in Mr.Link's updated
23 economic analysis of the Combined Projects.
24 Q.At this point,do you foresee any future tax
25 reform legislation that will materially impact the
1761 Kobliha,Di-Supp -7
Rocky Mountain Power
1 economics of the Combined Projects?
2 A.No.
3 Q.Does this conclude your supplemental direct
4 testimony?
5 A.Yes.
6
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1762 Kobliha,Di-Supp -7a
Rocky Mountain Power
1 (The following proceedings were had in
2 open hearing.)
3 MR.LOWNEY:Ms.Kobliha is available for
4 cross-examination or Commissioner questions.
5 COMMISSIONER ANDERSON:Thank you.Let's
6 begin with Monsanto.
7 MR.BUDGE:No questions.
8 COMMISSIONER ANDERSON:Mr.Williams.
9 MR.WILLIAMS:No questions.
10 COMMISSIONER ANDERSON:Mr.Olsen.
11 MR.OLSEN:No questions,Chair.
12 MR.KARPEN:No questions from the Staff.
13 COMMISSIONER ANDERSON:No redirect.
14 MR.LOWNEY:No redirect.Thank you.
15 COMMISSIONER ANDERSON:Thank you very
16 much.
17 THE WITNESS:Thank you.
18 COMMISSIONER ANDERSON:Thank you for
19 making the trip here.
20 THE WITNESS:No problem.
21 (The witness left the stand.)
22 COMMISSIONER ANDERSON:We'll return back
23 to Staff.
24 MR.KARPEN:Thank you,Commissioner
25 Anderson.Staff calls Staff expert Michael Eldred.
CSB REPORTING 1763 KOBLIHA
208.890.5198 Rocky Mountain Power
1 MICHAEL ELDRED,O 2 produced as a witness at the instance of the Staff,
3 having been first duly sworn to tell the truth,was
4 examined and testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR.KARPEN:
9 Q Hi,good morning.
10 A Good morning.
11 Q Can you please state your name and spell
12 your last name for the record?
13 A Michael Eldred,E-l-d-r-e-d.
14 Q Can you please tell the Commissioners how
15 you're employed?
16 A I'm a utilities analyst at the Idaho
17 Public Utilities Commission.
18 Q Are you the same Michael Eldred that filed
19 testimony in this matter?
20 A Yes,I am.
21 Q Do you have any corrections to make to
22 that testimony?
23 A Yes,I do.I believe we're handing out
24 corrected pages.On page 16 of my supplemental testimony
25 on line 2,the confidential number there,I made a
CSB REPORTING 1764 ELDRED (Di)
208.890.5198 Staff
1 correction and on page 17,the Table 4,I corrected that,
2 and these are errors that correct calculations that Mr.
3 Link identified in his testimony.
4 Q Do you have any additions to make to your
5 testimony?
6 A Yes.I've also provided a confidential
7 Exhibit No.104 and this is an updated Table 4 that
8 provides a breakeven analysis without Uinta,which is
9 what we agreed to in the stipulation.
10 Q Thank you.Do you have any other
11 corrections or additions to make to your testimony?
12 A No,I do not.
13 MR.KARPEN:With that,I move that
14 Mr.Eldred's testimony and associated exhibits be spread
15 upon the record as if read.
16 COMMISSIONER ANDERSON:Without objection,
17 we will spread Mr.Eldred's testimony and exhibits across
18 the record as if read.
19 (Staff Exhibit Nos.101 -104 were
20 admitted into evidence.)
21 (The following prefiled supplemental
22 testimony of Mr.Michael Eldred is spread upon the
23 record.)
24
25
CSB REPORTING 1765 ELDRED (Di)
208.890.5198 Staff
1 Q.Please state your name and business address forO2therecord.
3 A.My name is Michael Eldred.My business address
4 is 472 W.Washington,Boise,Idaho 83702.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a Utilities Analyst in the Utilities
8 Division.
9 Q.What is your educational and experience
10 background?
11 A.I graduated,with honors,from Boise State
12 University with a bachelor's degree in Mechanical
13 Engineering in 2014 and a master's degree in Business
14 Administration in 2016.I have worked with the
15 Commission since 2017.During my time with the
16 Commission,I have conducted analysis on electricity and
17 natural gas prices in general rate cases,integrated
18 resource plans,prudence reviews of capital investments,
19 and cost recovery mechanisms.In addition,I have
20 attended the Institute of Public Utilities Annual
21 Regulatory Studies Program at Michigan State University,
22 and also attended Michigan State University's NARUC
23 Utility Rate School.
24 Q.What is the purpose of your testimony in this
O 25 proceeding?
A.The purpose of my testimony in this case is to
CASE NO.PAC-E-17-07 1766 ELDRED,M.(Supp)1
04/11/18 STAFF
1 provide direct testimony on PacifiCorp's new wind and
2 transmission combined project's Request for Proposal(RFP)
3 supplemental filings.My testimony supplements the
4 direct testimony of Staff witness Rick Keller's direct
5 testimony.Mr.Keller provided Staff's position on the
6 prudence of the proposed investment for the new wind and
7 transmission based on preliminary information and the
8 Company's benchmark wind projects and not the final
9 projects selected through the RFP.
10 Q.Please summarize your testimony.
11 A.The results of the new wind RFP,known as 2017R
12 RFP,continue to show net customer benefits for the
13 Company's proposal,but additional concerns and risks
14 have been identified during the review process.The
15 concerns and risks identified are:
16 1.A change in the Company's present value
17 revenue requirement differential (PVRR(d))
18 analysis methodology.Staff believes the
19 approach overstates the amount of net benefits
20 of the proposal;
21 2.The combined wind and transmission project
22 (Combined Projects)may not be the least-cost
23 least-risk when compared to the solar
24 generation projects submitted in response to
25 the Company's solar RFP;
CASE NO.PAC-E-17-07 1767 ELDRED,M.(Supp)2
04/11/18 STAFF
1 3.Additional future cost risk to the
2 transmission portion of the project;
3 4.Additional future cost risk in the wind
4 generation portion of the project;
5 5.Schedule delay risk due to the potential
6 need for a supplemental Environmental Impact
7 Statement (EIS).
8 Q.What is your concern with the change in the
9 Company's PVRR(d)analysis methodology?
10 A.The Company uses nominal Production Tax Credits
11 (PTCs)in its levelized analysis extending out to 2036
12 and terminal values for the projects.The approach
13 overstates net benefits and creates a bias toward
14 Company-owned wind and the Company's proposal.In my
15 testimony,"levelized analysis"will refer to the
16 economic analysis covering the 20-year planning timeframe
17 out to 2036."Nominal analysis"will refer to the
18 economic analysis covering the 30-year useful life of the
19 wind projects out to 2050.
20 Q.Please provide more detail on the use of
21 nominal PTCs in the levelized analysis.
22 A.The Company chose to create a hybrid analysis
23 that mixes levelized cost with nominal benefits in its
24 supplemental filings.This creates an unfair comparison
O 25 between alternatives.In the Company's RFP supplemental
filings,the treatment of PTCs in the levelized analysis
CASE NO.PAC-E-17-07 1768 ELDRED,M.(Supp)3
04/11/18 STAFF
1 was changed from the Company's initial filing.In the
2 initial filing,PTCs were levelized,which is consistent
3 with how the Company has handled PTCs in the past,
4 including the 2017 IRP where the Company's proposal was
5 first identified.The reason for levelizing values is to
6 create a fair comparison when trying to make a selection
7 between alternatives with different lives and in-service
8 dates.
9 The Company states that the application of PTCs
10 on a nominal basis,"better reflects how the federal PTC
11 benefits for these bids will flow through to customers."1
12 This statement is true,but the Company's nominal
13 analysis already reflects how benefits,and costs would
14 be recovered in rates.The Company's hybrid analysis
15 does not accurately reflect how capital costs are
16 captured in rates.When capital costs are put into rates,
17 they are front loaded,starting with a large value and
18 decrease each year with depreciation.The Company's
19 hybrid methodology mixes nominal and levelized values
20 which results in an analysis that does not produce a fair
21 comparison between resources,and does not accurately
22 reflect how rates are recovered.
23 Q.How does the use of nominal PTCs impact the
24 results of the levelized analysis?
25 A.The cost of the project would increase by
CASE NO.PAC-E-17-07 1769 ELDRED,M.(Supp)4
04/11/18 STAFF
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CASE NO.PAC-E-17-07 1770 ELDRED,M.(Supp)4A
04/11/18 STAFF
1 approximately $2142 million if the Company used levelized
2 PTCs instead of nominal PTCs as they did in their hybrid
3 analysis.Table 1 provides the PVRR(d)results for the
4 Company's hybrid levelized analysis with nominal PTCs and
5 the Company's levelized analysis adjusted for levelized
6 PTCs for all price-policy scenarios.The Company's
7 hybrid levelized results using nominal PTCs shows benefit
8 in all price-policy scenarios.The adjusted results
9 using levelized PTCs shows benefit in 7 of the 9
10 price-policy scenarios.Table 1 shows how the treatment
11 of PTCs impacts the results of the Company's hybrid
12 levelized analysis:overstating the net benefits.
13 Table 1-Nominal vs Levelized PTC Treatment in PVRR(d)
14 Analysis
15 (Benefit)/Cost ($million)
16
C bpany
Levelized Levelized Company
Price-Policy Scenario Levelized PTC Analysis Nominal
with Analysis17AnalysisAdjustmentAdjustment(Nom.PTC)(Nom.PTC)
18 Low Gas,Zero CO2 (150)214 64 184
19 Low Gas,Medium CO2 (179)214 35 127
Low Gas,High CO2 (337)214 (123)(147)
20 Medium Gas,Zero CO2 (319)214 (105)(92)
Medium Gas,Medium CO2 (357)214 (143)(167)21 Medium Gas,High CO2 (448)214 (234)(304)
22 High Gas,Zero CO2 (568)214 (354)(448)
High Gas,Medium CO2 (603)214 (389)(449)
2 3 High Gas,High CO2 (694)214 (480)(635)
24
O 25 2 Approximation of $214 million provided by the Company in IPUC Data
Request Response 75 .
CASE NO.PAC-E-17-07 1771 ELDRED,M.(Supp)504/11/18 STAFF
1 Included in Table 1 is the PVRR(d)results for
2 the Company's nominal 30-year analysis using nominal
3 PTCs.Staff believes this provides the most reasonable
4 method to show how the Combined Projects would impact
5 rates.The nominal results are included to show that the
6 adjusted levelized analysis is similar with regard to
7 showing net benefits in 7 of the 9 price-policy
8 scenarios.The fact that the adjusted levelized analysis
9 is similar to the nominal analysis helps provide more
10 evidence that the Company's hybrid analysis overstates
11 the net benefits.
12 Q.Does the use of nominal PTCs create other
13 concerns?
14 A.Yes,an additional concern is the use of
15 nominal PTCs in the levelized analysis creates a bias
16 toward Company-owned wind.Both Oregon and Utah
17 independent evaluators (IE)expressed concern with the
18 use of nominal PTCs in the levelized analysis and how
19 such an approach favors Build Transfer Agreements (BTA)
20 bids over Power Purchase Agreements (PPA)bids in the
21 2017R RFP.The Oregon IE requested the Company run a
22 sensitivity analysis to address these concerns.The
23 Company completed the sensitivity analysis and the
24 results produced a portfolio with more PPA bids that
O 25 generated more benefits over the life of the project when
compared to the Company's selected
CASE NO.PAC-E-17-07 1772 ELDRED,M.(Supp)6
04/11/18 STAFF
1 portfolio.3 In the Oregon IE final report,the IE
2 concluded,"the Company's modeling method,which
3 levelized cost but not the benefits of PTC acquisition,
4 could have biased the bid selection to less favorable
5 offers."4 A copy of the Oregon IE final report is
6 included as Staff Exhibit No.103.
7 Q.How much additional benefit did Company-owned
8 wind in the final short list receive through the use of
9 nominal PTCs?
10 A.The Company's choice to mix methodologies of
11 nominal and levelized values in their hybrid analysis
12 created a bias toward company-owned wind by introducing
13 approximately $214 million worth of additional PTC
14 benefits into the levelized analysis for the 2017R RFP
15 final short list.Graph 1 shows the year by year PTC
16 value for the nominal and levelized PTC treatment in the
17 levelized analysis from 2017-2036 for the final RFP short
18 list.The net present value (NPV)of the nominal PTC
19 treatment is (redacted)million but the levelized PTC
20 treatment NPV is (redacted)million.This creates $214
21 million worth of additional PTC benefits in the Company's
22 hybrid analysis.
23 3 This is based on the analysis which is surmarized in the Oregon IE
final report identified as,"The Independent Evaluator's final report
24 on PacifiCorp's 2017R Request for Proposals",Public Version,
February 16,2018,page 31.
25 4 The Independent Evaluator's final report on PacifiCorp's 2017R
Request for Proposals,Public Version,February 16,2018,page 6.
CASE NO.PAC-E-17-07 1773 ELDRED,M.(Supp)7
04/11/18 STAFF
--,1
IIIb 2
3
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8
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"'-13O14
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17
18 Q.Please explain your issue with terminal value.
19 A.I believe that the terminal value introduced
20 into the PVRR(d)analysis is speculative and potentially
21 overvalues Company-owned wind.In the Company's RFP
22 supplemental filings,the terminal value includes the
23 value of development rights,transmission assets (i.e.
24 network upgrades),and non-transmission infrastructure
25 (i.e.roads)
CASE NO.PAC-E-17-07 1774 ELDRED,M.(Supp)8
04/11/18 STAFF
1 in 2050.5 Terminal value was not included in theO2Company's initial filing.
3 Staff believes terminal value is speculative
4 because the estimation is predicting a value 33 years
5 into the future and it assumes the assets will still be
6 needed.There are numerous future uncertainties such as
7 technological advancements and obsolescence that could
8 impact the estimated terminal value in the 33-year
9 timeframe.The further out in time,the more difficult
10 it is to accurately estimate the value of an asset,
11 especially one that has to be re-purposed.To take
12 advantage of a terminal value that far into the future,
13 the assets assigned would need to be utilized for some
14 unknown purpose.If they were utilized,there is good
15 probability there would be a cost associated that was not
16 accounted for in the Company's estimate.
17 Q.What is the impact of using terminal value?
18 A.The NPV of the terminal value in the nominal
19 analysis is (redacted)million.When comparing this
20 value to the cost of the project,the value is small.
21 However,when comparing the cost to the medium gas,
22 medium CO2 price-
23
5 Information provided by the Company in IPUC Data Request Response
24 78,sub response (k)
6 Value from Company witness Link confidential work papers,fileO25"EV2020 Workpapers Second Supp Results Summary File -VOM adjusted
CONF
CASE NO.PAC-E-17-07 1775 ELDRED,M.(Supp)9
04/11/18 STAFF
1 policy scenario with benefits of $1677 million,the
2 terminal value makes up approximately (redacted)of the
3 project benefits.If the terminal value was excluded
4 from the nominal analysis,the benefits for the medium
5 gas,medium CO2 scenario would be reduced to (redacted)
6 million.
7 Q.Please explain how the Combined Projects may
8 not be least-cost least-risk when compared to the solar
9 generation projects?
10 A.The Company's solar RFP,known as 2017S RFP,
11 creates additional uncertainty whether or not the
12 Combined Projects are the least-cost least-risk option
13 for a capacity deficit that occurs 10 years in the
14 future.The results of the 2017S RFP
15
16 (redacted)
17
18 I also believe that the solar projects are
19 lower risk than the Combined Projects for three reasons:
20 the solar projects have lower capital project expense
21 than the Combined Projects;the construction of a new
22 transmission line,which has high cost-overrun potential,
23 is not required;and all solar bids are PPAs so the
24 developer takes on the risk for the projects.Table 2
25 shows the nominal analysis comparison between the
CASE NO.PAC-E-17-07 1776 ELDRED,M.(Supp)10
04/11/18 STAFF
1 Combined Projects and solar as an alternative.It only
2 includes two price-
3 /
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24 7 Value from CORRECTED Link,Di-Second Supp,page 17,CORRECTED Table
25
3-ss.
CASE NO.PAC-E-17-07 1777 ELDRED,M.(Supp)10a
04/11/18 STAFF
1 policy scenarios since the 2017S RFP analysis only
2 studied two scenarios for the solar only portfolio.
3 Based on the nominal analysis in the 2017S RFP,a solar
4 only portfolio has the potential
5 (redacted)
6
7 Table 2-Solar vs Wind Nominal PVRR(d)
8 (Benefit)/Cost ($million)
9 Price-Policy Scenario Solar Wind Change in
10 PVRR (d)PVRR (d)PVRR (d)
11 Low Gas,Zero CO2 (redacted)(redacted)(redacted)
12 Medium Gas,Medium CO2 (redacted)redacted)(redacted)
13
14 Q.Does the Company's 2017S RFP levelized analysis
15 have the same validity issues as identified in the
16 Company's hybrid levelized analysis?
17 A.Yes.The levelized results of the 2017S RFP
18 shows greater benefits for the Combined Projects when
19 compared to solar,but it uses the Company's flawed
20 hybrid levelized analysis methodology.As discussed
21 earlier in my testimony,the Company's hybrid analysis
22 overstates net benefits and is not the best comparison
23 between alternatives.The nominal analysis should be the
24 analysis used when comparing how alternatives would
25 impact rates.
CASE NO.PAC-E-17-07 1778 ELDRED,M.(Supp)11
04/11/18 STAFF
1 The Company confirms this statement:"Using nominal
2 revenue requirements is the best representation of what
3 the actual revenue requirement costs and benefits would
4 be if the Combined Projects were placed in base rates
5 during the same period."8
6 The continued use of the Company's flawed
7 hybrid levelized analysis in the 2017S RFP makes the
8 Combined Projects appear more beneficial than solar by
9 introducing additional benefits from nominal PTC
10 treatment and by shifting a greater amount of project
11 cost outside of the modeling timeframe.The additional
12 benefits from the nominal PTC treatment in the levelized
13 analysis is the same $214 million I discussed previously.
14 When projects with a large capital cost such as the
15 Combined Projects are put into a modeling timeframe that
16 only capture half of the project life,a large amount of
17 the project cost is shifted outside of the modeling
18 timeframe due to levelization.The solar PPAs in the
19 2017S RFP have a lower project cost and a more uniform
20 yearly cost so less of the project cost is shifted
21 outside of the modeling timeframe.
22 There is approximately three times the amount
23 of project cost that is shifted outside of the modeling
24 timeframe for the Combined Projects as compared to the
25 solar projects in the Company's inaccurate hybrid
CASE NO.PAC-E-17-07 1779 ELDRED,M.(Supp)12
04/11/18 STAFF
1 analysis.
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25 6 Response to IPUC Data Request 80.
CASE NO.PAC-E-17-07 1780 ELDRED,M.(Supp)12a
04/11/18 STAFF
--1 Table 3 illustrates this effect.It shows that 36%of
2 the nominal project costs are excluded from the Company's
3 Combined Projects levelized analysis as compared to only
4 10%for the solar projects.
5
6 Table 3 -20 Year Project Cost NPV Comparison
($million)
7 hvelized 20 year Difference %Change
8 Project Project in Project in Project
Cost NPV Cost CostNPV
9 Combined Projects
10 Solar ¯
11
12 The Comppny decided to not select any of the 20175 RFP
"13 bids due to expected cost reductions in the future and toO14avoidthecurrentriskpremiumassociatedwithtariffand
15 tax reform uncertainties.The Company stated it plans to
16 reassess the solar option in the 2019 IRP.Staff agrees
17 that the solar option needs more study,but believes the
18 2017S RFP results create additional uncertainty whether
19 or not the Combined Projects are the least-cost
20 least-risk option.
21 Q.Please explain the additional future cost risk
22 to the transmission portion of the project.
23 A.In addition to the cost risk to the
24 transmission project identified in Mr.Keller's
25 testimony,new
CASE NO.PAC-E-17-07 1781 ELDRED,M.(Supp)13
04/11/18 STAFF
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25 9 Information from confidential attachment IPUC 76-1.
CASE NO.PAC-E-17-07 1782 ELDRED,M.(Supp)13a
04/11/18 STAFF
1 transmission cost risks have been identified related to
2 mineral development,surface use agreements,and
3 abandoned mines along the transmission route.Andrew
4 Wurdack on behalf of Anadarko Land Corporation has
5 brought this information before the Public Service
6 Commission of Wyoming (Wyoming Commission)in his
7 supplemental response testimony.10 Mr.Wurdack's
8 testimony states,"the language used in the FEIS11
9 clearly intended that future mineral development would be
10 protected."12 He also requested that the commission
11 adopt a stipulation that the Company enter into surface
12 use agreement with split-estate owners providing for
13 active and future mineral development.13
14 Abandoned mines create a safety and cost risk
15 to the transmission line.Mr.Wurdack identified several
16 more abandoned mines which were previously not identified
17 or disclosed by the Company that are in the path of the
18 proposed transmission line.14
19 The information provided in Mr.Wurdack's
20 testimony creates significant additional future
21
10 Docket No.20000-520-EA-17 (Record No.14781)Supplemental
22 Response Testimony.
11 Final Environmental Impact Statement
23 12 Page 8,lines 14-15,Andrew Wurdack Supplemental Response
Testimony,Docket No.20000-520-EA-17 (Record No.14781)
24 13 Page 8,lines 15-17,Andrew Wurdack Supplemental Response
Testimony,Docket No.20000-520-EA-17 (Record No.14781)
25 14 Page 9,Andrew Wurdack Supplemental Response Testimony,Docket
No.20000-520-EA-17 (Record No.14781)
CASE NO.PAC-E-17-07 1783 ELDRED,M.(Supp)14
04/11/18 STAFF
1 transmission cost risk.
2 Q.Please explain the future cost risk in the wind
3 generation portion of the Combined Projects.
4 A.Mineral development rights of split-estate
5 owners creates cost risk in the wind projects."Anadarko
6 remains concerned that the Company may attempt to use the
7 wind power projects to block all mineral development
8 leading to costly litigation."15 Anadarko has interest
9 in the wind projects because they own mineral rights
10 under the private land sections of some of the wind
11 projects.Anadarko has estimated the total to be at
12 least 58,82016 acres of split-estate lands.As a
13 solution,Anadarko is recommending the Wyoming Commission
14 adopt a condition to secure agreements to address surface
15 use and recognition of rights of split-estate owners.17
16 These previously unidentified or undisclosed issues
17 increase the risk of additional costs not previously
18 identified in the Company's ecomomic analysis.
19 Q.How much of an increase in total project
20 capital cost results in the Combined Projects providing
21 no economic benefit?
22
15 Page 20,lines 9-11,Andrew Wurdack Supplemental Response
23 Testimony,Docket No.20000-520-EA-17 (Record No.1478)
16 Page 11,line 15,Andrew Wurdack Supplemental Response Testimony,
24 Docket No.20000-520-EA-17 (Record No.1478)
17 Page 20,lines 13-16,Andrew Wurdack Supplemental Response
25 Testimony,Docket No.20000-520-EA-17 (Record No.1478))
CASE NO.PAC-E-17-07 1784 ELDRED,M.(Supp)15
04/11/18 STAFF
1 A.The amount of benefits compared to the overall
2 capital cost is very small.A cost overrun of only
3 (redacted)above the Company's proposed capital cost will
4 eliminate any net benefits for the Combined Projects.
5 This is based on the nominal analysis of the medium gas
6 and medium CO2 price-policy scenario.Given that
7 customers are already taking on the risk that two of the
8 nine price-policy scenarios are showing negative net
9 benefits,the Company will need to execute the project
10 very close to its estimated costs and realize all the
11 benefits assumed in its PVRR(d)analysis in order for it
12 to be worthwhile for customers.
13 In Table 4,I have provided the amount above or
14 below budget the Company would have to achieve to
15 break-even for each price-policy scenario.
16
17
18
19
20
21
22
23
24
25
CASE NO.PAC-E-17-07 1785 ELDRED,M.(Supp)16
04/11/18 STAFF
(Ili 2
3 Table 4-Capital Cost Breakeven Values for
4 Nominal PVRR(d)Analysis
($million)
5 Breakeven $Breakeven %
.Capital Cost Capital Cost
6 Price-Policy Scenario Increase/Increase/
(Decrease)-Decrease
Low Gas,Zero CO2
Low Gas,Medium CO2
Low Gas,High CO2
9 Medium Gas,Zero CO2
Medium Gas,Medium CO210MediumGas,High CO2
11 High Gas,Zero CO2
High Gas,Medium CO2
12 High Gas,High CO2
13O14
15 Q.Please explain the schedule delay risk due to
16 the potential need for a supplemental EIS.
17 A.A supplemental EIS may be required since the
18 transmission line and the wind project are now dependent
19 upon one another.The initial 2013 Federal Environmental
20 Impact Study (FEIS)assumed the transmission line was
21 independent of wind projects.Anadarko believes "that a
22 supplement to the 2013 FEIS is necessary to disclose and
23 analyze the new connected actions under National
24 Environmental Policy Act (NEPA)."18 In addition,
O 25 Anadarko is requesting the Company ask the Bureau of Land
CASE NO.PAC-E-17-07 1786 ELDRED,M.(Supp)17
04/11/18 STAFF
1 Management
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24 3-6 Page 28,lines 6-7,Andrew Wurdack Supplemental Response
25
Testimony,Docket No.20000-520-EA-17 (Record No.1478)
CASE NO.PAC-E-17-07 1787 ELDRED,M.(Supp)17a
04/11/18 STAFF
1 (BLM)to prepare a supplemental EIS.19 Mr.Wurdack's
2 opinion is that a supplemental EIS is unlikely to delay
3 the Combined Projects.20 However,I believe a
4 supplemental EIS could condense the already compressed
5 schedule and lead to an increase in cost to finish the
6 project by the end of 2020,which is required to qualify
7 for the full amount of PTC benefits.
8 Q.Does this conclude your supplemental testimony
9 in this proceeding?
10 A.Yes,it does.
11
12
13
14
15
16
17
18
19
20
21
22
23 19 Page 28,lines 7-9,Andrew Wurdack Supplemental Response
Testimony,Docket No.20000-520-EA-17 (Record No.1478)
24 20 Page 27,lines 20,Andrew Wurdack Supplemental Response Testimony,
25
Docket No.20000-520-EA-17 (Record No.1478)
CASE NO.PAC-E-17-07 1788 ELDRED,M.(Supp)18
04/11/18 STAFF
1 (The following proceedings were had in
2 open hearing.)
3 MR.KARPEN:With that,I tender him for
4 cross-examination.
5 COMMISSIONER ANDERSON:Thank you.Mr.
6 Budge.
7 MR.BUDGE:Thank you,Mr.Chairman.
8
9 CROSS-EXAMINATION
10
11 BY MR.BUDGE:
12 Q Good morning,Mr.Eldred.
13 A Good morning.
14 Q Would you please turn to page 10 of your
15 supplemental testimony and I'm looking at your testimony
16 that begins on line 16.
17 A Yes.
18 Q If I understand correctly your testimony
19 here,you express concern that the combined projects are
20 not least cost,least risk when compared with the solar
21 PPA.
22 A Yes,for the Staff,we believe this brings
23 into question whether it's a least cost,least risk.
24 Q Is it true that that particular concern
25 has not been resolved by way of the Staff-Company
CSB REPORTING 1789 ELDRED (X)
208.890.5198 Staff
1 settlement stipulation?
2 A I think the stipulation helps reduce many
3 of those risks.I don't know that it's 100 percent
4 resolved.
5 Q Would you --you have a table that you
6 prepared on the following page 11 of your testimony,
7 Table 2,and I want to simply inquire of the Company
8 counsel whether or not any of the figures there are still
9 confidential or not.I thought those were all in the
10 public record,but before I inquire,I wanted to ask.
11 (Pause in proceedings.)
12 MR.BUDGE:While they're making that
13 inquiry,I'll ask questions without talking specific
14 numbers just in the interest of moving forward.
15 COMMISSIONER ANDERSON:That's fine.
16 Q BY MR.BUDGE:It may not be necessary to
17 get into the numbers,but if you'd look at your Table 2
18 on page 11,I wanted to know whether you had updated that
19 particular table to reflect the terms of the settlement
20 stipulation,and I think the only change that might be
21 relevant is whether or not the Uinta project is in or
22 out.
23 A Yeah,with that one,I couldn't myself
24 accurately change that.My updated Table 4 that I
25 changed it for,Mr.Link provided that.I would have a
CSB REPORTING 1790 ELDRED (X)
208.890.5198 Staff
1 tough time adjusting that,because this had some other
2 adjustments to it that wasn't in the filing.
3 Q Mr.Link,I think,made some adjustments
4 in his settlement testimony,his testimony that was
5 attached to the settlement stipulation,and I was
6 wondering if you had that available or if it could be
7 made available.
8 A I believe I have his testimony here.
9 Q That was an attachment to the settlement
10 stipulation and I believe --
11 A Actually,I'll need a copy of it,sorry.
12 Q You have it?
13 A No,I'll need a copy of it.
14 (Mr.Karpen approached the witness.)
15 THE WITNESS:What page?
16 Q BY MR.BUDGE:I'm referring to page 8 of
17 Mr.Link's testimony in support of the settlement and
18 look at the table at the top,Table 3-ST.
19 A Yes.
20 Q It has the estimated impact of removing
21 Uinta.
22 A Yes.
23 Q If you look at the middle column,the
24 bottom numbers under modeled result without Uinta,
25 there's some numbers there,the low gas,zero CO2 and
CSB REPORTING 1791 ELDRED (X)
208.890.5198 Staff
1 medium gas,medium CO2,do you see those numbers?
2 A Yes --
3 Q Without testifying from the numbers if
4 they --I'll inquire of counsel,are they still
5 confidential or not?
6 MS.McDOWELL:[Inaudible.]
7 MR.LOWNEY:I can just repeat really
8 quickly,the numbers on Table 2 of Mr.Eldred's testimony
9 are not confidential.
10 MS.McDOWELL:Thank you for inquiring.I
11 can also verify that the numbers on Table 3-ST are not
12 confidential.
13 MR.BUDGE:Okay,thank you.
14 Q BY MR.BUDGE:With that in mind,Mr.
15 Eldred,I think if you took the numbers that are in Table
16 3-ST with the modeled result without Uinta,under the low
17 gas,zero CO2 scenario,that is a $154 million number,
18 and then under medium gas,medium CO2,it's a negative
19 $174 million number,do you see that?
20 A Yes.
21 Q Would those be the numbers that you would
22 have to utilize in order to update the Table 2 on page 11
23 of your testimony?
24 A So Table 2,that wind PVRR(d)was taken
25 from the solar sensitivity that had some adjustments to
CSB REPORTING 1792 ELDRED (X)
208.890.5198 Staff
1 it that is different than this one.I think Mr.Link
2 could speak to that more,but I don't believe I could
3 just transfer those over,because the numbers I used
4 there was from a solar one and they made some adjustments
5 to that,so those numbers aren't exactly comparable.I
6 don't believe I could just place them in there.They
7 might be close,but there's some adjustment.
8 Q It would take some effort to make that
9 calculation?
10 A Yes.
11 Q Let me ask the question,then,this way:
12 Based on what you can see from Mr.Link's testimony,
13 would you agree that even with Uinta removed,the solar
14 continues to show hundreds of millions of dollars in
15 greater benefits --
16 MR.KARPEN:I'm going to object to this
17 testimony.Our witness has already responded that this
18 in the purview of Mr.Link and he's unable to calculate
19 these numbers.
20 MR.BUDGE:I'm not asking him to
21 calculate an exact number.If he can tell by looking at
22 the Link numbers here and comparing them to what is in
23 his Table 2,I think the witness should be able to
24 testify if even with Uinta being removed,is the solar
25 project still hundreds of millions of dollars least cost
CSB REPORTING 1793 ELDRED (X)
208.890.5198 Staff
1 than the wind projects,if you can make that estimate.
2 THE WITNESS:Based on these,I can.One
3 thing I will say to that,in the medium,medium,they're
4 still very close.They're comparable.The solar from
5 this Table 2 shows it has a slight advantage if we go in
6 the low gas scenario.
7 Q BY MR.BUDGE:When you say there's a
8 slight advantage,you mean the solar project would be
9 least cost?
10 A In that specific scenario,that's what
11 this table is showing,correct.
12 Q And if I understand your testimony with
13 respect to the solar being least risk,is that in the
14 context of the solar project being a PPA without any
15 capital costs involved?
16 A Yes,and I think on page 10 where we're
17 discussing earlier those three points,those are points
18 that I feel that the solar project is lower risk,yeah.
19 Q And the lack of any transmission component
20 as well --
21 A Yes.
22 Q --contributes to that conclusion?
23 A Yes.
24 MR.BUDGE:No further questions.Thank
25 you,Mr.Eldred.
CSB REPORTING 1794 ELDRED ()C
208.890.5198 Staff
1 COMMISSIONER ANDERSON:Thank you,Mr.
2 Budge.Mr.Williams.
3 MR.WILLIAMS:No questions.Mr.Budge
4 asked mine.Thank you.
5 COMMISSIONER ANDERSON:Mr.Olsen.
6 MR.OLSEN:No questions.
7 COMMISSIONER ANDERSON:Mr.Lowney,the
8 Company?
9 MS.McDOWELL:Good morning,thank you.
10
11 CROSS-EXAMINATION
12
13 BY MS.McDOWELL:
14 Q Good morning,Mr.Eldred.
15 A Good morning.
16 Q So the only remaining issues between the
17 Company and Staff are whether the Commission should
18 establish an absolute not to exceed cost cap in this
19 case;is that correct?
20 A Yes.
21 Q So based on that,I'm just going to limit
22 my questions to the last five pages of your testimony,
23 pages 14 through 19,where you discuss project risk.
24 A Yes.
25 Q And I'd like to begin on page 14,if I
CSB REPORTING 1795 ELDRED (X)
208.890.5198 Staff
1 may,if you could turn to that page,and really,on pages
2 14 and 15,beginning at the bottom of page 14,you talk
3 about some future cost risks you've identified with
4 respect to the transmision project.Do you see that?
5 A Yes.
6 Q Up on page 15,you cite the testimony of
7 Andrew Wurdack on behalf of Anadarko in the Wyoming CPCN
8 proceeding related to this project?
9 A Yes.
10 Q Do you have that?So I assume you have
11 some familiarity with that docket since you cited the
12 testimony of Mr.Wurdack from that docket.
13 A Yes.
14 Q So your testimony was filed on April 11th,
15 2018,in this docket;correct?
16 A That's correct.
17 Q And the next day you're aware,aren't you,
18 that the Wyoming Commission issued a conditional CPCN in
19 that docket?
20 A Yes,I'm aware of that.
21 Q And isn't it also true that on that day,
22 April 12th,Anadarko filed a notice to withdraw from that
23 CPCN proceeding?
24 A That's correct.I followed that hearing.
25 Q And they did before they offered that
CSB REPORTING 1796 ELDRED ()C
208.890.5198 Staff
1 testimony of Mr.Wurdack;correct?
2 A Sorry,can you say that again?
3 Q So Anadarko never presented the testimony
4 of Mr.Wurdack in that case,because they withdrew before
5 presenting any part of their case in that docket;
6 correct?
7 A That's correct.
8 Q Now,are you familiar with the
9 supplemental testimony of Mr.Teply on this point?
10 A Yes,I am.
11 Q And do you recall that he testified that
12 the Company and Anadarko reached a settlement agreement
13 that mitigated Anadarko's concerns on the issues raised
14 in Mr.Wurdack's testimony?
15 A Yes,I saw that.I'm also not aware of
16 what was in that to see if it protected all of these
17 risks.
18 Q But are you aware of Mr.Teply's testimony
19 that that resolution did not have any material impact on
20 the Company's underlying economic analysis,in other
21 words,it was within budget?
22 A Yes,I read his testimony.
23 Q And are you also aware from your review of
24 that case that the Company settled all of the mineral
25 rights issues or at least settled with all of the other
CSB REPORTING 1797 ELDRED DC
208.890.5198 Staff
1 parties in that case that raised the split-estate mineral
2 rights issues that you address in your testimony?
3 A Yes,that's correct.
4 Q And wouldn't you agree that the resolution
5 of the mineral rights and split-estate issues in the
6 Wyoming CPCN docket mitigates the concern and the risks
7 that you cite in your testimony?
8 A I will.One thing I wanted to explain
9 about my testimony,these are additional ones into what
10 Mr.Keller identified.These are adding on to those and
11 these were just additional ones and not necessarily the
12 major ones.They were ones that came from the filing.
13 Q I understand,but wouldn't you agree that
14 the resolution of those issues within the Wyoming CPCN
15 addresses the risks that you flagged in your testimony?
16 A With respect to the two that you
17 mentioned.I don't know if it addressed,for example,
18 the abandoned mines.I don't know what you guys reached
19 in the agreement,so I can't answer that it fully
20 mitigated them.It reduced it,it looks like,yes.
21 Q So now your testimony on page 18,line 13,
22 addressed a potential scheduling delay risk.Do you see
23 that?
24 A Yeah.Is that page 17?
25 Q It's page 18 of my --on my --are you
CSB REPORTING 1798 ELDRED (X)
208.890.5198 Staff
1 with me there?
2 A Yeah,I believe,"Please explain the
3 schedule delay risk due to the potential need for a
4 supplemental EIS."
5 Q Right,and that risk you cited related to
6 the potential that Mr.Wurdack raised in his testimony
7 that was ultimately not submitted in that docket around
8 the potential need for a supplemental federal
9 environmental impact study.Do you recall that?
10 A Yes,I do.
11 Q And are you familiar with the exhibit to
12 Mr.Teply's testimony that indicates in response to this
13 testimony that BLM has opined that no supplemental EIS
14 will be required?
15 A Yes,I am.
16 Q So that also addresses that potential
17 risk,doesn't it?
18 A Yes,I believe so.
19 Q Now,I want to ask you a question about
20 your updated breakeven analysis,so that's your
21 confidential Exhibit 104 and just to be clear about what
22 this table shows,you're basically showing that after the
23 removal of Uinta and based on the Company's updated
24 economic analysis,the level of cost increase that could
25 occur,that would still provide the benefits that are in
CSB REPORTING 1799 ELDRED (X)
208.890.5198 Staff
1 that column;is that correct?
2 A Increase or decrease to break even.
3 Q So I just wanted to ask you a hypothetical
4 question.Let's say conditions in the high gas,zero CO2
5 case prevailed and let's say that in the same
6 hypothetical that due to circumstances outside of the
7 Company's control,the Company acted prudently,but
8 exceeded its cost estimate by,let's say,$100 million,
9 so do you have me on that hypothetical?
10 A Yes.
11 Q So under Staff's proposal,even though
12 customers would be receiving hundreds of millions of
13 dollars of benefits,the Company would be denied approval
14 of that $100 million of prudently-incurred costs;
15 correct?
16 A Yes,if the Commission approved a hard cap
17 and made that decision.
18 Q But doesn't that hypothetical illustrate
19 the problem of imposing an absolute not to exceed amount
20 in advance,in a vacuum,without understanding the
21 circumstances of the case?
22 A It is a hypothetical,but the reason that
23 we do this,all these price policy scenarios,is because
24 there's a potential for all of these happening.I
25 believe the Company agrees that there's a potential for
CSB REPORTING 1800 ELDRED (X)
208.890.5198 Staff
1 all of these to happen,so in that case,it would limit
2 the Company from being able to recover those costs,
3 you're correct.
4 Q So doesn't a hard cap imposed at this
5 stage of the project eliminate the Commission's
6 discretion to determine a fair and reasonable outcome in
7 a scenario like that in the future?
8 A Sorry,can you repeat that one more time?
9 Q So doesn't a hard cap imposed at this
10 stage of the project eliminate the Commission's
11 discretion to determine a fair and reasonable outcome in
12 a scenario like the one we just described?There would
13 be only one outcome,which is the Company would not
14 recover its costs;correct?
15 MR.KARPEN:I'm going to object to that
16 characterization on a limit on the Commission.I believe
17 it's a limit on the Company's ability to apply for those
18 overages,not a limit on the Commission's ability.
19 MS.McDOWELL:My question stands.
20 COMMISSIONER ANDERSON:Well,I think
21 you're asking for a decision,an opinion that only the
22 three of us when we deliberate are going to be able to
23 do.I don't think that I'm going to hold him to have to
24 answer that particular question.
25 MS.McDOWELL:Fair enough.That's all I
CSB REPORTING 1801 ELDRED (X)
208.890.5198 Staff
1 have.
2 COMMISSIONER ANDERSON:Thank you.Let's
3 see where we're at.Commissioners?Is there any
4 redirect?
5 COMMISSIONER RAPER:Me real quick.
6 COMMISSIONER ANDERSON:Oh,sorry.
7 COMMISSIONER RAPER:Sorry,I was slow.
8
9 EXAMINATION
10
11 BY COMMISSIONER RAPER:
12 Q Hi,welcome.I'm trying to get straight
13 in my head your testimony versus the settlement stip and
14 those things,especially in relation to the solar PPA,so
15 I may ask things outside the scope of your testimony and
16 I'll challenge Mr.Karpen to object to that as he needs.
17 A Okay.
18 MR.KARPEN:I won't.
19 Q BY COMMISSIONER RAPER:The economic
20 versus reliability issue that we've been talking about
21 for the last day-and-a-half --
22 A Yeah.
23 Q --does the need versus want,let's call
24 it,play into where the risk should fall,in your
25 opinion?Does that make sense?
CSB REPORTING 1802 ELDRED (Com)
208.890.5198 Staff
1 A Yes.In my opinion,since this project is
2 not needed for reliability,the Company should hold a
3 little bit more of the risk.I understand in past ones
4 where there's more of a reliability need,capacity
5 identified-near-term need,the customers should be,I
6 guess,more considered equal weight.Since this is more
7 of an economic project,we feel more in the want or the
8 discretionary want,an economic project,the Gompany
9 should hold a little bit more of the risk.
10 What we're asking for as Staff with the
11 cap at cost estimates,the customers are still at risk.
12 It's not like we're limiting everything.We still have
13 the risks,for example,in the two lower cases,and we
14 still have to pay for those costs,so that's why we feel
15 that there should be a shift from that.The customers
16 aren't held limitless with what we're requesting.We're
17 not going as far as to try to eliminate that.We do see
18 it's reasonable that the customers should take on the
19 risk for this,because from the Company's economic
20 analysis,it shows that it can provide benefits in the
21 majority of the cases.
22 Q So how do you feel about Mr.Yankel's
23 testimony regarding let the Company bear the risk and
24 build,because,I mean,Staff is asking for a hard cap,
25 there's definite risk to the Company in this Commission
CSB REPORTING 1803 ELDRED (Com)
208.890.5198 Staff
1 imposing a hard cap,I think everyone can appreciate that
2 for what it is --
3 A Yes.
4 Q --so what about the reverse scenario?
5 Based on your risk assessment and where that balance lies
6 on an economic opportunity versus a reliability issue
7 that they're trying to address,how do you feel about
8 Mr.Yankel's suggestion that we let them build it and
9 then they will come and ask for recovery?
10 A It's something,I mean,we viewed and
11 considered,also.I think probably Mr.Louis,our policy
12 one,would be the best to answer that.
13 COMMISSIONER RAPER:Fair enough.I'll
14 let you stop with that.Thank you.
15 THE WITNESS:All right.
16 COMMISSIONER ANDERSON:Mr.Karpen,
17 redirect?
18 MR.KARPEN:Yes.
19
20 REDIRECT EXAMINATION
21
22 BY MR.KARPEN:
23 Q The Company had asked you about the
24 settlement that it reached with Anadarko,did you
25 participate in those settlement conversations?
CSB REPORTING 1804 ELDRED (ReDi)
208.890.5198 Staff
1 A No,I did not.
2 Q Are you familiar with the terms of that
3 settlement?
4 A No,I'm not.
5 Q So is it fair to say you don't know if
6 that settlement mitigates any of the risks from the --to
7 the customers other than the Company's own assertion?
8 A Yes,that's correct.I might add to that,
9 what the company Anadarko brought up in that,that's
10 something that could be applied to other private
11 landowners that they haven't got right of way,so the
12 issues that they bring up apply to them and other private
13 landowners could potentially bring up.Anadarko was a
14 bigger company and the resources that it needs to go into
15 those is,in my opinion,greater,so some of those other
16 landowners maybe didn't,but they could have similar
17 issues,so I think it still has those issues.
18 Q Thank you.I'd like you to refer to your
19 Exhibit No.104.It's the updated breakeven table,if
20 you will.I'd like to pose to you a hypothetical.Let's
21 say in the future,get out your crystal ball,we are in a
22 situation similar to what we're in today,a low gas,zero
23 CO2 future,and the Company has exceeded its estimates,
24 cost estimates,by,let's say,$100 million,under your
25 analysis if there was no hard cap imposed,would that not
CSB REPORTING 1805 ELDRED (ReDi)
208.890.5198 Staff
1 put the customers at risk for $291 million?
2 A Yes,that's correct.
3 MR.KARPEN:Thank you.I have no further
4 questions for this witness.
5 COMMISSIONER ANDERSON:Thank you,Mr.
6 Karpen.Thank you for your testimony.
7 THE WITNESS:Thank you.
8 (The witness left the stand.)
9 COMMISSIONER ANDERSON:You may call your
10 next witness.
11 MR.KARPEN:Staff calls Company --excuse
12 me,Staff calls Staff witness Rick Keller.
13
14 RICHARD KELLER,
15 produced as a witness at the instance of the Staff,
16 having been first duly sworn to tell the truth,was
17 examined and testified as follows:
18
19 DIRECT EXAMINATION
20
21 BY MR.KARPEN:
22 Q Good morning,Mr.Keller.
23 A Good morning.
24 Q Can you please state your name and spell
25 your last name for the record?
CSB REPORTING 1806 KELLER (Di)
208.890.5198 Staff
1 A Yes,my name is Richard Keller.My last
2 name is spelled K-e-l-1-e-r.
3 Q Can you please state for the record how
4 you're employed?
5 A Yes,I'm employed by the Idaho Public
6 Utilities Commission as an engineer for Staff.
7 Q Are you the same Rick --excuse me,
8 Richard Keller who provided testimony in this matter?
9 A Yes.Direct testimony,yes.
10 Q Do you have any corrections or additions
11 to make to that testimony?
12 A No,other than to point out that
13 subsequent to my testimony,the corporate tax change has
14 been implemented and,also,my testimony with respect to
15 the project is based off the benchmark projects.
16 MR.KARPEN:Thank you.With that,I'll
17 move that the testimony and associated exhibits be spread
18 upon the record as if read live.
19 COMMISSIONER ANDERSON:Without objection,
20 we'll spread Mr.Keller's testimony across the record and
21 exhibits.
22 (The following prefiled direct testimony
23 of Mr.Richard Keller is spread upon the record.)
24
25
CSB REPORTING 1807 KELLER (Di)
208.890.5198 Staff
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Richard Keller.My business address
4 is 472 West Washington Street,Boise,Idaho 83702.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a Staff Engineer.
8 Q.What is your educational and experience
9 background?
10 A.I received my Bachelor of Science degree,with
11 Honors,in Mechanical Engineering from the University of
12 Wyoming in 1994.I have been registered as a
13 professional engineer in Idaho since 2002.In addition
14 to my formal education,I attended the Electric Utility
15 Basic Practical Regulatory program offered by New Mexico
16 State University's Center for Public Utilities,and also
17 attended Michigan State University's Institute of Public
18 Utilities Electricity Grid School.
19 I started my engineering career working for the
20 Kiewit Industrial Company as an estimator,and progressed
21 into the positions of field engineer and mechanical lead
22 engineer.As an engineer,I was involved in the
23 construction of large industrial projects including
24 Amtrak's Northeast Corridor Electrification,a northeast
25 segment of Level 3 Communications long haul fiber optic
CASE NO.PAC-E-17-07 1808 KELLER,R.(Di)1
11/20/17 STAFF
1 network,and initial support of a combined cycle power
2 plant in Washington State.
3 In 2001,I began working for POWER Engineers
4 Inc.,holding positions as mechanical engineer,lead
5 mechanical engineer,and project engineer.My roles
6 included engineering,design,project oversight,and the
7 sealing of project documents as a registered professional
8 engineer responsible for mechanical engineering and
9 design.Several projects that I was directly involved
10 with during this period include reciprocating engine
11 generating plants;simple cycle and combined cycle power
12 plants;and retrofits to existing coal fired power
13 plants.
14 I began work at the Idaho Public Utilities
15 Commission in 2015.My work responsibilities include a
16 variety of electric and water utility cases including
17 integrated resource plans,depreciation,purchased gas
18 and power cost adjustment,prudence review of
19 investments,line extension,and general rate cases
20 looking specifically into capital investment.
21 Q.What is the purpose of your testimony in this
22 proceeding?
23 A.The purpose of my testimony in this case is to
24 review and provide Staff's position regarding the
25 Company's analysis of the Application for determining the
CASE NO.PAC-E-17-07 1809 KELLER,R.(Di)2
11/20/17 STAFF
1 prudence of a proposed investment in new wind and
2 transmission.
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CASE NO.PAC-E-17-07 1810 KELLER,R.(Di)2a
11/20/17 STAFF
1 In addition,I address whether or not the
2 Company's proposal for the project is a least-cost and
3 least-risk alternative for meeting a system capacity
4 deficit projected to occur in the year 2028.
5 Q.Could you please summarize your testimony?
6 A.Yes.Although not needed to meet system
7 capacity requirements until 2028,I believe that the new
8 wind and transmission project as presented by the Company
9 could be the least cost,least risk alternative to meet
10 future resource needs over the next 30 years.I believe
11 the assumptions used by the Company in its economic
12 analysis fall within a reasonable range and support the
13 Company's proposal.
14 The Company completed an analysis to determine
15 the net benefit difference between the proposed project,
16 and a baseline across nine alternative futures with
17 different natural gas forecasts and CO2 prices.
18 Results for seven of nine alternative future
19 scenarios show a net benefit to customers when compared
20 to the baseline alternative.Assuming there is an equal
21 probability that each scenario will occur,the expected
22 value of the net benefit difference is about $191 million
23 in favor of the project (See Exhibit No.101).
24 A significant portion of economic benefit
25 associated with the new wind and transmission project
CASE NO.PAC-E-17-07 1811 KELLER,R.(Di)3
11/20/17 STAFF
1 occurs as a result of the Company's reliance on capturing
2 100 percent of the federal wind Production Tax Credits
3 (PTCs).Without receiving the full benefit from the
4 PTCs,the project economics would not be beneficial to
56customers.I
maintain that risks and uncertainties can be
7 categorized into one of two groups:those the Company can
8 control and those it cannot.Project risks that the
9 Company can control include overall project costs and
10 timely project completion.Project risks that the
11 Company cannot control include changes in corporate tax
12 rate,future natural gas prices,and CO2 mitigation
13 costs.
14 I believe the Company must protect customers
15 from risks that it can control and look to mitigate those
16 risks that are beyond its control,primarily with respect
17 to corporate tax rate changes.
18 Successful completion of the new wind and
19 transmission project by the Company is subject to
20 significant risk because the project has a "time-limited
21 opportunity"tied to qualifying for the $24 per
22 megawatt-hour PTC benefit by year end 2020.Completing
23 the project by the deadline is within the Company's
24 control.
25 A potential change to the corporate tax rate as
CASE NO.PAC-E-17-07 1812 KELLER,R.(Di)4
11/20/17 STAFF
1 proposed in legislation currently being considered by
2 Congress could make the project uneconomical before
3 construction even begins.
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CASE NO.PAC-E-17-07 1813 KELLER,R.(Di)4a
11/20/17 STAFF
1 To reduce risk whether within or outside the Company's
2 control,the Company should continually assess the
3 liability posed by the various risks to reduce,limit,or
4 prevent negative impacts on customers.
5 Q.Please provide a summary of the Company's
6 proposed project.
7 A.The Company proposes to construct or acquire
8 new Wyoming wind resources with a total capacity of 860
9 megawatts.The Company has submitted a request for
10 proposal seeking competitive bids.The Company plans to
11 bid directly into this proposal with four projects of its
12 own that the Company identifies as benchmark resources.
13 The Company also proposes construction of a
14 140-mile segment of the Energy Gateway West transmission
15 project from Aeolus-to-Anticline in southern Wyoming.
16 This 500 kV transmission line will include upgrades and
17 improved interconnection to several sub-stations along
18 the route.
19 The Company presents this project as a
20 "time-limited opportunity"to obtain cost-effective
21 generation and construct the necessary transmission
22 facilities with minimal impact to customer rates.The
23 Company states that without the new PTC qualified wind,
24 the transmission project would not be economic.
25 Q.What is your perspective of the Company's need
for this project?
CASE NO.PAC-E-17-07 1814 KELLER,R.(Di)5
11/20/17 STAFF
1 A.The 2017 IRP indicates that the Company does
2 not require added system capacity until 2028.The
3 Company's conclusion is based on its 13 percent
4 planning-reserve margin,assumed coal unit retirements,
5 incremental energy efficiency savings,and available
6 wholesale-power market purchases.
7 Aside from this lack of current need,if the
8 Company delivers the project as described,the new wind
9 and transmission project would provide benefit to
10 customers by providing lower cost energy to the system,
11 provide improved transmission system reliability,and
12 would add diversity to the Company's generating
13 resources.
14 I believe that in implementing the new wind and
15 transmission project there are numerous and significant
16 risks.If not properly mitigated,the result could be a
17 project that is not beneficial to customers.
18 Q.What is your opinion regarding the Company's
19 method for evaluating the economics of the project?
20 A.I believe the Company's method for economically
21 evaluating the project is reasonable and in several ways
22 conservative.The Company compared the relative system
23 net present value revenue requirement difference
24 (PVRR(d))between operating with the project and
25 operating without the project over the investment's
CASE NO.PAC-E-17-07 1815 KELLER,R.(Di)6
11/20/17 STAFF
1 30-year useful life.The Company also calculated the
2 PVRR(d)across nine different
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CASE NO.PAC-E-17-07 1816 KELLER,R.(Di)6a
11/20/17 STAFF
1 alternative futures including different combinations of
2 low,medium,and high natural gas price forecasts,and
3 zero,medium,and high carbon dioxide prices to
4 understand their economic impact.
5 The analysis and assumptions used in this case
6 were based on the Company's 2017 IRP.The project is
7 also included in the Company's 2017 IRP preferred
8 portfolio as a result of its analysis.
9 Q.What is your assessment of the Company's
10 methodology used to determine the difference in net
11 benefits between the project and the baseline?
12 A.I believe the factors selected and the
13 methodology used to evaluate the cost effectiveness and
14 risk in the Company's analysis are reasonable.The
15 Company's approach is similar to the methodology used for
16 the 2017 IRP.
17 There are two factors that make the Company's
18 results conservative.First,the Company used 300
19 megawatts of low cost PTC qualified wind generation as a
20 proxy to utilize 240 megawatts of existing transmission
21 capacity in its baseline alternative.In actuality there
22 are PURPA qualified facilities which have priority for
23 interconnection.Replacing the 300 megawatts of wind
24 proxy resources with PURPA qualified generation would
25 increase the revenue requirements in the baseline because
the proxy
CASE NO.PAC-E-17-07 1817 KELLER,R.(Di)7
11/20/17 STAFF
1 wind receives PTC benefits making the costs much lower
2 than the PURPA projects.This would result in a more
3 beneficial PVRR(d)for the new wind and transmission
4 case.
5 Second,the Company did not reflect any benefit
6 for the sale of RECs associated with new wind generation.
7 The Company indicates the present value benefit to the
8 project through 2050 would increase by $34 million (Link
9 direct testimony,p 4)for every dollar assigned to the
10 incremental RECs generated from new wind.When
11 considering the adjustments for PURPA wind and the value
12 of RECs,all nine scenarios would show a positive
13 economic benefit to customers.
14 Q.What is the benefit of the Production Tax
15 Credit and why is it important to project economics?
16 A.The Company's analysis shows the present value
17 benefit of the PTCs for the project through 2050 is $795
18 million (Link,Exhibit 25).The amount is conditioned on
19 recovering 100 percent of the PTC benefit.The PTC value
20 is one of the most important factors for providing
21 economic benefit to customers.If the project is not
22 operational by December 31,2020,each year of delay
23 reduces the PTC benefit by 20 percent.A reduction of
24 the benefit by just one year or 20 percent equates to a
25 present value reduction of the PTC benefit by $159
CASE NO.PAC-E-17-07 1818 KELLER,R.(Di)8
11/20/17 STAFF
1 million.This reduction would make the project
2 uneconomic ($137 million PVRR(d)benefit
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CASE NO.PAC-E-17-07 1819 KELLER,R.(Di)8a
11/20/17 STAFF
1 minus $159 million reduction to PTC benefit)costing
2 customers $22 million based on the medium natural gas and
3 CO2 pricing forecasts which are used to support the
4 Company's Application.
5 Q.What are the project risks that prevent the
6 Company from realizing full PTC benefits?
7 A.In order for the Company to be eligible for the
8 full PTC benefit,each project must meet specific
9 requirements prior to January 1,2017.Beginning
10 construction is the most visible way to meet eligibility
11 requirements.Alternatively,the Company has relied on a
12 five-percent Safe Harbor option in order to satisfy the
13 requirements.The Company has both contracted directly
14 with a wind turbine manufacturer and a developer for the
15 Company's four proposed benchmark resource sites to
16 capture the Safe Harbor.However,any change to the
17 current interpretation of the five-percent Safe Harbor
18 rule may put PTCs at risk.
19 Based on the current status of the Company's
20 benchmark sites,the projects will need to be operational
21 by December 31,2020.Although the Company seems
22 confident it can meet this date,there are numerous steps
23 that need to be completed.The Company indicates that
24 the transmission line is on the critical path for meeting
25 the operational deadline.In order to complete the
CASE NO.PAC-E-17-07 1820 KELLER,R.(Di)9
11/20/17 STAFF
1 transmission portion of the project,the Company still
2 needs to secure the remaining federal permits,Wyoming
3 approval of a CPCN,and secure the remaining transmission
4 rights of way.
5 Securing the remaining wind turbine equipment
6 and the potential for construction delays could add even
7 more risk to capturing full PTC benefits from the
8 project.
9 Q.Is the amount of wind energy used to support
10 the Company's economic analysis reasonable?
11 A.Yes,I believe the amount of wind energy
12 assumed in the Company's Application is reasonable for
13 the four benchmark resource sites.
14 I reviewed several factors tied to the
15 reliability of wind turbine generators,wind turbine
16 efficiency,and the average wind velocity for the area
17 considered for the Company's proposed benchmark sites.
18 Industry data 1,2 indicates the mechanical
19 availability of modern wind turbines to be almost 97
20 percent.This value represents the percent of time a
21 wind turbine generator is available to generate whether
22 or not
23
1 GE's Onshore Wind Services -GE Renewable Energy
24 https://www.gerenewableenergy.com/content/dam/gepower-renewables/
global/en_US/downloads/brochures/wind-onshore-services-gea31819b.pdf
25 2 Siemens -Harnessing opportunities for better results
https://www.siemens.com/global/en/home/markets/wind/service.html
CASE NO.PAC-E-17-07 1821 KELLER,R.(Di)10
11/20/17 STAFF
1 the wind is blowing.This high availability can be
2 attributed to the continued advancement in wind turbine
3 technology,industry requirements for wind turbine
4 generator reliability,and mechanical operational data
5 from the large installed base of wind turbines placed
6 into service in recent years.If the Company's wind
7 turbine generators are properly operated and maintained,
8 this equipment should perform equivalent to those
9 currently operated within the industry.
10 Based on information from the National
11 Renewable Energy Laboratory (NREL)for south central
12 Wyoming,the area (at a specified hub height 80 meters
13 above the surface elevation)has an average annual wind
14 speed near or above 10 meters per second.NREL also
15 provides wind related capacity factors for some of the
16 existing sites within the area.These capacity factors
17 are consistent with values used by the Company for its
18 economic analysis.
19 Q.Should the Company be held responsible for
20 mitigating the risk associated with qualifying for full
21 PTC benefits?
22 A.I believe the Company is responsible for
23 mitigating the risks in order to qualify for full PTC
24 benefits because the factors of success are within the
25 Company's control.In order to satisfy the Safe Harbor
CASE NO.PAC-E-17-07 1822 KELLER,R.(Di)11
11/20/17 STAFF
1 requirements,the Company is responsible for insuring
2 that
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CASE NO.PAC-E-17-07 1823 KELLER,R.(Di)lla
11/20/17 STAFF
1 five percent of the capital cost were expended prior to
2 the year 2017.Furthermore,the Company is responsible
3 for meeting a schedule the Company developed to insure
4 the new wind and the transmission are operational by
5 December 31,2020.
6 Q.Have the Company's actions demonstrated its
7 commitment to achieving full PTC benefits?
8 A.Yes.It's evident the Company understands the
9 project economics rely on achieving full PTC benefits and
10 considers the risk acceptable given its application to
11 the Commission requesting a CPCN.The Company's
12 Application is supported by significant analysis related
13 to the economics of the project and likewise has
14 committed to a compressed schedule for completing the
15 project prior to the December 31,2020 PTC deadline.In
16 addition,the Company has committed significant capital
17 in order to qualify for the five-percent Safe Harbor
18 requirements.
19 The Company is also in the midst of completing
20 a request for proposal for PTC qualified wind projects,
21 which the Company is bidding into based on its benchmark
22 resources.In total,these actions reflect the Company's
23 commitment to an expected successful outcome of the
24 project.
25 Q.Are there any other considerations related to
meeting the December 31,2020 deadline?
CASE NO.PAC-E-17-07 1824 KELLER,R.(Di)12
11/20/17 STAFF
1 A.In order to capture the full PTC benefit,the
2 Company faces significant pressure to meet the December
3 31,2020 deadline.Any delay to the project will serve
4 to further compress the schedule.This is especially
5 true for any delays to the construction of the
6 transmission line,given that the transmission line is on
7 the critical path for full operation of the project.The
8 combination of hard deadlines and project uncertainties
9 can lead to delays which can only be remedied by
10 increasing cost,authorizing overtime,and adding
11 incremental resources.This risk will adversely affect
12 capital cost and cost effectiveness to customers if not
13 mitigated.
14 Q.How much additional transmission capital
15 investment makes the project no longer economically
16 beneficial to customers?
17 A.Based on the Company's model,if the $681
18 million capital investment for the transmission portion
19 of the project increases by 24.8 percent,the project is
20 no longer beneficial to customers.This analysis is
21 based on the medium natural gas and CO2 pricing forecasts
22 which are used to support the Company's Application.
23 Q.Are there factors that are outside of the
24 Company's control?
25 A.Yes.There are several,but three risk factors
pose the greatest risk to the economic viability of the
CASE NO.PAC-E-17-07 1825 KELLER,R.(Di)13
11/20/17 STAFF
1 project:changes to the corporate tax rate,the price of
2 natural gas,and changes to the price of CO2.
3 Q.Can you please characterize the risk created by
4 changes in the corporate tax rate and how it can be
5 mitigated?
6 A.If corporate income tax rates are lowered from
7 the current rates assumed in the Company's economic
8 analysis,there will be a significant negative impact for
9 two reasons:1)a lower income tax rate could
10 significantly reduce the PTC benefit amount,and 2)the
11 Company has little control of the circumstances other
12 than exiting the project if the new rates cause the
13 project to be uneconomic.Corporate tax reduction is
14 currently a high priority in Congress.
15 The Senate and House currently have proposed
16 legislation to reduce the corporate tax rate somewhere in
17 the 20 percent to 25 percent range.If this occurs,it
18 would significantly reduce the PVRR(d)of the project
19 primarily by reducing the after-tax benefit of the PTC.
20 For example,if the corporate tax rate was reduced from
21 current levels to 20 percent,the net present value of
22 the PTC's over the ten-year eligibility period would be
23 reduced from $795 million to $627 million making the
24 project much less economically viable.
25 There is a good chance the outlook for reducing
CASE NO.PAC-E-17-07 1826 KELLER,R.(Di)14
11/20/17 STAFF
1 the corporate income tax will be known before the Company
2 commits to significant capital expenditure.To mitigate
3 this risk,the Company needs to monitor corporate tax
4 rate status.If tax rates are reduced,the Company
5 should be required to make a filing with the Commission
6 for additional review before proceeding with the project.
7 Q.Can you please characterize the risk created by
8 natural gas prices and how it can be mitigated?
9 A.Yes.The risk is that actual natural gas
10 prices turn out to be lower than those assumed in the
11 Company's analysis.This makes the next best
12 alternative,which includes gas-fired generation,more
13 beneficial in comparison to the proposed project.While
14 natural gas prices can have a large impact on project
15 economics,the Company used a reasonable range of natural
16 gas price forecasts and are somewhat conservative with
17 respect to what future natural gas prices will actually
18 be.This conservative natural gas price assumption will
19 likely result in greater project benefits than those
20 estimated by the Company.For example,the Company
21 evaluated the project using low,medium,and high natural
22 gas price forecasts.The Company's PVRR(d)results for
23 the different forecasts,keeping the CO2 price constant
24 to isolate the effects of natural gas,are reflected in
25 the table below.
CASE NO.PAC-E-17-07 1827 KELLER,R.(Di)15
11/20/17 STAFF
1 Modeled Scenario PVRR(d)
2 Low Gas,Medium CO2 $93 million
3 Medium Gas,Medium CO2 ($137)million
4 High Gas,Medium CO2 ($351)million
5
6 As can be seen from the table,different
7 natural gas forecasts have a large effect on the
8 economics of the project.The low natural gas price
9 forecast results in a project that costs more than the
10 Company's next best alternative,but costs less for both
11 the medium and high forecasts.
12 The range of natural gas forecasts used in its
13 analysis are conservative when compared to the most
14 recent Energy Information Administration (EIA)forecasts.
15 As can be seen in the chart below,the Company's
16 forecasts are largely and consistently lower than EIA's
17 forecasts through 2036.
18
19
20
21
22
23
24
25
CASE NO.PAC-E-17-07 1828 KELLER,R.(Di)16
11/20/17 STAFF
O 1 Comparison of Natural Gas Forecasts
(2017 EIA Annual Energy Outlook Forecasts to Pacificorp Proposals)
2 $16.00
3 $1400
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
---Adopted Medium---Adopted High Adopted Low
--2017 Ref EIA 2017 Lo EIA -2017 Hi EIA
10 There is very little that can be done to
11 mitigate changes in the price of natural gas once the
12 project is implemented.The only mitigation measure that
13 the Company can take is to re-evaluate natural gas prices
14 and other circumstances just prior to commitment of
15 capital and determine if an alternative course of action
16 is warranted.
17 Q.Can you characterize the risk created by CO2
18 prices and how it can be mitigated?
19 A.Yes.The risk is that the actual cost to
20 mitigate CO2 is lower than that assumed in the Company's
21 analysis.This makes the Company's next best alternative
22 more economical when compared to the proposed project.
23 While CO2 prices can have a large impact on the economics
24 of the project,the Company used a conservative and
25 reasonable range of CO2 prices that support the Company's
CASE NO.PAC-E-17-07 1829 KELLER,R.(Di)17
11/20/17 STAFF
1 proposal.Given that current CO2 prices are relatively
2 non-existent,any increase in CO2 prices moving forward
3 will only make the proposed project more economical when
4 compared to available alternatives.
5 For example,the Company evaluated the project
6 economics on three different CO2 price forecasts:zero,
7 medium,and high.The zero price assumes no cost of CO2
8 throughout the project's life.The medium price forecast
9 ranges from $3.41 to $14.40 per ton and the high forecast
10 ranges from $4.73 to $38.42 per ton through year 2036.
11 The Company's PVRR(d)results for the different
12 forecasts,keeping the natural gas price constant to
13 isolate the effects of CO2 pricing,are reflected in the
14 table below:
15 Modeled Scenario PVRR(d)
16 Medium Gas,Zero CO2 $(53)million
17 Medium Gas,Medium CO2 ($137)million
18 Medium Gas,High CO2 ($317)million
19
20 As can be seen by the table,different levels
21 of CO2 price have a large effect on the economics of the
22 project.The Company's next best alternative uses natural
23 gas-fired generation to fill the capacity deficit which
24 makes system costs higher compared to the new wind and
25 transmission project when considering increasing CO2
prices.
CASE NO.PAC-E-17-07 1830 KELLER,R.(Di)18
11/20/17 STAFF
1 Because the Company uses zero priced CO2 as its
2 low case scenario,the Company has provided an evaluation
3 which represents a reasonable "worst case"in terms of
4 CO2 pricing and project economics.Given the "worst
5 case"scenario as a starting point,the Company's
6 analysis provides an accurate evaluation of risk across a
7 full range of CO2 prices.
8 Because future implementation of Federal CO2
9 regulations are uncertain,there is little the Company
10 can do to mitigate future CO2 price risk.However,any
11 future legislation that increases the price on carbon
12 emissions would improve the economics of the proposed
13 project.
14 Q.What project risks that are within the
15 Company's control?
16 A.The Company is in direct control of:
17 a)maintaining Safe Harbor qualification;
18 b)meeting regulatory requirements;
19 c)risks tied to the schedule for both the new
20 wind and transmission as it relates to
21 capturing 100 percent of the PTC benefit;
22 d)costs tied to development and construction of
23 the new wind and transmission project;and
24 e)life cycle performance and availability of the
25 assets through proper operation and
CASE NO.PAC-E-17-07 1831 KELLER,R.(Di)1911/20/17 STAFF
1 maintenance.
2 Q.Is it appropriate for the Company to protect
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NO.PAC-E-17-07 1832 KELLER,R.(Di)19a
11/20/17 STAFF
1 customers from risks within its control?
2 A.Yes.The project is only economical for
3 customers if the project is constructed as proposed.
4 Customers should not be responsible for project costs if
5 the Company fails to complete the project at reasonable
6 cost and on schedule to obtain the necessary PTCs.
7 Q.What project risks are not in the Company's
8 control?
9 A.The Company does not have control of:
10 a)future pricing of natural gas;
11 b)future pricing of the CO2 cost;
12 c)future market price of electricity;and
13 d)any change to corporate tax legislation after
14 significant capital investment.
15 Q.Does this conclude your testimony in this
16 proceeding?
17 A.Yes,it does.
18
19
20
21
22
23
24
25
CASE NO.PAC-E-17-07 1833 KELLER,R.(Di)20
11/20/17 STAFF
1 (The following proceedings were had in
2 open hearing.)
3 MR.KARPEN:With that,I tender the
4 witness for cross-examination.
5 COMMISSIONER ANDERSON:We'll begin with
6 Monsanto,please.
7 MR.BUDGE:No questions.Thank you.
8 COMMISSIONER ANDERSON:Mr.Williams.
9 MR.WILLIAMS:No questions.
10 COMMISSIONER ANDERSON:Mr.Olsen.
11 MR.OLSEN:No questions.
12 COMMISSIONER ANDERSON:The Company,
13 questions?
14 MS.McDOWELL:Yes,we have some questions
15 for Mr.Keller.
16
17 CROSS-EXAMINATION
18
19 BY MS.McDOWELL:
20 Q Good morning.
21 A Good morning.
22 Q So I'd like to turn your attention to page
23 3 of your testimony,please.
24 A Yes.
25 Q I'm just going to ask you some questions
CSB REPORTING 1834 KELLER DC
208.890.5198 Staff
1 about your review of the Company's economic analysis and
2 just to be clear,even though the projects have changed,
3 the economic analysis throughout the case,the models
4 have remained the same;correct?
5 A Generally.
6 Q And on lines 10 through 13,you indicate
7 that you believe the assumptions used by the Company in
8 its economic analysis fall within a reasonable range and
9 support the Company's proposal?
10 A Yes,with regard to the natural gas
11 pricing and the CO2 pricing,I believe they were
12 reasonable.
13 Q So there on page --let me get the cite
14 here.Just further down the page,you conducted an
15 analysis where you looked at the nine scenarios that the
16 Company produced and calculated basically a benefit
17 number that assumed that there was an equal probability
18 that any of those scenarios could occur.Do you recall
19 that analysis?
20 A Yes,based off the benchmark projects,
21 equal weighting for each of the scenarios,yes.
22 Q And that analysis is Exhibit 101 to your
23 testimony;correct?
24 A Yes.
25 Q And in the benchmark case,that produced
CSB REPORTING 1835 KELLER (X)
208.890.5198 Staff
1 an expected value of 191 million?
2 A That's correct.Based off that at that
3 point in time,yes.
4 Q Now,Mr.Link in his settlement
5 testimony --do you have that by the way?
6 A I don't have it.I'm sorry,I have his
7 redacted,yes.
8 Q Okay;so I just wanted to ask you about
9 his Chart 2-ST on page 6 and that is not a confidential
10 chart.
11 A Page 6;is that correct?
12 Q Yes,it's Table 2-ST,do you have that?
13 A Yes,I do.
14 Q So would you accept,subject to check,
15 that conducting that same exercise weighting each of the
16 probabilities or each of the results equally would
17 produce a benefit number of $210 million?
18 A I would defer --I have not completed that
19 calculation.I really can't address it directly.
20 Q But to do that calculation,you would
21 basically take the numbers that are in that first column
22 and average them,effectively?
23 A That was the method that I used.
24 Q Would you accept,subject to check,that
25 that average is 210 million?
CSB REPORTING 1836 KELLER (X)
208.890.5198 Staff
1 MR.KARPEN:I object.The witness said
2 he could not do that calculation.
3 Q BY MS.McDOWELL:It is a subject to check
4 calculation.I'm not going to ask you to pull out your
5 calculator here,but I'm just asking,subject to check,
6 would you accept that that number is 210 million?
7 MR.KARPEN:The witness said he could not
8 answer that question.
9 COMMISSIONER ANDERSON:The witness said
10 he could not answer that question,but with the subject
11 to check,we have given some leeway.Can you rephrase --
12 can you find another way to get there?
13 MS.McDOWELL:Well,I mean,we can go
14 through the math right here of doing the average,so I
15 mean,just normally the subject to check is designed to
16 avoid that.
17 Q BY MS.McDOWELL:So let me just say,does
18 that seem like just ball parking the numbers that 210
19 million would be a reasonable approximate average for
20 those numbers?
21 COMMISSIONER ANDERSON:Subject to
22 check.
23 MS.McDOWELL:Subject to check,of
24 course.
25 THE WITNESS:It seems reasonable,yes.
CSB REPORTING 1837 KELLER (X)
208.890.5198 Staff
1 Q BY MS.McDOWELL:Thank you;so can you
2 turn,then,to page 6 of your testimony?
3 A Yes,I'm there.
4 Q And on lines 19 through 20,actually
5 through 21,you indicate that the Company's economic
6 evaluation is reasonable and in several ways
7 conservative.Do you see that?
8 A Yes,I do.
9 Q And you gave --I found three discussions
10 of the conservative nature of the analysis in your
11 testimony,and I think the first one you mentioned there
12 at the bottom of the page is the way the Company
13 accounted for QF costs in its base case.Do you see
14 that?
15 A Yes,relative to the differential in their
16 base case,as I recall,they used a PTC-qualified
17 resource and based off my investigation that it was more
18 likely that there would be a QF project that would more
19 likely be considered and given that they're looking at
20 the difference between the two cases that using the
21 PTC-qualified benefit,the benefit would be less than if
22 they used the QF.
23 Q And that's just because the base case
24 would be higher cost with the QF;is that the
25 rationale?
CSB REPORTING 1838 KELLER (X)
208.890.5198 Staff
1 A Yes,I believe so.O 2 Q And then on page 8,turning to the next
3 page,you list a second reason why you thought the
4 Company's economic analysis was conservative,and there
5 you indicate beginning on line 4 that the analysis does
6 not include any benefits associated with the sale of
7 RECs.Do you see that?
8 A That's my understanding from Mr.Link's
9 testimony.
10 Q And at least in the initial analysis in
11 this case,including that REC benefit would have taken
12 the cases where there was a net cost and converted those
13 to a net benefit if you assumed a reasonable value for
14 that REC number;correct?
15 A Based off my calculations on the
16 benchmarks and the benefit of the RECs given Mr.Link's
17 testimony,yes.
18 Q And then lastly,I wanted to talk to you
19 about your assessment of the conservatism of the
20 Company's natural gas forecasts,so can you turn to page
21 15 of your testimony?
22 A Page 15,I'm there.
23 Q Do you have that?
24 A Yes.
25 Q Okay,and between lines 13 and 17,there's
CSB REPORTING 1839 KELLER (X)
208.890.5198 Staff
1 a sentence that includes in part the statement that theO2Companyusedareasonablerangeofnaturalgasprice
3 forecasts and are somewhat conservative with respect to
4 the future --to what future natural gas prices will
5 actually be.Do you see that testimony?
6 A Yes.
7 Q And then you actually included a table on
8 line 17 or,excuse me,on page 17,just a couple pages
9 forward.
10 A I'm sorry?
11 Q You included a table on page 17.
12 A I have a graph on page 17.
13 Q Yeah,a graph,I'm sorry.That's what I
14 should have referred to it as.It compares the Company's
15 forecasts to --forecasts from the EIA.Do you see that
16 there?
17 A Yes.
18 Q And your conclusion was that the Company's
19 forward price curve was less than the EIA's referenced
20 case;is that correct?
21 A Staff completed an analysis of natural gas
22 pricing regarding PacifiCorp's forecasted natural gas
23 price relative to the EIA and given Staff's analysis,we
24 determined or believe that at that time the natural gas
25 pricing was conservative relative to what the EIA
CSB REPORTING 1840 KELLER (X)
208.890.5198 Staff
1 projected.There again,that was based off at that point
2 in time.
3 Q And the Company's official forward price
4 curve is the basis for the Company's medium or base case;
5 is that correct?
6 A I believe so,yes.
7 Q Now,back to your testimony on page 15 --
8 A Yes.
9 Q --the fact that you concluded that the
10 Company's natural gas price curves were conservative led
11 you to state beginning on line 17,"This conservative
12 natural gas price assumption will likely result in
13 greater project benefits than those estimated by the
14 Company."Do you see that?
15 A Yes,relative to the forecasted natural
16 gas pricing from the EIA,yes.
17 Q So just translating that into Mr.Link's
18 chart on page 2-ST [sic]--
19 A I'm sorry,the page again?
20 Q It's on page 6 of Mr.Link's settlement
21 testimony.It's Table 2-ST.
22 A Yes.
23 Q So just to try to understand your
24 testimony there,what you're saying about greater project
25 benefits than those estimated,you're saying in these
CSB REPORTING 1841 KELLER (X)
208.890.5198 Staff
1 cases based on the conservatism of the curves,the actual
2 benefits that are likely will be higher than what's in
3 these benefit columns;is that the effect of your
4 testimony?
5 A There's quite a bit of history between now
6 and back then.With respect to this table,this is based
7 off the analysis from Rocky Mountain Power.My
8 information was based off,I think it was,November,so
9 there's been change associated with that.I think
10 there's been an update to the natural gas forecast,so I
11 recognize that I believe my testimony with respect to the
12 conservative nature of Rocky Mountain Power's natural gas
13 forecast relative to the EIA at that time is not directly
14 correlated to what's occurred between my original
15 testimony and what's currently today with lower natural
16 gas prices.
17 Q So you just have not updated your analysis
18 of the Company's curve compared to current EIA curves;is
19 that correct?
20 A I have not updated the analysis.
21 Q So as of last fall when the Company --
22 when you did do this review,however,your assessment was
23 that the project benefits that were projected by the
24 Company were likely to be conservative and could be
25 higher;is that a fair assessment of your testimony?
CSB REPORTING 1842 KELLER (X)
208.890.5198 Staff
1 A At that point?
2 Q At that time.
3 A At that time.
4 Q Thank you.Now,I would like to ask you a
5 question about your testimony at page 3.No,I gave you
6 the wrong cite,I'm so sorry.Can you turn to page 10
7 instead,and in your analysis of the Company's project,
8 you also reviewed the Company's assumptions around wind
9 performance or wind output from the facilities;is that
10 correct?
11 A I did.Would you repeat the question,
12 please?
13 Q I asked whether you reviewed the Company's
14 assumptions around wind performance and energy output
15 from the facilities,the projected facilities.
16 A I did look at based off the benchmark
17 projects.
18 Q And you there on line 13 or,actually,on
19 line 10,you indicate that the amount of energy assumed
20 in the Company's application is reasonable for those
21 benchmark resource sites.Do you see that?
22 A Yes.
23 Q And that analysis was --that conclusion
24 was based on your analysis tied to the reliability of the
25 wind turbine generators,wind turbine efficiency,and the
CSB REPORTING 1843 KELLER (X)
208.890.5198 Staff
1 average wind velocity for the area considered for the
2 proposed benchmark sites.Do you see that?
3 A Yes.
4 Q And it's true,isn't it,that certain of
5 the projects currently on the Company's --that are
6 included in the stipulated projects in the settlement
7 between the Company and the Staff were those benchmark
8 resources;correct?
9 A I believe the only one that falls outside
10 of that is the Cedar Springs project.
11 Q So at that time your assessment was that
12 the Company's wind performance estimates were
13 reasonable?
14 A Given the availability or given the
15 current industry availability of the wind turbines and
16 given my review from INEL of that particular area that my
17 sense was that the capacity factors associated with the
18 benchmark projects in that area were reasonable.
19 Q And you did have a recommendation in your
20 testimony around mechanical availability and the
21 importance of having a mechanical availability guarantee
22 tied to that to a 90 percent availability.Do you recall
23 that?
24 A 97 percent availability,yes.
25 Q And that provision is now included in the
CSB REPORTING 1844 KELLER (X)
208.890.5198 Staff
1 stipulation between the Company and the Staff;correct?
2 A That's correct.
3 Q And that's in,I believe it's,paragraph
4 18 of the stipulation?
5 A I would have to look.
6 Q I meant paragraph 19,I'm sorry.
7 A It indicates that the Company will
8 negotiate these guarantees,yes,at 97 percent.
9 Q And that addresses the issue you raised in
10 your testimony around wind performance?
11 A Yes,it does.
12 Q So I wanted to turn your attention to
13 page --
14 A May I step back from that?
15 Q Of course.
16 A When you say wind performance,with
17 respect to the turbines themselves,yes.
18 Q Thank you.Can you turn to page 6 of your
19 testimony?
20 A Yes,I'm there.
21 Q And there you describe certain benefits of
22 the stipulated projects,I guess,at the time of the
23 combined projects,so beginning on line 8,you indicate,
24 "the new wind and transmision project would provide
25 benefit to customers by providing lower cost energy to
CSB REPORTING 1845 KELLER (X)
208.890.5198 Staff
1 the system,provide improved transmission system
2 reliability,and would add diversity to the Company's
3 generating resources."Do you see that testimony?
4 A Yes,I'd like to preface that with respect
5 to I say,"Aside from this lack of current need."
6 Q With respect to your testimony on lines 8
7 through 12,does that remain your opinion with respect to
8 the stipulated projects that they provide those
9 benefits?
10 A I would agree with that,yes.
11 MS.McDOWELL:That's all I have.Thank
12 you.
13 COMMISSIONER ANDERSON:Thank you,Ms.
14 McDowell.Any questions from the Commission?
15 Redirect?
16 MR.KARPEN:Yes.
17
18 REDIRECT EXAMINATION
19
20 BY MR.KARPEN:
21 Q On page 3 of your testimony,starting with
22 line 6,you say specifically,"Although not needed to
23 meet system capacity requirements until 2028,"is it
24 still your opinion that the combined projects are not
25 needed to meet system capacity requirements until 2028?
CSB REPORTING 1846 KELLER (ReDi)
208.890.5198 Staff
1 A Yes.
2 Q On page 4 of your testimony,you state
3 starting on page 5 that there are several risks
4 associated.You categorize them into two risks,those
5 the Company can control and those it can't control.I
6 think of the risks outside of the Company's control,you
7 had stated gas prices,CO2 prices,and federal tax
8 legislation;is that accurate?
9 A That's correct.
10 Q And you stated at the beginning of your
11 testimony before it was spread on the record that that
12 federal tax revision has come to fruition at this point;
13 is that correct?
14 A Yes,that's correct.
15 Q So at this point the risks outside of the
16 Company's control,in your opinion,generally are natural
17 gas pricing and CO2 pricing;is that accurate?
18 A That's correct.
19 Q The risks that you categorize that are
20 within the Company's control,do you believe those
21 remain?
22 A Could you direct me in my testimony?
23 Q Yeah,starting on page 4,you had said
24 that there are risks,and I believe it's on line 5,you
25 broadly categorize the risks that the Company can and
CSB REPORTING 1847 KELLER (ReDi)
208.890.5198 Staff
1 can't control.We already went over the risks theO2Companycan't control and the remaining part of your
3 testimony,generally speaking,you speak to a number of
4 risks that the Company does have within its control,such
5 as completing the project on time,securing rights of
6 way,regulatory approval,et cetera.
7 A Yes.
8 Q Do you believe those risks remain?
9 A That's correct,and controlling costs.
10 Q In fact,on page 13 of your testimony,
11 starting on line 7,you state,"The combination of hard
12 deadlines and project uncertainties can lead to delays
13 which can only be remedied by increasing cost,
14 authorizing overtime,and adding incremental resources."
15 Do you believe those costs remain as well --risks,
16 excuse me?
17 A I think those risks are still a potential
18 issue.
19 Q Do you believe those risks can be
20 mitigated by the imposition of an overall capital cost
21 cap,a hard cap,if you will?
22 A I think with respect to the imposition of
23 a hard cap as well the guarantee on the PTCs,yes.
24 Q Now,you stated your testimony was done in
25 November of 2017.Since that time,are you aware that
CSB REPORTING 1848 KELLER (ReDi)
208.890.5198 Staff
1 there have been changes in the natural gas forecasts done
2 by the Company?
3 A Yes.
4 Q Those forecasts have gone down from their
5 previous estimates;is that correct?
6 A Subject to check,yes.
7 Q So subject to check,if those natural gas
8 prices go down,that makes the Company estimates less
9 conservative and more risky;is that accurate?
10 A Yes,if the natural gas prices go down,it
11 makes the benefit,the differential benefit,between the
12 baseline and the stipulated projects less beneficial,
13 yes.O 14 Q That amount of risk underscores the
15 necessity for a hard cap,would you agree?
16 A I would agree with that,yes.
17 MR.KARPEN:Thank you.I have no further
18 questions for this witness.
19 COMMISSIONER ANDERSON:Thank you,Mr.
20 Karpen.Thank you for your testimony,Mr.Keller.
21 THE WITNESS:Thank you.
22 (The witness left the stand.)
23 COMMISSIONER ANDERSON:You may call your
24 next witness.
25 MR.KARPEN:Staff calls Mike Louis.
CSB REPORTING 1849 KELLER (ReDi)
208.890.5198 Staff
1 MICHAEL LOUIS,O 2 produced as a witness at the instance of the Staff,
3 having been first duly sworn to tell the truth,was
4 examined and testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR.KARPEN:
9 Q Good morning,Mr.Louis.
10 A Good morning.
11 Q Can you please state your name and spell
12 your last name for the record?
13 A My name is Michael Louis.Last name isO14spelledL-o-u-i-s.
15 Q Mr.Louis,how are employed?
16 A I'm employed as the program manager over
17 the engineering section within the Idaho Public Utilities
18 Commission.
19 Q Are you the same Michael Louis who filed
20 supplemental testimony in this matter?
21 A Yes,I am.
22 Q Are you also the same Michael Louis who
23 has agreed to sponsor the direct testimony of former
24 utility administrator Randy Lobb?
25 A Yes,I will.Yes,I do.
CSB REPORTING 1850 LOUIS (Di)
208.890.5198 Staff
1 Q Are you familiar with both of those
2 testimonies?
3 A Yes,I am.
4 Q Do you have any corrections or additions
5 to make to those?
6 A I do.On page 13 of my supplemental
7 testimony,page 13,line 16,it has 8.7 percent,that
8 should be corrected to 9.1 percent.
9 MS.McDOWELL:So that number is
10 confidential,so perhaps we could ensure that it's
11 maintained in a confidential way in the transcript.
12 THE WITNESS:We noticed that it was
13 included in Rick Link's testimony as a non-confidentialO14numberandthat's why we --
15 MS.McDOWELL:All right,can I just
16 verify,if I might?
17 COMMISSIONER ANDERSON:Subject to check?
18 MS.McDOWELL:Thank you.It's a handy
19 tool,isn't it?
20 (Pause in proceedings.)
21 MS.McDOWELL:So I have checked and I
22 have verified that it's not confidential,so you're right
23 and the alarm is off.Thank you.
24 COMMISSIONER ANDERSON:Thank you.
O 25 MR.KARPEN:Our apologies,nonetheless.
CSB REPORTING 1851 LOUIS (Di)
208.890.5198 Staff
1 MS.McDOWELL:My apologies.I saw yellow
2 here and I saw red.
3 Q BY MR.KARPEN:Do you have any other
4 corrections or additions to make to those testimonies?
5 A No,I do not.
6 MR.KARPEN:With that,I move that the
7 testimony and associated exhibits be spread upon the
8 record as if read.
9 COMMISSIONER ANDERSON:Without objection,
10 we will spread Mr.Louis'testimony and exhibits,along
11 with the sponsored testimony of Randy Lobb,across the
12 record as if read.
13 (The following prefiled direct testimony
14 of Mr.Randy Lobb,sponsored by Mr.Michael Louis,and
15 the supplemental testimony of Mr.Michael Louis is spread
16 upon the record.)
17
18
19
20
21
22
23
24
25
CSB REPORTING 1852 LOUIS (Di)
208.890.5198 Staff
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Randy Lobb and my business address
4 is 472 West Washington Street,Boise,Idaho.
5 Q.By whom are you employed?
6 A.I am employed by the Idaho Public Utilities
7 Commission as Utilities Division Administrator.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science Degree in
11 Agricultural Engineering from the University of Idaho in
12 1980 and worked for the Idaho Department of Water
13 Resources from June of 1980 to November of 1987.IO14receivedmyIdaholicenseasaregisteredprofessional
15 Civil Engineer in 1985 and began work at the Idaho Public
16 Utilities Commission in December of 1987.I have
17 analyzed utility rate applications,rate design,tariff
18 filings and customer petitions.I have testified in
19 numerous proceedings before the Commission including
20 cases dealing with rate structure,cost of service,power
21 supply,line extensions,regulatory policy and facility
22 acquisitions.My duties at the Commission include case
23 management and oversight of all technical Staff assigned
24 to Commission filings.
25 Q.What is the purpose of your testimony in this
CASE NO.PAC-E-17-07 1853 LOBB,R.(Di)1
11/20/17 STAFF
1 case?
2 A.The purpose of my testimony is to present
3 Staff's
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CASE NO.PAC-E-17-07 1854 LOBB,R.(Di)la
11/20/17 STAFF
1 position on the Company's request for a Certificate of
2 Public Convenience and Necessity (CPCN)and Binding
3 Ratemaking Treatment to construct new wind generation and
4 associated transmission.
5 Q.Please summarize your testimony.
6 A.Based on an evaluation of the Company's
7 proposal,Staff believes the Commission should
8 conditionally approve a CPCN to construct the project.
9 Given that the proposed generation and transmission
10 project will be constructed well in advance of need,
11 project justification depends upon the reasonableness of
12 assumptions used in the Present Value Revenue Requirement
13 (PVRR)analysis and the Company's ability to acquire allO14availableProductionTaxCredits(PTCs).
15 Consequently,Staff's CPCN recommendation comes
16 with conditions that include off-ramps and project
17 benefit/cost assurances whereby the Company would
18 discontinue project development,impute PTCs,or cap
19 project costs subject to recovery if it failed to meet
20 necessary terms.The terms include timelines,generation
21 of sufficient PTCs,or capping costs.Staff also
22 recommends that the Commission accept the proposed Rate
23 Adjustment Mechanism (RTM)to properly track costs and
24 benefits but reject Binding Ratemaking Treatment in this
O 25 case due to lack of need and justification for such a
CASE NO.PAC-E-17-07 1855 LOBB,R.(Di)2
11/20/17 STAFF
1 finding.
2 Q.Could you please briefly summarize the
3 Company's
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CASE NO.PAC-E-17-07 1856 LOBB,R.(Di)2a
11/20/17 STAFF
1 request in this case?
2 A.Yes.The Company requests a CPCN to construct
3 four new wind projects in Wyoming with a name plate
4 capacity of 860 Mw.As a necessary part of the new wind
5 project,the Company also proposes to construct 179 miles
6 of new transmission line with voltages ranging from 500
7 KV to 230 KV.Total project cost is approximately $2
8 billion and must be in operation by December 31,2020,to
9 secure necessary PTC benefits.
10 The Company maintains that if the wind
11 generation and transmission line is constructed in a
12 timelyer manner,sufficient PTCs will be generated to
13 make the project the most economical resource on a
14 Present Value Revenue Requirement (PVRR)basis over the
15 next 30 years.The Company also maintains that Binding
16 Rate Making Treatment with an associated RTM is necessary
17 to assure overall project cost recovery and that costs
18 and benefits are properly balanced.
19 Q.Does Staff support the Company's request for a
20 CPCN in this case?
21 A.Yes,based on Staff's review of the Company's
22 filing and provided conditions described below are
23 included with the CPCN,Staff supports the Company's CPCN
24 request.
25 Q.Has Staff evaluated the PVRR economic analysis
CASE NO.PAC-E-17-07 1857 LOBB,R.(Di)3
11/20/17 STAFF
1 performed by the Company?
2 A.Yes,Staff witness Rick Keller has conducted a
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CASE NO.PAC-E-17-07 1858 LOBB,R.(Di)3a
11/20/17 STAFF
1 comprehensive review of the Company's PVRR analysis
2 including an evaluation of the associated risks.Mr.
3 Keller's testimony detailing the results of his analysis
4 are included as part of the record in this case.
5 Q.What does his analysis conclude?
6 A.His analysis concludes that the risks and
7 uncertainties associated with the project can be
8 categorized into one of two groups;those in which the
9 Company can exert control and those in which it cannot.
10 He maintains that if the Company protects
11 customers from those risks that are within its control,
12 then he believes the new wind and transmission project
13 would be least-cost least-risk when compared to the
14 baseline alternative.
15 Q.How does Mr.Keller's investigation affect
16 Staff's CPCN recommendation in this case?
17 A.Because the Company's identified first need for
18 capacity is approximately 2028,the need for the project
19 is currently driven by the limited opportunity to
20 generate production tax credits that make the project
21 more economical than other resource options over the next
22 30 years.Staff witness Keller assessed the Company's
23 ability to acquire PTCs in a timely manner and whether
24 the assumptions used by the Company in its economic
O 25 comparison are reasonable.Mr.Keller also identified
the risks that have the greatest
CASE NO.PAC-E-17-07 1859 LOBB,R.(Di)4
11/20/17 STAFF
1 impact on the analysis.
2 Q.What are the most important risks identified by
3 Mr.Keller?
4 A.Mr.Keller identified two types of risk:1)
5 those that can be controlled by the Company;and 2)those
6 outside of the Company's control.The most important
7 risk under the Company's control is failure to complete
8 the project in the time specified to obtain PTCs.
9 Company witness Crane agrees,stating in testimony that
10 PTC value is essential to the combined projects overall
11 economic viability.Other important risk factors under
12 the Company's control are project cost overruns,the
13 proper tracking of project costs and benefits and
14 mechanical availability of the project.
15 The most important risks outside the Company's
16 control include the potential change in corporate tax
17 rate,and the potential inaccuracy of future PVRR
18 assumptions.
19 Q.Can the identified risk factors be mitigated to
20 allow a CPCN and assure customer benefits?
21 A.I believe some of the risks can be mitigated.
22 As a condition for granting a CPCN,the Commission should
23 establish conditions assuring that customers are held
24 harmless if benefits fail to materialize and the project
25 becomes uneconomical.Therefore,Staff recommends that
C ONO.PAC-E-17-07 1860.LOBB,R.(D TAF5F
1 the Company continually reassess project economics due to
2 changing circumstances and establish off-ramps before
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CASE NO.PAC-E-17-07 1861 LOBB,R.(Di)5a
11/20/17 STAFF
1 development occurs.O 2 For example,the Company must reassess project
3 economics due to schedule delays that reduce PTCs.The
4 Company should also reassess pursuing the project if tax
5 rate changes reduce project benefits.Finally,the
6 Company should be prepared to justify its actions prior
7 to any cost recovery request if identified risk factors
8 change materially.Once the project is completed and
9 PTCs are fully acquired,remaining risks subject to
10 further mitigation would include transmission costs
11 overruns associated with meeting the PTC deadline,
12 matching costs and benefits after a rate case and project
13 mechanical availability.
14 Q.How does Staff propose to mitigate transmission
15 costs overruns?
16 A.Staff recommends that project costs associated
17 with the new transmission be capped at a level not to
18 exceed the Company's estimate for cost recovery purposes.
19 While costs associated with the project's wind component
20 are subject to competitive bidding,they are backstopped
21 by the Company's self-build project cost.There is no
22 such back stop for the project's transmission costs
23 component.
24 Timing is the most critical factor in securing
25 customer benefits.Staff is concerned that once the
CASE NO.PAC-E-17-07 1862 LOBB,R.(Di)6
11/20/17 STAFF
1 Company reaches a point of no return in terms of project
2 investment,transmission costs could escalate in order to
3 finish
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CASE NO.PAC-E-17-07 1863 LOBB,R.(Di)6a
11/20/17 STAFF
1 construction by the PTC deadline.Staff witness Keller
2 shows that transmission costs overruns of 25%will make
3 the project uneconomical.Therefore,Staff recommends
4 that the Commission establish a cost cap for transmission
5 costs recovery based on the cost estimate provided by the
6 Company in this case.
7 Q.How will the Company assure a proper matching
8 of costs and benefits?
9 A.The proposed RTM is designed to match project
10 benefits such as reduced power supply expenses and PTCs
11 that track automatically through the annual ECAM with
12 project costs that are normally only included as part of
13 a general rate case.Under the Company's proposal,the
14 RTM would be discontinued once costs and benefits are
15 included in a general rate case.Because all benefits
16 will automatically flow through the Energy Cost
17 Adjustment Mechanism (ECAM),a general rate case or RTM
18 in the ECAM as proposed by the Company in this case would
19 be required to allow recovery of offsetting costs.
20 Q.Does Staff support an RTM in this case?
21 A.Staff supports the concept and purpose of an
22 RTM.Assuming an economical project is constructed,
23 customers would automatically receive benefits through
24 the annual ECAM mechanism but would not pay any project
O 25 costs without a general rate case.An RTM would
equitably match project
CASE NO.PAC-E-17-07 1864 LOBB,R.(Di)7
11/20/17 STAFF
1 costs with project benefits as costs are actually
2 incurred.
3 Q.Has Staff evaluated the mechanics of the
4 proposed RTM?
5 A.Yes,Staff evaluated the details of an RTM in
6 this case,and in Case No.PAC-E-17-06,the Wind
7 Repowering case.Staff maintains that an RTM is a
8 reasonable way to balance benefits and costs as long as
9 all benefits are included in the ECAM.
10 Q.What happens to cost and benefit matching after
11 a general rate case?
12 A.Once the RTM is eliminated,benefits will
13 continue to track through the existing ECAM and costO14recoverywillremainataconstantleveluntilthe next
15 general rate case.
16 Q.Has Staff identified any problems with this
17 approach?
18 A.Yes,potentially.While an RTM would track
19 benefits and costs annually through the ECAM before a
20 general rate case,the timing of rate cases would dictate
21 cost level recovery from that point forward.If revenue
22 requirement associated with the project declines in
23 between general rate cases,the reduction in costs would
24 not flow to customers as assumed in the Company's NPVRR
25 analysis.
CASE NO.PAC-E-17-07 1865 LOBB,R.(Di)8
11/20/17 STAFF
1 Staff Exhibit No.102 shows how revenue
2 requirement declines in the Company's PVRR analysis and
3 what the decline would be without annual rate cases.
4 Staff analysis shows
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CASE NO.PAC-E-17-07 1866 LOBB,R.(Di)8a
11/20/17 STAFF
1 customers would lose approximately $13 million in net
2 present value benefits if rates are set in a 2021 rate
3 case and are not reset again until 2030.
4 Q.What does Staff recommend to assure that
5 benefits and costs are properly tracked after a general
6 rate case?
7 A.Staff recommends that revenue requirement for
8 this project continue to be tracked after the first
9 general rate case as it would be in the RTM annually.If
10 project revenue requirement declines in between rate
11 cases,then the benefit of declining cost would be
12 returned to customers through the ECAM.
13 Q.Is there any risk that project generation will
14 be less than estimated?
15 A.As stated by Staff witness Keller,wind
16 profiles,wind velocities and wind turbine conversion
17 efficiencies are fairly well established and are
18 reasonably estimated by the Company.However,reduced
19 mechanical availability of the wind machines can
20 significantly reduce project output.Manufacturer
21 warranties and proper wind turbine O&M can mitigate that
22 risk.
23 Staff maintains that the Company should provide
24 a Mechanical Availability Guarantee (MAG)for this
25 project based on the industry average of 97%as provided
CASE NO.PAC-E-17-07 1867 LOBB,R.(Di)9
11/20/17 STAFF
1 by Staff witness Keller.While the Company can'tO2guaranteethatthewindwillblowsufficientlyto produce
3 the estimated PTCs,
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CASE NO.PAC-E-17-07 1868 LOBB,R.(Di)9a
11/20/17 STAFF
1 reduced PTCs should not occur because the wind turbinesO2arenotmechanicallyavailable.Through manufacturer
3 guarantees and proper maintenance,the Company should be
4 able to reasonably meet this MAG average or reimburse
5 customers for failure to do so.
6 Q.Does Staff support the Company's request for
7 Binding Ratemaking treatment?
8 A.No.Staff does not believe the Company has
9 shown that Binding Ratemaking is justified in this case.
10 Q.How did Staff evaluate the Company's request
11 for Binding Ratemaking treatment?
12 A.Staff reviewed Idaho Code,Company
13 justification and other cases before the Commission where
14 Binding Ratemaking was addressed.While Staff concedes
15 that the Company meets the statutory requirements of
16 Idaho Code §61-541 in terms of having a current IRP,
17 participating in regional transmission groups,and a
18 showing that the project is in the public interest,the
19 Company has not shown that binding ratemaking is
20 necessary for the project to proceed.
21 Staff identified four reasons for the
22 Commission to reject the Company's request in this
23 regard:1)the Company admits that its ability to finance
24 the project is not an issue in this case;2)Idaho
25 represents only 6%of the Company's total system and it
CASE NO.PAC-E-17-07 1869 LOBB,R.(Di)10
11/20/17 STAFF
1 is the decisions on cost recovery in the otherO2jurisdictionsthatwilldriverating
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CASE NO.PAC-E-17-07 1870 LOBB,R.(Di)10a
11/20/17 STAFF
1 agency perceptions;3)Staff has already recommended
2 approval of a CPCN and the alternative RTM ratemaking
3 treatment so Binding Ratemaking is unnecessary;and 4)
4 the Company has already made significant investment in
5 the project.
6 Q.Has the Commission addressed this issue in the
7 past?
8 A.Yes.The Commission has addressed the issue
9 twice.The first time in Case No.IPC-E-09-03,Idaho
10 Power requested Binding Ratemaking treatment for
11 construction of its Langley Gulch gas fired generating
12 plant during turbulent economic conditions.The
13 Commission approved binding rate making treatment for
14 project costs that had already been incurred but did not
15 assure recovery of estimated costs that were more
16 uncertain.Order No.30892 at 39.
17 The second time the Commission addressed a
18 request for Binding Ratemaking treatment was in Case No.
19 IPC-E-13-16.In that case,Idaho Power requested Binding
20 Ratemaking treatment for costs associated with Selective
21 Catalytic Reduction Controls (SCRC)for Jim Bridger Units
22 3 and 4.In Order No.32929 the Commission rejected the
23 request stated that financial markets were risk averse to
24 large investment at the time the Commission approved
25 binding ratemaking treatment in the Langley Gulch case.
CASE NO.PAC-E-17-07 1871 LOBB,R.(Di)11
11/20/17 STAFF
1 The Commission concluded that circumstances were entirelyO2distinguishable.The Commission also noted that the
3 Company had already
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CASE NO.PAC-E-17-07 1872 LOBB,R.(Di)lla
11/20/17 STAFF
1 purchased a significant portion of the SCRC equipmentO2neededfortheproject.In this case,the conditions are
3 also distinguishable from the Langley case in terms of
4 financial urgency.Binding ratemaking should be denied.
5 Q.Does this conclude your testimony in this case?
6 A.Yes,it does.
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CASE NO.PAC-E-17-07 1873 LOBB,R.(Di)12
11/20/17 STAFF
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Michael Louis.My business address
4 is 472 West Washington Street,Boise,Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as the Engineering Section Program Manager.
8 Q.What is your educational and professional
9 background?
10 A.I received my Bachelor and Master of Science
11 degrees in Industrial Engineering with concentrations in
12 manufacturing systems and engineering economics from
13 Purdue University in 1985 and 1992,respectively.I also
14 received my Masters in Public Policy and Administration
15 at Boise State University in 2005.In addition to my
16 formal education,I have attended Michigan State
17 University Institute of Public Utilities Annual
18 Regulatory Studies Program,NARUC Utility Rate School,
19 Electricity Grid School,and Advanced Regulatory Studies
20 Program as well as CAISO Market and Transaction training.
21 My work experience includes 18 years of
22 industrial/commercial practice developing and managing
23 manufacturing systems and operations,planning processes,
24 and supply chains for General Motors,Hewlett-Packard,
25 Jabil Circuit,and Albertsons Companies.I also have
CASE NO.PAC-E-17-07 1874 LOUIS,M.(Supp)1
04/11/18 STAFF
1 spent six years administrating and conducting energyO2policyresearchwiththeEnergyPolicyInstituteat Boise
3 State University.
4 I began working for the Idaho Public Utilities
5 Commission in July 2011 where I am currently supervising
6 the Staff Engineering Section.I have conducted analysis
7 on a wide variety of electricity,natural gas,and water
8 utility cases dealing with integrated resource plans,
9 purchased gas and power cost adjustments,prudence
10 reviews of power plant and other facility infrastructure
11 investments,facility decommissioning,line extensions,
12 and general rate cases.
13 Q.What is the purpose of your testimony in this
14 case?
15 A.The purpose of my testimony is to provide
16 additional detail and refinement of Staff's position on
17 the Company's request for a Certificate of Public
18 Convenience and Necessity (CPCN)and Binding Ratemaking
19 Treatment to construct new wind generation and
20 transmission infrastructure.I am modifying Staff's
21 position that was presented in Randy Lobb's direct
22 testimony as a result of new information obtained from
23 the Company's supplemental Request for Proposal (RFP)
24 filings and discovery requests.I also provide additional
O 25 detail clarifying the rationale and basis for Staff's
position.
CASE NO.PAC-E-17-07 1875 LOUIS,M.(Supp)2
04/11/18 STAFF
1 Q.How is your testimony organized?
2 A.My testimony is organized into the following
3 sections:
4 I.Summary of Testimony
5 II.Clarification of Staff's position
6 III.Mitigation of Project Cost Risk
7 IV.Mitigation of Production Tax Credit (PTC)
8 benefit risk
9 I.Summary of Testimony
10 Q.Please summarize your testimony in this case.
11 A.Staff continues to recommend that the
12 Commission conditionally approve a CPCN to construct the
13 combined new transmission and wind project.However,as
14 a result of Staff's analysis of the Company's RFP
15 supplemental testimony submitted on January 17,2018,
16 Staff identified additional risks and concerns.
17 Accordingly,Staff proposes modifications of the
18 conditions contained in Staff witness Randy Lobb's
19 testimony to limit exposure to risk that the project will
20 not provide net benefits to ratepayers.
21 The project is being constructed well in
22 advance of need.As such,the Company's justification
23 rests on a projected cost reduction to customers and the
24 reasonableness of cost and benefit assumptions used in
25 its Present Value Revenue Requirement difference
CASE NO.PAC-E-17-07 1876 LOUIS,M.(Supp)3
04/11/18 STAFF
1 (PVRR(d))economic analysis submitted in the Company's
2 RFP
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CASE NO.PAC-E-17-07 1877 LOUIS,M.(Supp)3a
04/11/18 STAFF
1 Supplemental and Second Supplemental filing.O 2 The Company's supplemental filings were
3 submitted primarily to provide analysis results with
4 updated assumptions including specific wind projects
5 selected as a result of the RFP process.The Company
6 conducted that analysis and modified assumptions related
7 to tax treatment,generation performance,construction
8 status,and other factors.
9 Staff witness Rick Keller's direct testimony
10 outlined several risks the project proposal contained in
11 the Company's initial Application and testimony.After
12 analyzing the Company's RFP supplemental filings and
13 discovery requests,Staff identified several additional
14 concerns that are detailed in Staff witness Michael
15 Eldred's supplemental testimony.
16 Staff still believes that the proposed project
17 will likely provide positive net benefits,but only if
18 the Company can achieve or exceed the benefits and costs
19 included in its PVRR(d)analysis.
20 After analyzing new information,in addition to
21 the conditions outlined in Randy Lobb's testimony,Staff
22 recommends modifying the hard cap on transmission capital
23 cost such that the Company be subject to a hard cap on
24 all capital project costs.This is due to additional
O 25 risks identified with the wind projects.Thus,Staff
recommends
CASE NO.PAC-E-17-07 1878 LOUIS,M.(Supp)4
04/11/18 STAFF
1 including capital cost for both the wind and transmissionO2projects.
3 II.Clarification of basis for Staff's Position
4 Q.Is there anything that you would like to
5 clarify regarding the basis for Staff's position?
6 A.Yes.In Staff witness Randy Lobb's direct
7 testimony,he states that,"[g]iven that the proposed
8 generation and transmission project will be constructed
9 well in advance of need,project justification depends
10 upon the reasonableness of assumptions used in the
11 Present Value Revenue Requirement analysis and the
12 Company's ability to acquire all available Production Tax
13 Credits."(Lobb,DI,pg.2)I would like to expand on
14 why this is important,especially regarding the project
15 being constructed well in advance of need.
16 Generally,most CPCNs submitted for new
17 generation projects or transmission are justified based
18 on a need to maintain sufficient capacity to meet load.
19 In such cases,Staff believes that the proper analysis is
20 to compare a sufficient number of different types of
21 viable load serving alternatives against each other so
22 that a least cost/least risk alternative can be
23 authorized.
24 For example,in Idaho Power's Langley
25 Gulch CPCN case,the Company performed a head-to-head
CASE NO.PAC-E-17-07 1879 LOUIS,M.(Supp)5
04/11/18 STAFF
1 Net Present Value (NPV)comparison analysis of 13
2 different
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CASE NO.PAC-E-17-07 1880 LOUIS,M.(Supp)5a
04/11/18 STAFF
1 dispatchable resource alternatives consisting of both
2 Combined Cycle Combustion Turbine (CCCT)and Simple Cycle
3 Turbine (SCT)generation projects,all with similar
4 amounts of capacity contribution.(IPC-E-09-03).Another
5 example is the Jim Bridger Selective Catalytic Reduction
6 (SCR)case (IPC-E-13-16).There,the Company performed a
7 head-to-head NPV comparison analysis between the proposed
8 installation of SCR environmental controls to two
9 comparable alternatives:a natural gas conversion,and a
10 CCCT replacement option.In both examples,the Company
11 needed dispatchable and/or baseload resources to maintain
12 system reliability.Within that scope,the Company
13 identified a sufficient set of viable generation types
14 and alternatives for comparison so that a least
15 cost/least risk resource could be selected.
16 This case is based on a different
17 justification.Here,the justification for the Combined
18 Projects is based on whether or not the Company's
19 proposal provides a cost savings to customers as compared
20 to the Company's base case:a resource portfolio that
21 does not include the Combined Projects.The conclusion
22 of having no generation or transmission need rests on two
23 sets of evidence.
24 1.The Company has estimated that capacity to
O 25 meet load is not needed until the summer
of 2028.
CASE NO.PAC-E-17-07 1881 LOUIS,M.(Supp)6
04/11/18 STAFF
1 2.There is considerable uncertainty that the
2 Combined Projects are least cost/least
3 risk for a capacity deficit that doesn't
4 occur for more than ten years.
5 These issues are discussed further in my
6 testimony and in Staff witness Michael Eldred's
7 testimony.
8 Q.Is the Company making a case that there is a
9 resource need prior to 2028?
10 A.Yes.In Company witness Rick Link's rebuttal
11 testimony (page 9,lines 13-16)he states that there is a
12 resource need prior to that time frame.Specifically,
13 Mr.Link states that "the 2017 IRP shows a near-termO14resourceneedof527MWin2017risingto1023MW in
15 2021,the first full year the Combined Projects will be
16 placed into service."
17 Q.Is a resource need the same as a need for
18 capacity to meet load in this case?
19 A.Absolutely not.The first capacity deficiency
20 date,when new capacity is needed to meet load
21 requirements,is determined by analyzing the Company's
22 Load and Resource Balance in the Company's Integrated
23 Resource Plan (IRP).
24 The Company's 2017 IRP (PAC-E-17-03)and the
O 25 Company's subsequent filing for a PURPA first capacity
deficiency date (PAC-E-17-09,Commission Order No.33917)
CASE NO.PAC-E-17-07 1882 LOUIS,M.(Supp)7
04/11/18 STAFF
1 both reflect a first capacity deficiency date for the
2 summer of 2028.
3 If a Company proposes new resources in its IRP far
4 in advance of the first capacity deficiency date,it is
5 likely for reasons other than to meet a capacity
6 deficiency,such as economics,as is the case with the
7 Combined Projects.
8 According to Rick Link's own rebuttal
9 testimony,when answering the question how the resource
10 need in 2021 would be met without the Combined Projects,
11 he states,"Resource portfolios that do not include the
12 Combined Projects include more uncommitted Front Office
13 Transactions (FOTs)."(Page 10,lines 4-7).That does
14 not mean that there is a need for additional new capacity
15 to meet load requirements.The only capacity requirement
16 for FOTs is that there is sufficient transmission
17 capacity.
18 Q.Is there sufficient existing transmission
19 capacity to meet load using FOTs?
20 A.Yes.The Company clearly states that "[t]he
21 2017 IRP shows that the Company first becomes capacity
22 deficient in 2028,"as stated in the Company's
23 Application for determining the PURPA first capacity
24 deficiency date (PAC-E-17-09,page 3).To determine the
25 deficiency date,the Company determines "firm resource
CASE NO.PAC-E-17-07 1883 LOUIS,M.(Supp)8
04/11/18 STAFF
1 capacity available at the annual system peak load hour,O 2 including the Company's firm
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CASE NO.PAC-E-17-07 1884 LOUIS,M.(Supp)8a
04/11/18 STAFF
1 access to imports from the wholesale market (or 'FrontO2OfficeTransactions')..."(See PAC-E-17-09
3 Application,pg.3)In order to have "firm access to
4 imports",the Company has to ensure it has sufficient
5 transmission capacity,the Company confirms this access
6 by establishing a 2028 capacity deficiency date.
7 Q.Is there additional evidence that the Company
8 is basing its justification on a cost savings to
9 customers and not on need for new capacity?
10 A.Yes.In Company witness Link's rebuttal
11 testimony,he states that "resource portfolios with more
12 uncommitted FOTs are higher cost than resource portfolios
13 that include the Combined Projects under a wide range of
14 price-policy scenarios."(Link,Rebuttal,p 10,
15 lines 7-9).The resource portfolios that he mentions
16 includes the resource "base case"portfolio that would
17 have been the Company's preferred portfolio in the IRP
18 had the opportunity to earn PTC's for wind projects not
19 materialized late in the IRP process.Furthermore,the
20 Company's overall analysis approach was based on showing
21 there would be a cost-savings to customers as compared to
22 the base case.
23 This implies that at least until 2028,the
24 justification is based purely on economics and not a need
25 for new capacity to meet load.
CASE NO.PAC-E-17-07 1885 LOUIS,M.(Supp)9
04/11/18 STAFF
1 Q.How certain is the need for capacity in 2028?
2 A.Not very certain.The ability of a Company to
3 accurately determine a capacity deficiency date ten years
4 into the future is limited,and the need to be accurate
5 that far into the future for resource planning purposes
6 is rarely required.
7 For most resource decisions,the amount of lead
8 time needed to make a decision to add capacity is based
9 on the longest lead time item of a resource's
10 construction plan.It is usually advantageous to wait as
11 long as reasonably possible to make a resource investment
12 decision because the information is usually more accurate
13 closer to the time it is needed.This prevents incurringO14investmentcostsbeforearesourceisactuallyneeded.
15 This is also one reason IRPs are required every two years
16 so that the latest information can be used to determine
17 when a new resource is needed closer to when a decision
18 has to be made.
19 For example,the table below illustrates how
20 much capacity deficiency dates can change between IRP's
21 for all three Idaho electric utilities.Further,because
22 of the conservative nature of long-term resource
23 planning,there is a tendency for additional capacity
24 needs to push out with each new planning cycle.
25
CASE NO.PAC-E-17-07 1886 LOUIS,M.(Supp)10
04/11/18 STAFF
1 First Capacity Deficit Dates 2013 IRP 2015 IRP 2017 IRP
2 Avista 2015 2021 2026
3 Idaho Power 2016 2025 2026
4 PacifiCorp 20131 2020 2028
5
6 Q.What kind of factors could change the type of
7 resource needed to fill a capacity requirement that far
8 into the future?
9 A.Some of the factors include changes in a
10 utility's loads and load characteristics,gas prices,
11 electricity prices,environmental regulations,and
12 advances in technology,just to name a few.And because
13 of a rapidly changing energy landscape,it is very
14 difficult to speculate which resource alternatives for
15 meeting capacity requirements will be the most economical
16 that far into the future.For example,the cost of gas
17 over the past 10 years has dramatically changed the types
18 of resources that are most economical to meet load
19 requirements.In June of 2008,Henry Hub gas spot prices
20 peaked at close to $13 per MMBtu but have since then
21 reduced by 77%,and now hovers between $2 and $3 per
22 MMBTU (EIA,Henry Hub Natural Gas Spot Prices).Because
23 of the changes in economics of natural gas-fired
24 generation,there has been a dramatic
25
CASE NO.PAC-E-17-07 1887 LOUIS,M.(Supp)11
04/11/18 STAFF
1 /
2
3 /
4
5 /
6
7
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24 1 This deficit does not reflect full import capability,only firm
purchases .
25
CASE NO.PAC-E-17-07 1888 LOUIS,M.(Supp)lla
04/11/18 STAFF
1 displacement of coal generation over the past ten years
2 that was not foreseen at the time that gas prices were
3 $13 per MMBTU.
4 Q.Are there any changing factors and resource
5 types that could make the Combined Projects less
6 economical than another type of load serving alternative
7 by the time that the Company experiences a capacity
8 deficit?
9 A.Yes,there are many scenarios that could change
10 the calculus.A good example is the cost of solar
11 generation.The cost of PV solar has changed
12 dramatically in the past eight years with reductions of
O 13 60%to 80%according to a recent National Renewable
14 Energy Laboratory study (See:U.S Solar Photovoltaic
15 System Cost Benchmark:Q1 2017).
16 Additionally,as illustrated in Staff witness
17 'Michael Eldred's testimony,there is evidence that the
18 solar projects included in a separate RFP may be lower
19 cost overall than the Combined Projects.If current
20 solar costs continue their downward trend,these projects
21 or ones that are similar may be a better option than the
22 Combined Projects within that ten-year time span.
23 Q.Based on Staff's basis for its position,what
24 does Staff believe is critical?
25 A.Staff believes that a disposition of need for
CASE NO.PAC-E-17-07 1889 LOUIS,M.(Supp)12
04/11/18 STAFF
1 the project which is based on reducing cost to customers
2 when
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
20
2î
22
23
24
25
CASE NO.PAC-E-17-07 1890 LOUIS,M.(Supp)12a
04/11/18 STAFF
1 compared to the base case,needs to have reasonable
2 certainty that the benefits and the costs that form the
3 foundation of the Company's PVRR(d)analysis are actually
4 realized.
5 Staff concedes that natural gas prices and CO2
6 prices are beyond the Company's ability to control once
7 the project is implemented.The Company provided a
8 reasonable risk analysis using 9 different price-policy
9 scenarios taking these factors into account.But even
10 with this analysis,after making corrections for methods
11 that Mr.Eldred believes biased the study,two of the
12 nine price-policy scenarios show negative net benefits
13 posing a risk to customers.
14 In addition,Michael Eldred's testimony
15 illustrates how thin the amount of net benefits are,
16 relative to the overall project cost:a 9.1%capital cost
17 overrun could eliminate any net customer benefits in the
18 medium gas/medium CO2 case.
19 Given that customers are still subject to
20 risks,such as natural gas price and CO2 regulations
21 after the project is implemented,Staff believes it is
22 important that if approval for a CPCN is granted,there
23 needs to be sufficient conditions in place that ensure
24 the Company can implement the project within budget and
O 25 on-time to ensure realization of PTC benefits.With
Staff's proposed
CASE NO.PAC-E-17-07 1891 LOUIS,M.(Supp)13
04/11/18 STAFF
1 conditions,there is a reasonable chance at the outset ofO2projectimplementationthatcustomerswillrealizesome
3 or all of the benefits predicted by the Company,
4 regardless of the Company's project implementation
5 performance.Without these conditions,Staff believes it
6 is less risky to forego the project entirely and move
7 forward with the Company's base case.This forms the
8 basis of Staff's position.
9 III.Conditions Mitigating Project Cost Risk to
10 Ratepayers
11 Q.As a result of Staff's review of the Company's
12 RFP supplemental filings,are there any conditions that
13 Staff proposes to change or modify that were originally
14 proposed in Staff witness Randy Lobb's direct testimony?
15 A.Yes.Staff is proposing to extend the cost cap
16 for transmission capital cost to include all project
17 capital costs to the Company's projected costs,including
18 both wind and transmission.This would place a "hard"
19 cap on the Company's projected capital costs for the
20 combined projects that forms the basis for the Company's
21 PVRR(d)analysis contained in its second supplemental
22 filing.
23 Q.What has changed that has caused Staff to
24 change its position on the cost cap?
25 A.As outlined in Staff witness Michael Eldred's
CASE NO.PAC-E-17-07 1892 LOUIS,M.(Supp)14
04/11/18 STAFF
1 testimony,Staff has discovered additional risks fromO2testimonyincludedintheWyomingCPCNcasethatcould
3 increase the cost of the transmission line and of the
4 wind
5 /
6
7 /
8
9 /
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NO.PAC-E-17-07 1893 LOUIS,M.(Supp)14a
04/11/18 STAFF
1 portion of the project beyond the cost the Company hasO2includedinitseconomicanalysis.Previous Staff
3 testimony and analysis of risk was focused on the
4 Company's benchmark projects which were not the final
5 wind projects that the Company is proposing to implement.
6 The specific wind projects that the Company proposes to
7 implement were only recently determined and included in
8 the Company's supplemental RFP filings.
9 Q.What is the justification for a "hard"cap?
10 A.A "hard"cap puts a ceiling on the amount the
11 Company can recover.As mentioned earlier,the basis for
12 Staff's overall position is that the project is justified
13 on a cost-savings to customers,not a need for capacity
14 to meet load.A hard cap provides a better chance that
15 the project once implemented will ultimately be
16 worthwhile to customers.
17 Per Randy Lobb's testimony,"Staff is concerned
18 that once the Company reaches a point of no return in
19 terms of project investment,transmission costs could
20 escalate in order to finish construction by the PTC
21 deadline."This concern that the rationale for prudence
22 could change in a subsequent proceeding,to minimize
23 losses once most of the investment is made,is extended
24 to the wind facilities now that the specific wind
O 25 projects are known and additional cost risks to the windprojectshavebeenidentified.
CASE NO.PAC-E-17-07 1894 LOUIS,M.(Supp)15
04/11/18 STAFF
1 III.PTC Benefit RiskO2Q.Can you please identify evidence of risk that
3 provides additional justification for mitigating PTC
4 benefit risk?
5 A.Yes.Staff has identified potential delays
6 that were not known at the time of the Company's initial
7 application.In Staff witness Eldred's testimony,he
8 discusses the possibility of delays in environmental
9 permitting establishing the right-of-way for the
10 transmission line and permits for the wind facilities
11 that were discovered in his review of the Wyoming CPCN
12 case.If such delays put the project implementation past
13 the PTC deadline,the amount of PTC benefits could be
14 drastically reduced affecting overall project economics.
15 This makes it imperative that the Company guarantee
16 through conditions in the CPCN that 100%of PTC benefits
17 are credited back to customers regardless of Federal safe
18 harbor eligibility.
19 Q.Does the risk of project delay affect project
20 cost risk providing additional justification for a cost
21 cap?
22 A.Yes.Even though the Commission may authorize
23 a condition guaranteeing full PTC benefits,to finish the
24 project on-time so the Company can qualify for 100%PTC
O 25 benefits to meet safe harbor requirements,the Company
could significantly overspend their capital budget to
CASE NO.PAC-E-17-07 1895 LOUIS,M.(Supp)16
04/11/18 STAFF
1 secure right-of-way and to finish construction on time.
2 This provides additional justification for imposing a
3 hard cost cap on the project.
4 Q.Do you have any other modifications or
5 additions to the conditions already proposed in Staff
6 witness Randy Lobb's testimony?
7 A.No.
8 Q.Does this conclude your supplemental testimony
9 in this proceeding?
10 A.Yes,it does.
11
12
13O14
15
16
17
18
19
20
21
22
23
24
25
CASE NO.PAC-E-17-07 1896 LOUIS,M.(Supp)17
04/11/18 STAFF
1 (The following proceedings were had in
2 open hearing.)
3 MR.KARPEN:With that,I tender the
4 witness for cross-examination.
5 COMMISSIONER ANDERSON:Thank you very
6 much,Mr.Karpen.Mr.Budge.
7 MR.BUDGE:Thank you,Mr.Chairman.
8
9 CROSS-EXAMINATION
10
11 BY MR.BUDGE:
12 Q Good morning,Mr.Louis.
13 A Good morning.
14 Q Could you turn to page 8 of your
15 testimony,please,and beginning on line 19,you have
16 some discussion of the 2017 IRP and you get at the
17 question that Commissioner Raper got at with one of the
18 earlier witnesses relative to when the Company will
19 become capacity deficit,and you testify there that they
20 would first become capacity deficit in 2028.Is there
21 anything that has come about in the course of the hearing
22 of this case that has been presented that would cause you
23 to change that testimony?
24 A No,it would not.
25 Q Do you have an opportunity --strike that.
CSB REPORTING 1897 LOUIS (X)
208.890.5198 Staff
1 I think your testimony was based upon the 2017 IRP as wasO2presentedupuntilthatpointintime.
3 A That's correct.It was based on the 2017
4 IRP and not the update.
5 Q And have you had an opportunity to review
6 the update?
7 A I have reviewed it,not extensively
8 because of the late submission of the update.
9 Q Would you from your review of the update,
10 would that tend to suggest that the need for new
11 resources possibly could even be put back beyond 2028 by
12 reason of forecasted load and forecasted prices being
O 13 reduced?
i
14 A Yes,based on some of the testimony that's
15 been provided today and,subject to check,with regards
16 to the testimony that's been provided by the Company,
17 they basically said that their first combined cycle plant
18 was going to be pushed out beyond the planning horizon,
19 so I would agree with your statement that it has tended
20 to push out the date for the first capacity deficiency.
21 Q Turning to page 8 --excuse me,I think I
22 went the wrong way.At page 11 of your testimony,you
23 have a chart at the top and I think that was a
24 culmination of some of your testimony that began on page
25 8 and the thrust of that testimony,if I understand it,
CSB REPORTING 1898 LOUIS 90208.890.5198 Staff
1 was there's a tendency in long-term resource planning forO2additionalcapacityneedstobepushedoutwitheachnew
3 planning cycle?
4 A It tends to do that,that's correct.
5 Q And your chart on page 11 was an attempt
6 to illustrate that,not only with respect to other
7 utilities,but also PacifiCorp?
8 A That's correct.
9 Q And with the update that was filed May 1st
10 of 2018 on the Company's IRP,would that update be yet
11 another example of new capacity needs being pushed out
12 with each new planning cycle?
13 A Yes,it would.
14 MR.BUDGE:I have no further questions.
15 Thank you.
16 COMMISSIONER ANDERSON:Thank you,
17 Mr.Budge.Mr.Williams.
18 MR.WILLIAMS:Thank you,Mr.Chairman.
19
20 CROSS-EXAMINATION
21
22 BY MR.WILLIAMS:
23 Q Mr.Louis,I had a couple of questions.
24 The first one follows up on Mr.Budge's questions in your
25 testimony on page 8 and there you're asked the question
CSB REPORTING 1899 LOUIS (X)
208.890.5198 Staff
1 about is there sufficient existing transmission capacityO2tomeetloadfortheCompanyusingfrontoffice
3 transactions and,in essence,you say that there is and
4 you also reference the Company's application in E-17-09,
5 which is an application by PacifiCorp for approval of
6 capacity deficit period to be used for calculating
7 avoided costs.Are you familiar with that?
8 A Yes,I am.
9 Q Okay,and on page 3 of that application,
10 in the Company's own words,they say the capacity balance
11 is developed by determining firm resource capacity
12 available at the annual system peak load hour,including
13 the Company's firm access to imports from wholesale
14 markets (front office transactions),and then the
15 application goes on to say the 2017 IRP shows that the
16 Company first becomes capacity deficit in 2018 [sic],so
17 my question is,how do you view the Company's treatment
18 of front office transactions for establishing a capacity
19 deficit date more than 10 years in advance for purposes
20 of setting avoided costs compared to this case where they
21 are attempting to establish a need for resources by
22 discarding front office transactions?
23 A Yes,I believe that it's improper,
24 especially in this case.The way to look at front office
25 transactions,which by the way is how it's viewed for the
CSB REPORTING 1900 LOUIS (X)
208.890.5198 Staff
1 other two electric utilities within the state and how the
2 Commission has basically viewed it,is that we look at
3 available capacity that can come from import capability
4 into the Company's system,and import capability from or
5 i.e.front office transactions comes from a couple of --
6 you know,is basically determined by a couple of things,
7 basically adequate transmission into the system and
8 within the system,as well as market depth and other
9 types of measurements,which by the way,in the 2017 IRP,
10 the Company performed a western resource adequacy
11 evaluation to determine that their assumptions for the
12 amount of FOTs that they can count on for capacity,they
13 verified it using that particular study,so even the
14 Company's IRP basically is counting on some amount of
15 available capacity from imports,and I think from my
16 perspective,if you look at import capability as that
17 infrastructure necessary to bring in electricity,you
18 could basically look at that import capability similar
19 to,like,a gas plant;whereas,the purchases of
20 electricity that flow through that import capability to
21 serve customer load is analogous to natural gas that
22 would flow through that natural gas plant,and so you
23 would not ignore capacity from a natural gas plant to
24 contribute to capacity to meet load and neither should
25 you ignore import capability into the system to
CSB REPORTING 1901 LOUIS (X
208.890.5198 Staff
1 contribute to capacity,so I would answer that in thisO2particularsituation,especially since we're trying to
3 determine need,it speaks to or justification for the
4 project,I think it's very important to include FOTs or
5 import capability as part of the capacity,because it
6 determines whether or not the project is based upon a
7 need for capacity to reliably meet load versus as an
8 economic opportunity,and because it's an economic
9 opportunity,we believe that a cap is justified in order
10 to ensure that customers are not harmed.
11 Q And Mr.Louis,I think you may have
12 incorrectly stated that the capacity date was 2018 and if
13 that was true,didn't you --
14 A Excuse me,that was 2028,I'm sorry.
15 Q Thank you very much,and if could you turn
16 to page 12 of your supplemental testimony and at line 18,
17 you state that if current solar costs continue on their
18 downward trend,these projects or ones that are similar
19 may be a better option than the combined projects within
20 that time frame,and you're familiar with the Company
21 also saying that solar prices look like they're dropping
22 and we should wait.Are you familiar with that?
23 A Yes,I am.
24 Q So in that case,shouldn't that wait also
25 apply to the combined projects?
CSB REPORTING 1902 LOUIS (X
208.890.5198 Staff
1 A Well,in comparison between the two,youO2know,it depends on how your justification --it depends
3 on your justification.
4 Q Let me state it again.If I follow the
5 logical sequence on that,the solar projects and the
6 combined projects are roughly price comparable from a
7 benefit standpoint and if you should wait for one for the
8 prices to drop,shouldn't you wait for the ones right --
9 essentially discard the ones right now and wait for
10 future prices to drop for solar?
11 A Well,I think in this particular situation
12 the wind projects are economical based upon the
13 availability of PTCs,and so you can't really equate the
14 combined projects with the wind and the solar projects.
15 I think my point speaking about lower prices with respect
16 to or declining prices with respect to solar is that if
17 you're looking to fill a need for capacity way out into
18 the future,there are a lot of changes in the energy
19 landscape that could basically skew that calculus,so
20 making a decision now and committing yourself to a
21 long-term resource for a capacity deficit that doesn't
22 occur for 10 plus years,you run the risk of another
23 resource basically becoming more economical in that time
24 frame,and so if you waited to make that decision,the
25 alternative resource,example would be solar,is that it
CSB REPORTING 1903 LOUIS (X
208.890.5198 Staff
1 would be a least cost resource when you actually neededO2tomeetthatcapacity.
3 MR.WILLIAMS:No further questions.
4 COMMISSIONER ANDERSON:Thank you,
5 Mr.Williams.Mr.Olsen.
6 MR.OLSEN:Yes,thank you,Chair.
7
8 CROSS-EXAMINATION
9
10 BY MR.OLSEN:
11 Q Mr.Louis,could you turn to pages 5 and 6
12 of your supplemental testimony,specifically page 6,line
13 16,and I'm just going to pick up on stuff that you've
14 touched on here,but beginning on line 16,you're just
15 making the distinction that the justification for this
16 project is different in that it's based on economic
17 factors,so I'll point that out,but if you could turn to
18 page 5,beginning on line 16,you talk about what I would
19 say the typical case would be when you're looking at
20 projects for new generation like we're doing here,and
21 you state there at the bottom,it says,"Staff believes
22 that the proper analysis is to compare a sufficient
23 number of different types of viable load serving
24 alternatives against each other so that a least cost,
25 least risk alternative can be authorized";so isn't it
CSB REPORTING 1904 LOUIS (X)
208.890.5198 Staff
1 fair to say that the analysis in this case didn't look atO2abroadswathofavailablealternatives,it was very
3 narrow and the RFP said wind in Wyoming as opposed to,
4 you know,all other potential alternatives?
5 A Yeah,I think your question basically
6 speaks to the type of justification for this particular
7 project.If this was a project to meet capacity needs to
8 reliably meet load,the proper analysis would be to
9 present as many alternatives as you possibly could that
10 are viable to meet that capacity need,and you would want
11 to compare those on a head-to-head basis,but the
12 Company's case in this particular situation and the way
13 that they've approached the case is as an economic
14 opportunity,and so the way that they've presented this
15 is,is it more viable than basically their existing
16 system or existing system as a base case,especially
17 within the next or until the capacity is actually needed
18 and so,you know,it basically speaks to the
19 justification more than anything.
20 MS.OLSEN:No further questions.
21 COMMISSIONER ANDERSON:Thank you,Mr.
22 Olsen.
23 COMMISSIONER ANDERSON:Ms.McDowell.
24
25
CSB REPORTING 1905 LOUIS (X)
208.890.5198 Staff
1 CROSS-EXAMINATIONlill2
3 BY MS.McDOWELL:
4 Q Good morning,Mr.Louis.
5 A Good morning.
6 Q Can you turn to page 14 of your testimony,
7 please?
8 COMMISSIONER KJELLANDER:Supplemental or
9 direct?
10 MS.McDOWELL:Mr.Louis'confidential
11 supplemental testimony at page 14.
12 COMMISSIONER KJELLANDER:Thank you.
13 Q BY MS.McDOWELL:Do you have that,Mr.
14 Louis?
15 A Yes,I do.
16 Q And there under subheading III,you
17 discuss the change in Staff's position,and I'll just
18 summarize this and you can tell me if it's a fair
19 summary,extending the proposed hard cost cap from
20 transmision costs only to the entire project costs,
21 including the wind project costs,is that a fair summary
22 of your testimony in that first Q&A there?
23 A It is.
24 Q And then at the bottom of that page,
25 beginning on line 20,you explain what has caused Staff
CSB REPORTING 1906 LOUIS (X)
208.890.5198 Staff
1 to change its position.Do you see that question?O 2 A Yes,I do.
3 Q And there you refer to Mr.Eldred's
4 testimony about the additional risks from the testimony
5 included in the Wyoming CPCN case,and just to clarify,
6 that's the testimony of Mr.Wurdack that we were speaking
7 about with Mr.Eldred earlier this morning?
8 A That's correct.
9 Q And is it your understanding based on that
10 colloquy that the Company settled with Anadarko?
11 A That's correct.
12 Q And that that testimony was never
13 presented to the Commission in that case?
14 A Yes,that's correct,but referring back to
15 Staff witness Eldred,he did say that some of those
16 reasons behind that settlement he's not aware of,and so
17 we basically still believe that there is a cost risk and
18 that this is basically justification for a cost cap,and
19 so the cost cap is basically --the justification for the
20 cost cap is because of the justification for the project,
21 which is based on economic viability.
22 Q But I'm asking really about your question
23 here that what caused you to expand your cost cap from
24 just transmission to transmission and wind,and you
25 identified the issues that Mr.Eldred discussed this
CSB REPORTING 1907 LOUIS (X)
208.890.5198 Staff
1 morning about the Anadarko position on split-estates,andO2thenthesecondissuewastheconcernthattheremightbe
3 a supplemental EIS required;do you recall that?
4 A Yes,I do.
5 Q And that issue has been resolved?
6 A This is my understanding as well,yes.
7 MS.McDOWELL:That's all I have.Thank
8 you.
9 COMMISSIONER ANDERSON:Thank you.
10 Commissioner questions?
11
12 EXAMINATION
13
14 BY COMMISSIONER RAPER:
15 Q Good almost afternoon,Mr.Louis.
16 A Good morning,Commissioner,or good
17 afternoon or whatever we want to call it at this point.
18 Q I'm going to try and ask you more artfully
19 than I did Mr.Eldred.You've already stated that this
20 is an economic opportunity for the Company and not a
21 reliability issue.
22 A That is my belief,yes.
23 Q So then the balance of risk that the
24 Company ought to take on is different,because it's an
25 economic opportunity and not to meet a reliability
CSB REPORTING 1908 LOUIS (Com)
208.890.5198 Staff
1 need?O 2 A I believe that the risk,that the Company
3 should bear more of the cost risk.As long as the
4 Company can deliver on its project as it's intended,I
5 believe that the Company bears the risk of not harming
6 customers because it is an economic opportunity.
7 Q And clearly,Staff within the settlement
8 stip took a position different from the Company on hard
9 cap for the costs,but what do you think,then,about
10 Mr.Yankel's testimony to let the utility build it and
11 then let them come in for recovery?How do you see the
12 balance of risk on just allowing the Company to build,
13 because it may not be a necessity,there's not a need
14 there,versus imposing a hard cap for the costs
15 associated with the build?
16 A Okay,this is a really good question.
17 Q Thank you.
18 A I think that it really speaks to the
19 importance of differentiating operational prudence from
20 decisional prudence,okay,so our attorney Mr.Karpen
21 brought that up in testimony yesterday as a question,but
22 the importance of that is that there's a distinct
23 difference and I think it needs to be considered whenever
24 we talk about prudence.The Company tends to want to
25 lump prudence together,but there is really two different
CSB REPORTING 1909 LOUIS (Com)
208.890.5198 Staff
1 types of prudence that you need to look at,and from a --O 2 so what we're doing today is basically determining the
3 prudency of the project to move forward,okay,which is
4 decisional prudence,which is based on need and,
5 obviously,the questions and what's being discussed in
6 this case have to do with whether it's needed or not for
7 capacity,and if it's not needed for capacity,it's an
8 economic opportunity,which basically plays into whether
9 or not a cap is needed,and a cap to me,a hard cap,is a
10 tool that the Commission can use to basically ensure
11 decisional prudence,and so once the decision is made,
12 then we get into the realm of operational prudence and
13 the criteria that's used for determining operational
14 prudence is much different.
15 Once that decision is made,it moves
16 towards how effectively or efficiently did the Company
17 implement the project,and so when you start talking
18 about that type of criteria to determine,you know,
19 basically non-recovery of certain costs,you're talking
20 about did the Company do it in the most efficient or
21 effective manner,and it's very difficult,then,to go
22 back once that decision is made and do a --basically not
23 allow the Company to recover expenses based on decisional
24 prudence criteria,which is being talked about today,so
25 I think it's very important that once we get to this
CSB REPORTING 1910 LOUIS (Com)
208.890.5198 Staff
1 point,the cap is basically to help ensure decisional
2 prudence,and once you get past that point,what we're
3 talking about is essentially how effectively the Company
4 can implement the project,so hopefully,that helps.
5 COMMISSIONER RAPER:That helps.That's
6 all I have.Thank you.
7 THE WITNESS:You're welcome.
8 COMMISSIONER ANDERSON:Mr.Karpen,any
9 redirect?
10 MR.KARPEN:Yes.
11
12 REDIRECT EXAMINATION
13
14 BY MR.KARPEN:
15 Q Mr.Louis,the Company asked you about the
16 risks that Mr.Eldred brought up in his testimony,more
17 specifically I'd like to ask you,did you participate in
18 the settlement negotiations between the Company and
19 Anadarko?
20 A I did not.
21 Q Do you know what the conditions of that
22 settlement were?
23 A I do not.
24 Q Do you know if that settlement resolved
25 the issues that were presented by Anadarko?
CSB REPORTING 1911 LOUIS (ReDi)
208.890.5198 Staff
1 A The specific issues,I do not.O 2 Q Thank you.On page 13 to 14 of your
3 testimony,at the very bottom you state,"With Staff's
4 proposed conditions,there is a reasonable chance at the
5 outset of project implementation that customers will
6 realize some or all of the benefits predicted by the
7 Company,regardless of the Company's project
8 implementation performance."
9 A Excuse me,are you on page 13?
10 Q It's at the very last.It starts on 13,
11 but it bleeds into 14.
12 A Okay.
13 Q It starts with "With."
14 A Gotcha,okay.
15 Q It says,"With Staff's proposed
16 conditions,there is a reasonable chance at the outset of
17 project implementation that customers will realize some
18 or all of the benefits predicted by the Company,
19 regardless of the Company's project implementation
20 performance."When you say that,do you mean as far as
21 Staff conditions,the imposition of an overall capital
22 cost cap?
23 A So it's not only the cost cap,but it's
24 also the guarantee on the PTC benefits being imputed
25 that's in the stipulation.
CSB REPORTING 1912 LOUIS (ReDi)
208.890.5198 Staff
1 Q Yes,that was my next question.TheO2imputationofthePTCshavebeenagreedtoalready;is
3 that correct?
4 A That's correct.
5 MR.KARPEN:I have no further questions
6 for this witness.
7 COMMISSIONER ANDERSON:Thank you very
8 much,Mr.Karpen.Thank you,Mr.Louis.
9 THE WITNESS:You're welcome.
10 (The witness left the stand.)
11 COMMISSIONER ANDERSON:Well,it would
12 appear that we've exhausted the witness list --excuse
13 me,Terri.Terri,before you come up,I think we're
14 going to take a five-minute break,because I'm out of
15 order,so five-minute break.
16 (Recess.)
17 COMMISSIONER ANDERSON:Before Staff
18 continues with their next witness,we do have one
19 Commissioner that has to depart at about five minutes to
20 noon for a teleconference call,so if we're not finished
21 by then,we will have to go after lunch and do all of
22 that,so just be mindful of that and I want to make sure
23 that we get all the comments made and all the cross made,
24 so go ahead and continue,Mr.Karpen.
25 MR.KARPEN:Thank you for that and we
CSB REPORTING 1913 LOUIS (ReDi)
208.890.5198 Staff
1 anticipate our final witness being done by noon,well
2 done before noon.Staff calls Terri Carlock.
3
4 TERRI CARLOCK,
5 produced as a witness at the instance of the Staff,
6 having been first duly sworn to tell the truth,was
7 examined and testified as follows:
8
9 MR.KARPEN:I would beg the Chair for
10 some latitude,we do anticipate asking some live direct
11 questioning with regard to the stipulation as the other
12 witnesses have considering its late-filed status.
13 COMMISSIONER ANDERSON:Okay.
14
15 DIRECT EXAMINATION
16
17 BY MR.KARPEN:
18 Q Can you please state your name and spell
19 your last name for the record?
20 A Terri Carlock,C-a-r-1-o-c-k.
21 Q Can you please state how you are
22 employed?
23 A I'm employed by the Idaho Public Utilities
24 Commission as the utilities division administrator.
25 Q Are you the same Terri Carlock who filed
CSB REPORTING 1914 CARLOCK (Di
208.890.5198 Staff
1 settlement testimony on May 10th,2018?O 2 A I am.
3 Q Do you have any additions or corrections
4 to make to that testimony?
5 A No,I do not.
6 Q If I asked you those same questions today
7 as they're presented in that testimony,would you respond
8 the same?
9 A Yes,I would.
10 MR.KARPEN:With that,I move that
11 Ms.Carlock's testimony be spread upon the record as if
12 read directly.
13 COMMISSIONER ANDERSON:Without objection,
14 we'll spread Ms.Carlock's testimony across the record as
15 if read.
16 (The following prefiled settlement
17 testimony of Ms.Terri Carlock is spread upon the
18 record.)
19
20
21
22
23
24
25
CSB REPORTING 1915 CARLOCK (Di
208.890.5198 Staff
1 Q.Please state your name and address for the
2 record.
3 A.My name is Terri Carlock.My business address
4 is 472 West Washington Street,Boise,Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as the Utilities Division Administrator.
8 Q.Please outline your educational background and
9 experience.
10 A.I graduated from Boise State University in
11 1980,with B.B.A.Degrees in Accounting and Finance.I
12 have attended various regulatory,accounting,rate of
13 return,economics,finance,and ratings programs.SinceO14joiningtheCommissionStaffinMay1980,I have
15 participated in audits,performed financial analysis on
16 various companies,participated in numerous proceedings,
17 and have presented testimony before this Commission.
18 Q.Please describe the scope of your
19 responsibilities in the preparation of this case.
20 A.I am responsible for coordination of Staff
21 positions.I acted as the Staff lead in the Settlement
22 discussions and am presenting the testimony in support of
23 the Stipulation filed with the Commission on May 8,2018
24 between the Company and Commission Staff in this
25 proceeding.The Stipulation recommends a Certificate of
CASE NO.PAC-E-17-07 1916 CARLOCK,T (Di)1
05/10/2018 STAFF
1 Convenience and Necessity (CPCN)be issued and resolvesO2allbutoneissuebetweentheCompanyandStaff.Staff
3 believes the Stipulation provides benefits for Idaho
4 customers by mitigating risk factors and limiting costs
5 to be paid by customers in rates.
6 Q.Please identify the final projects covered by
7 the Stipulation.
8 A.The final projects include transmission and new
9 wind projects.The transmission project covers the
10 Aeolus-to-Bridger/Anticline 500 kV transmission line and
11 the New Wind projects include the Ekola Flats,TB Flats I
12 and II,and Cedar Springs wind projects.Together they
13 are referred to as the Stipulated Projects.
14 Q.Please explain the benefits provided by the
15 Stipulation Provisions.
16 A.Every provision in the Stipulation is important
17 but I will summarize and discuss three main categories
18 that create customer benefits:
19 The Resource Tracking Mechanism (RTM)
20 Limitations cover many provisions limiting
21 risks and costs.
22 The Production Tax Credit (PTC)Guarantees
23 assure savings flowing from Federal Tax
24 Incentives are realized by customers.
25
CASE NO.PAC-E-17-07 1917 CARLOCK,T (Di)2
05/10/2018 STAFF
1 The Operational Guarantees reduce the riskO2ofnotgeneratingpowerforuseinthesystem,
3 off-system sales,and the receipt of PTCs based
4 on full generation capabilities.
5 Q.Please explain the Resource Tracking Mechanism
6 and the limitations imposed in the Stipulation.
7 A.The RTM is the same mechanism authorized in
8 Order No.33954 on the Repowering Projects for existing
9 wind sites in Case No.PAC-E-17-06.The Stipulated
10 Projects in this agreement have more limitations imposed
11 in the RTM and will be tracked separately from the
12 Repowered Projects.The greater limitations are
13 important because the Stipulated Projects are based on
14 economics rather than a need for generation and capacity.
15 Other Staff witnesses provide this analysis in their
16 testimonies.
17 To reduce risks that the Stipulated Projects
18 fail to provide an economic benefit for customers,the
19 capital costs that will be tracked in the RTM are limited
20 to the construction cost estimate of (redacted),as
21 provided in the Company's Second Supplemental Direct
22 Testimony.Further,the annual actual costs will be
23 capped at the annual benefit amount for the Stipulated
24 Projects in the RTM and the Energy Cost Adjustment
25 Mechanism (ECAM).Any dollar amounts expended above
CASE NO.PAC-E-17-07 1918 CARLOCK,T (Di)3
05/10/2018 STAFF
1 these caps must be justified by the Company and deemedO2prudentbytheCommissioninageneralratecasebefore
3 being included in customer rates.The Company will
4 include 100%of the benefits from the Stipulated Projects
5 in the RTM and ECAM mechanisms.Additionally,in
6 recognition of receiving timely investment recovery
7 through the RTM and ECAM,the Company will provide
8 $300,000 annually in a Regulatory Liability account from
9 the first Stipulated Project in-service date until the
10 next general rate case.The continued use of the RTM will
11 be re-evaluated in the next general rate case following
12 project in-service dates.
13 Q.Please explain the Production Tax Credit
14 Guarantees.
15 A.The Company will bear the risk of any portion
16 of the wind projects that do not qualify for PTCs.
17 Receiving 100%of the PTCs are a critical and required
18 component for these Stipulated Projects to be economic.
19 If the full amount of PTCs are not received,the Company
20 will impute the PTCs to each project as if received based
21 on actual production levels for each project.
22 Q.Please explain the operational guarantees.
23 A.The Company will negotiate availability
24 guarantees for the Wind Projects in any third-party
25 provided maintenance contracts,as provided by the
CASE NO.PAC-E-17-07 1919 CARLOCK,T (Di)4
05/10/2018 STAFF
1 competitive market at 97 percent available generation.
2 All liquidated damages received by the Company for these
3 projects will be passed onto customers in the ECAM.
4 Q.You previously stated that this Stipulation
5 resolves all but one issue between the Company and the
6 Commission Staff.Please identify the remaining issue,
7 why it is important,and briefly state Staff's position.
8 A.The only issue not resolved between the Company
9 and Commission Staff in the Stipulation relates to an
10 overall cost cap.Staff believes an overall Hard Cap is
11 necessary to reduce the risk that these economic projects
12 do not provide benefits to customers.Staff proposed a
13 Hard Cap at the combined construction estimates of
14 (redacted)as identified in the Company's Second
15 Supplemental Direct Testimony.
16 This is the same cap agreed to in the
17 Stipulation for the RTM.The economic margins are
18 limited and fairly slim as shown in Staff witness
19 Eldred's Confidential Exhibit No.104.As stated
20 previously,these narrow margins make a Hard Cap
21 essential to increase the probability that the Stipulated
22 Projects are prudent resources that are developed at a
23 reasonable and economic cost.
24 The Company has proposed a soft cap.Staff
25 believes a soft cap is inadequate and recommends the
CASE NO.PAC-E-17-07 1920 CARLOCK,T (Di)505/10/2018 STAFF
1 Commission adopt a Hard Cap for the Stipulated Projects.
2 A soft cap is inadequate because,in spite of the "cap"
3 moniker,it is in reality just standard ratemaking
4 practice.The Stipulated Projects are recommended based
5 on the economics of these discretionary projects.The
6 Staff and Intervening Parties each testify to the lack of
7 need and economic justifications of the projects.To
8 maintain a reasonable probability that the Stipulated
9 Projects will be economic,Staff believes a Hard Cap is
10 required and is confident the Commission will also
11 identify the need for a Hard Cap.
12 Q.Does this conclude your direct testimony in
13 this proceeding?
14 A.Yes,it does.
15
16
17
18
19
20
21
22
23
24
25
CASE NO.PAC-E-17-07 1921 CARLOCK,T (Di)6
05/10/2018 STAFF
1 (The following proceedings were had inO2openhearing.)
3
4 DIRECT EXAMINATION
5
6 BY MR.KARPEN:(Continued)
7 Q Ms.Carlock,put simply,do you believe
8 that the stipulation as presented is in the public
9 interest?
10 A Yes,I do.
11 Q Monsanto's expert Nick Phillips expressed
12 some skepticism in the PTC guarantees that they provide a
13 meaningful benefit to customers.Do you agree with that
14 assessment?
15 A I believe that the stipulation provides
16 benefits for and restrictions on the outcome of PTCs.It
17 does not address will the wind blow,but beyond the
18 question of will the wind blow,I believe it is adequate
19 to protect the customers from the Company not receiving
20 PTCs.
21 Q There's also been some questions,I
22 believe,that have been spurred by the Irrigators'expert
23 Mr.Yankel with regard to allowing the Company to go
24 ahead with the project and come back in for prudency at a
25 later time.In comparison with the stipulation,do you
CSB REPORTING 1922 CARLOCK (Di)
208.890.5198 Staff
1 believe that is a wise course for the Commission to
2 take?
3 A I do not believe it is the best course for
4 the Commission to take,because this is an economic
5 project,and that with this economic project,as with
6 others,there are benefits that are going to flow through
7 the ECAM,and I personally do not want to try to break
8 those benefits out because we haven't matched the costs
9 with them.I believe the stipulation caps the cost at
10 the benefits and it is a reasonable outcome for customers
11 so that we should look at matching those as well looking
12 at the economic analysis for these projects themselves.
13 Because it is an economic analysis,you do have to lookO14atitdifferentlyandthatiswhytheStaffisalso
15 proposing a hard cap.
16 Q Great;so to be clear,you do believe that
17 there are still risks associated with the stipulated
18 projects?
19 A There are risks associated with the
20 stipulated projects,yes.That's why Staff believes that
21 the stipulation is in the best interest,because if you
22 grant a certificate and then wait,you are not providing
23 these limitations that would be in the stipulation.
24 Q Do you believe there are any other ways
O 25 that these outstanding risks can be mitigated,for
CSB REPORTING 1923 CARLOCK (Di)
208.890.5198 Staff
1 example,the imposition of an overall capital hard cap?
2 A As I stated earlier,a hard cap in my mind
3 is necessary because these are economic projects,and as
4 Cindy Crane mentioned,they are reducing other costs,and
5 so we want to make sure that those economics are actually
6 occurring.
7 Q Compared to other capital projects that
8 come before the Commission on a regular basis,what makes
9 this project different to the point that a hard cap is
10 appropriate?
11 A We are usually looking at projects that
12 are based on a need for a new generating unit that would
13 address growth or replacement of a different unit,that
14 type of thing,so it's a reliability need,not an
15 economic need,so that's why this project is different in
16 my opinion.
17 Q Can you please refer to Staff Exhibit 104
18 as provided through Mr.Eldred's testimony?
19 A Okay.
20 Q Noting that it's confidential,so if you
21 can maybe refer to the price policy scenarios rather than
22 the actual numbers.
23 A Yes.
24 Q Do you have an opinion where a hard cap
25 should be set and why?
CSB REPORTING 1924 CARLOCK (Di)
208.890.5198 Staff
1 A The hard cap that Staff is recommending
2 doesn't actually show up on this schedule,because we
3 were recommending it be at the construction cost estimate
4 of the second supplemental testimony that the Company has
5 filed,and that's consistent with what we have negotiated
6 as the cap in the RTM.Looking at Exhibit 104,though,
7 you can look at the various scenarios and whether there
8 is a benefit or not having a benefit and there are seven
9 of the nine scenarios where under the Company's
10 assumptions,there are benefits,so as long as the
11 Company is capped of not going outside of these benefits,
12 I think there's a good chance that customers will receive
13 those benefits.The two scenarios that there are not
14 benefits in may not be long-term scenarios in my
15 opinion.
16 Q So to be clear,even if we tap the
17 costs --excuse me,even if the Commission were to cap
18 the costs at the Company's estimates,customers would
19 still bear risk that they will not see benefits from the
20 projects?
21 A There are some risks,particularly in the
22 two scenarios,yes.
23 MR.KARPEN:Thank you.That concludes my
24 direct.I will now tender this witness for cross.
25 COMMISSIONER ANDERSON:Thank you,Mr.
CSB REPORTING 1925 CARLOCK (Di)
208.890.5198 Staff
1 Karpen.Mr.Budge.
2 MR.BUDGE:Thank you,Mr.Chairman.
3
4 CROSS-EXAMINATION
5
6 BY MR.BUDGE:
7 Q Just a couple of questions,if I may,
8 Ms.Carlock.Just as a follow-up on questions from
9 Mr.Karpen,you testified about the cap and how it would
10 provide protection on capital cost overruns,but that
11 there are still some risks and I think that gets to the
12 point that Commissioner Kjellander made earlier that we
13 can't control all risks.The Staff settlement
14 stipulation doesn't make an effort to control the other
15 risks which you commented on with respect to the two gas
16 scenarios that the customers are at risk of price
17 increases and,also,the risk relative to wind,whether
18 it blows or the timing is off,that settlement doesn't
19 address those;correct?
20 A That's correct,for the most part.
21 Q So those two risks that remain with the
22 customers,are those in fact risks that the intervenors
23 were attempting to address with respect to the
24 recommendations in their testimony?
25 A If I interpret the testimony of the
CSB REPORTING 1926 CARLOCK (X)
208.890.5198 Staff
1 intervenors correctly,I believe that is true.
2 Q And that would have been one of the
3 fundamental differences with respect to which the
4 intervenors had as we had settlement negotiations?
5 A It's my understanding from the testimony
6 filed from the intervenors that they're recommending that
7 no CPCN be granted in order to mitigate that risk,and I
8 personally believe there are some benefits of the project
9 that I would like to capture and,therefore,went forward
10 with the stipulation.
11 Q Right,the intervenors'position is that
12 there was no necessity and we shouldn't have the project
13 at all and that it's not least cost --
14 MR.KARPEN:I'm going to object.I
15 believe that the intervenors'testimony speaks for
16 itself.Ms.Carlock can speak to the settlement as was
17 entered into.
18 MR.BUDGE:I would agree.It was just
19 preliminary to asking a question.
20 Q BY MR.BUDGE:But the question I had
21 asked you on the conditions was the testimony that said
22 if in fact the projects were granted,then these are the
23 list of conditions we feel are appropriate,and I think
24 if I understand your answer correctly,you were simply
25 saying yes,that was the intervenors'attempt to get at
CSB REPORTING 1927 CARLOCK (X)
208.890.5198 Staff
1 these additional risks that are not mitigated by the
2 settlement --
3 MR.KARPEN:Again,I believe Mr.Budge is
4 testifying as to his client's position and not asking a
5 question of my witness on the settlement which she's
6 testifying to.
7 COMMISSIONER ANDERSON:Latitude --
8 MR.BUDGE:Let me rephrase it.I was not
9 testifying at all.I was simply asking a
10 cross-examination question to clarify the witness'
11 testimony,but let me just rephrase it.
12 Q BY MR.BUDGE:So you recognize that the
13 intervenors'position is that the project should not be
14 approved at all from their testimony;correct?
15 A I understand where the position of the
16 intervenors are,I believe.
17 Q And I think you would recall from your
18 review of the intervenors'testimony that there was also
19 additional testimony that said if the projects were to be
20 approved,here are the conditions we think would be
21 appropriate;do you recall that testimony?
22 A There is testimony that talk about
23 additional conditions,yes.
24 Q So it was those additional conditions
25 should the project be approved that attempted to get
CSB REPORTING 1928 CARLOCK (X
208.890.5198 Staff
1 these additional risks that were not addressed by Staff'sO2recommendedhardcaponcapitalcostsonly;would that be
3 correct?
4 A There are additional conditions that were
5 recommended that are not addressed in a hard cap,but I'm
6 not sure that I would agree with all of those additional
7 conditions.
8 Q I appreciate that.One other question,if
9 I understand correctly,as the Staff was trying to
10 negotiate this settlement agreement that was arrived at,
11 you had had an opportunity to review and consider some of
12 the settlement terms that were in the settlement
13 agreement in Wyoming with WIEC,I believe?
14 A I did not look at the settlement terms of
15 the Wyoming stipulation.I know what some of them were,
16 but I did not review that.
17 Q In this case,we had some testimony about
18 the differences in Wyoming in that they had some of the
19 economic benefits and those types of things.To your
20 knowledge,would the Wyoming stipulation be different in
21 the sense that it resolved not simply one case like we
22 have here,but there were three cases that were all part
23 of that settlement,if you know?
24 A It's my understanding that some of the
25 parties agreed to a stipulation that was associated with
CSB REPORTING 1929 CARLOCK (X)
208.890.5198 Staff
1 three cases,yes.I do believe that not all parties
2 agreed to every component of that.That's why there's
3 three separate stipulations.
4 MR.BUDGE:That's all I had.Thank you
5 very much.
6 COMMISSIONER ANDERSON:Thank you,Mr.
7 Budge.Mr.Williams.
8 MR.WILLIAMS:Mr.Chairman,thank you.
9
10 CROSS-EXAMINATION
11
12 BY MR.WILLIAMS:
13 Q Ms.Carlock,I have a couple of questions.
14 If you would look at your testimony on page 3,line 12,
15 you make the statement,"The greater"--you're talking
16 about --well,it doesn't matter what you're talking
17 about.You say,"The greater limitations are important
18 because the stipulated projects are based on economics
19 rather than a need,"and when I read Idaho Code section
20 61-526,it says the Commission will grant a
21 certificate --
22 MR.KARPEN:I object to this question.
23 It calls for the witness to make a legal conclusion.
24 MR.WILLIAMS:Well,she's already made a
25 legal conclusion on your first question when you asked
CSB REPORTING 1930 CARLOCK (X)
208.890.5198 Staff
1 her if she thought this was in the public convenience and
2 necessity.
3 COMMISSIONER ANDERSON:I'm going to let
4 it continue and give it the weight that we can
5 consider.
6 Q BY MR.WILLIAMS:So my question is if you
7 think it meets the statutory standard --well,first of
8 all,do you think it meets the present or future need for
9 convenience?
10 A I think for convenience,I think it meets
11 a future need,but for economics,I believe it meets a
12 current need and that is that whether you're looking at
13 the IRP,whether you're looking at risk analysis,whether
14 we're looking at general rate cases,my goal is always to
15 try to develop the least cost,least risk scenarios and
16 then also to manage that after those analyses have been
17 completed so that customers are paying the lowest rates
18 possible within that risk analysis.
19 Q So how do you square that answer with your
20 testimony that says it's based on economics rather than a
21 need?
22 A I square that because I am looking at the
23 need for generation and capacity as being in the future
24 and not immediate because of front office transactions
25 and that the economics are associated with the dispatch
CSB REPORTING 1931 CARLOCK (X)
208.890.5198 Staff
1 of the resources,including front office transactions,
2 and where customers may benefit from greater economics by
3 having these projects allowed.These projects are not
4 something you can decide to do two,three years down the
5 road.There is limitations on when the PTCs must be
6 utilized;therefore,these projects are a reasonable
7 opportunity to take advantage of those PTCs,providing
8 there are limitations and a hard cap so that the
9 economics actually develop,but also to recognize that
10 there are some other items that these projects might also
11 reflect a benefit from,such as the transmision.
12 Q So do you think a future need that is
13 identified as being 35 years out would qualify for a
14 certificate?
15 A No,we're not looking at 35 years out,for
16 one thing.We're looking at a potential of generation of
17 2028 or 2029 and we're looking at the potential of
18 transmision for 2024,and the project completions would
19 be by December 31st of 2020 and economics are always
20 going on.
21 Q So this is justified on economics rather
22 than,in your words,need for generation?
23 A In my mind it is,yes.
24 Q Is economics more of a convenience or is
25 it a need for generation?
CSB REPORTING 1932 CARLOCK (X)
208.890.5198 Staff
1 A I think there is a cross-over to some of
2 that.It's more of a convenience.It's more of
3 efficiency.It's more of what other options are now
4 available in order to better manage and better dispatch
5 the resources that the Company owns or the front office
6 transactions that they have available to it,so there's a
7 combination.To say that there is a generation need,no,
8 there isn't at this point in time,because the Company
9 can manage the system with front office transactions;
10 however,if you could manage the system at a lower cost
11 provided that you've got an economic project in place,
12 then you should consider that.
13 MR.WILLIAMS:No further questions.
14 COMMISSIONER ANDERSON:Thank you,
15 Mr.Williams.Mr.Olsen.
16 MR.OLSEN:No questions.
17 COMMISSIONER ANDERSON:Thank you.Does
18 the Company have questions?
19 MS.McDOWELL:No questions.Thank you.
20 COMMISSIONER ANDERSON:Thank you.
21 Commissioner Raper.
22
23
24
25
CSB REPORTING 1933 CARLOCK (X)
208.890.5198 Staff
1 EXAMINATION
2
3 BY COMMISSIONER RAPER:
4 Q Good afternoon.
5 A Good afternoon,almost.
6 Q I am just wondering about the 2017
7 capacity deficit that I believe it was the Company
8 witness Mr.Link was speaking to versus the 2028,which
9 we're all aware is in their IRP.In your opinion,is it
10 fair for the Company to utilize 2028 for purposes of,
11 say,PURPA projects and when they're paid capacity,but
12 then say well,but if we don't include these,because to
13 my knowledge,front office transactions are included in
14 the estimation of when capacity payments ought to be paid
15 in that scenario,but then for their own purposes,for
16 their own projects when they see an economic opportunity,
17 they choose an earlier date and say well,but without
18 those,we're here and utilize that as a justification for
19 the accrual of expenses for building these projects.
20 A I see that as part of that cross-over,
21 also,that you're looking at a need that may be further
22 out,but if you can economically replace a current
23 operation,then that brings it forward,because front
24 office transactions are not owned entities,so if you're
25 looking at reliability,that type of thing based on owned
CSB REPORTING 1934 CARLOCK (Com)
208.890.5198 Staff
1 resources at this point in time,but everybody recognizes
2 that there are markets out there,they're efficient
3 markets and you should evaluate what you're going to do
4 based on using those efficient markets,so yes,there is
5 some inconsistency in how some of these markets might be
6 reflected in the way that is viewed for different
7 pricing,such as the capacity payments for QFs.
8 COMMISSIONER RAPER:Thank you.
9 COMMISSIONER ANDERSON:Redirect?
10 MR.KARPEN:I have no redirect.Staff
11 rests.
12 (The witness left the stand.)
13 COMMISSIONER ANDERSON:So if the Chair
14 stays in order,I believe we have exhausted the witness
15 list.At this point,though,I do want to give an
16 opportunity to call any other witnesses,re-call any
17 witnesses.
18 MS.McDOWELL:None from the Company.
19 Thank you.
20 COMMISSIONER ANDERSON:And does the
21 Company wish --are there any other comments the Company
22 wishes to make?
23 MS.McDOWELL:The Company at this point
24 does not intend to call any rebuttal witnesses.
25 COMMISSIONER ANDERSON:Thank you.I'm
CSB REPORTING 1935 CARLOCK (Com)
208.890.5198 Staff
1 getting some help because I'm new and I appreciate the
2 help.I just want to do a couple other clean-up things
3 here.Under Rule 164 allows for 14 days to apply for
4 intervenor funding.I anticipate that there may be one
5 party that wishes to do that.By my read on the
6 calendar,that makes May 15th the cutoff date,subject to
7 check on that.
8 COMMISSIONER RAPER:Fourteen days?
9 MR.KARPEN:The 25th,I believe.
10 COMMISSIONER ANDERSON:The 25th.
11 MR.KARPEN:May 25th.
12 COMMISSIONER ANDERSON:What did I say?
13 MR.KARPEN:15th.
14 COMMISSIONER ANDERSON:Well,it's kind of
15 hard to do the 15th.That was subject to check.Thank
16 you.I want to thank our court reporter today for her
17 work and I also want to thank all the parties for their
18 development of a good record.A lot of things went on in
19 this case.It was a load for the Commission,too,a lot
20 of things to follow and I just appreciate everybody's
21 attendance.
22 At this point we'll consider the record
23 fully developed and I just want to make one more notation
24 here.If I've overlooked the admission of any additional
25 exhibits that were previously identified in this matter,
CSB REPORTING 1936 COLLOQUY
208.890.5198
1 they are now hereby admitted pursuant to Rule 267,and
2 with that,we are adjourned and thank you.
3 (All exhibits previously marked for
4 identification were admitted into evidence.)
5 COMMISSIONER ANDERSON:Oh,excuse me,Mr.
6 Budge.
7 MR.BUDGE:I may have missed it,but was
8 all testimony and exhibits of all parties deemed
9 admitted?
10 COMMISSIONER RAPER:He just finished
11 saying that.
12 MR.BUDGE:Okay.
13 COMMISSIONER ANDERSON:I probably should
14 have said that prior to --I lost it and then I came back
15 to it,so I apologize for that.
16 MR.BUDGE:Thank you.
17 COMMISSIONER ANDERSON:So now at this
18 point we are adjourned.
19 (The Hearing adjourned at 11:45 a.m.)
20
21
22
23
24
25
CSB REPORTING 1937 COLLOQUY
208.890.5198
1 A UTHENT I C A T I ONO2
3
4 This is to certify that the foregoing
5 proceedings held in the matter of the application of
6 Rocky Mountain Power for a certificate of public
7 convenience and necessity and binding ratemaking
8 treatment for new wind and transmission facilities,
9 commencing at 9:30 a.m.,on Thursday,May 10,and
10 continuing on Friday,May 11,2018,at the Commission
11 Hearing Room,472 West Washington Street,Boise,Idaho,
12 is a true and correct transcript of said proceedings and
13 the original thereof for the file of the Commission.
14 Accuracy of all prefiled testimony as
15 originally submitted to the Reporter and incorporated
16 herein at the direction of the Commission is the sole
17 responsibility of the submitting parties.
18
19
ONSTANCE S.BUCY
22 60""""Gr,C tified Shorthand Report r 187
CSB REPO NG 1938 AUTHENTICATION
208.890.519
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