20180411Eldred Supplemental Direct - Redacted.pdf

BEFORE THE CEP/ED
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )OF ROCKY MOUNTAIN POWER FOR A )CASE NO.PAC-E-17-07
CERTIFICATE OF PUBLIC )
CONVENIENCE AND NECESSITY AND )
BINDING RATEMAKING TREATMENT )
FOR NEW WIND AND TRANSMISSION )
FACILITIES )
NON-CONFIDENTIAL SUPPLEMENTAL TESTIMONY OF MICHAEL ELDRED
IDAHO PUBLIC UTILITIES COMMISSION
APRIL 11,2018
1 Q.Please state your name and business address for
2 the record.
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 Commission
15 since 2017.During my time with the Commission,I have
16 conducted analysis on electricity and natural gas prices in
17 general rate cases,integrated resource plans,prudence
18 reviews of capital investments,and cost recovery
19 mechanisms.In addition,I have attended the Institute of
20 Public Utilities Annual Regulatory Studies Program at
21 Michigan State University,and also attended Michigan State
22 University's NARUC Utility Rate School.
23 Q.What is the purpose of your testimony in this
24 proceeding?
25 A.The purpose of my testimony in this case is to
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)104/11/18 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 direct
4 testimony of Staff witness Rick Keller's direct testimony.
5 Mr.Keller provided Staff's position on the prudence of the
6 proposed investment for the new wind and transmission based
7 on preliminary information and the Company's benchmark wind
8 projects and not the final projects selected through the
9 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 have
14 been identified during the review process.The concerns
15 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 of
20 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 generation
24 projects submitted in response to the Company's
25 solar RFP;
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)204/11/18 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 need
6 for a supplemental Environmental Impact Statement
7 (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 and
12 terminal values for the projects.The approach overstates
13 net benefits and creates a bias toward Company-owned wind
14 and the Company's proposal.In my testimony,"levelized
15 analysis"will refer to the economic analysis covering the
16 20-year planning timeframe out to 2036."Nominal analysis"
17 will refer to the economic analysis covering the 30-year
18 useful life of the wind projects out to 2050.
19 Q.Please provide more detail on the use of nominal
20 PTCs in the levelized analysis.
21 A.The Company chose to create a hybrid analysis
22 that mixes levelized cost with nominal benefits in its
23 supplemental filings.This creates an unfair comparison
24 between alternatives.In the Company's RFP supplemental
25 filings,the treatment of PTCs in the levelized analysis
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)304/11/18 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 analysis
13 already reflects how benefits,and costs would be recovered
14 in rates.The Company's hybrid analysis does not
15 accurately reflect how capital costs are captured in rates.
16 When capital costs are put into rates,they are front
17 loaded,starting with a large value and decrease each year
18 with depreciation.The Company's hybrid methodology mixes
19 nominal and levelized values which results in an analysis
20 that does not produce a fair comparison between resources,
21 and does not accurately reflect how rates are recovered.
22 Q.How does the use of nominal PTCs impact the
23 results of the levelized analysis?
24 A.The cost of the project would increase by
25
i Link,Di-Supp,page 25,lines 16-17.
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)404/11/18 STAFF
1 approximately $2142 million if the Company used levelized
2 PTCs instead of nominal PTCs as they did in their hybrid
3 analysis.Table 1 provides the PVRR(d)results for the
4 Company's hybrid levelized analysis with nominal PTCs and
5 the Company's levelized analysis adjusted for levelized
6 PTCs for all price-policy scenarios.The Company's hybrid
7 levelized results using nominal PTCs shows benefit in all
8 price-policy scenarios.The adjusted results using
9 levelized PTCs shows benefit in 7 of the 9 price-policy
10 scenarios.Table 1 shows how the treatment of PTCs impacts
11 the results of the Company's hybrid levelized analysis:
12 overstating the net benefits.
13 Table 1-Nominal vs Levelized PTC Treatment in PVRR(d)
14 Analysis
(Benefit)/Cost ($million)
15 Company
.Levelized CompanyHybridLevelized16AnalysisNominalPrice-Policy Scenario Levelized PTC
.with Analysis
17 Analysis Adjustment Adjustment (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)
21 Medium Gas,Medium CO2 (357)214 (143)(167)
Medium Gas,High CO2 (448)214 (234)(304)
22 High Gas,Zero CO2 (568)214 (354)(448)
23 High Gas,Medium CO2 (603)214 (389)(449)
High Gas,High CO2 (694)214 (480)(635)
24
25
2 Approximation of $214 million provided by the Company in
IPUC Data Request Response 75.
CASE NO.PAC-E-17-07 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 PTCs.
3 Staff believes this provides the most reasonable method to
4 show how the Combined Projects would impact rates.The
5 nominal results are included to show that the adjusted
6 levelized analysis is similar with regard to showing net
7 benefits in 7 of the 9 price-policy scenarios.The fact
8 that the adjusted levelized analysis is similar to the
9 nominal analysis helps provide more evidence that the
10 Company's hybrid analysis overstates the net benefits.
11 Q.Does the use of nominal PTCs create other
12 concerns?
13 A.Yes,an additional concern is the use of nominal
14 PTCs in the levelized analysis creates a bias toward
15 Company-owned wind.Both Oregon and Utah independent
16 evaluators (IE)expressed concern with the use of nominal
17 PTCs in the levelized analysis and how such an approach
18 favors Build Transfer Agreements (BTA)bids over Power
19 Purchase Agreements (PPA)bids in the 2017R RFP.The
20 Oregon IE requested the Company run a sensitivity analysis
21 to address these concerns.The Company completed the
22 sensitivity analysis and the results produced a portfolio
23 with more PPA bids that generated more benefits over the
24 life of the project when compared to the Company's selected
25
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)604/11/18 STAFF
1 portfolio.3 In the Oregon IE final report,the IE
2 concluded,"the Company's modeling method,which levelized
3 cost but not the benefits of PTC acquisition,could have
4 biased the bid selection to less favorable offers."'A
5 copy of the Oregon IE final report is included as Staff
6 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 benefits
14 into the levelized analysis for the 2017R RFP final short
15 list.Graph 1 shows the year by year PTC value for the
16 nominal and levelized PTC treatment in the levelized
17 analysis from 2017-2036 for the final RFP short list.The
18 net present value (NPV)of the nominal PTC treatment is
19 million but the levelized PTC treatment NPV is
20 million.This creates $214 million worth of additional PTC
21 benefits in the Company's hybrid analysis.
22
23 3 This is based on the analysis which is summarized in theOregonIEfinalreportidentifiedas,'The Independent
24 Evaluator's final report on PacifiCorp's 2017R Request forProposals",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 ELDRED,M.(Supp)704/11/18 STAFF
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18 Q.Please explain your issue with terminal value.
19 A.I believe that the terminal value introduced into
20 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 value
23 of development rights,transmission assets (i.e.network
24 upgrades),and non-transmission infrastructure (i.e.roads)
25
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)804/11/18 STAFF
1 in 2050.6 Terminal value was not included in the Company's
2 initial filing.
3 Staff believes terminal value is speculative
4 because the estimation is predicting a value 33 years into
5 the future and it assumes the assets will still be needed.
6 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 it
10 is to accurately estimate the value of an asset,especially
11 one that has to be re-purposed.To take advantage of a
12 terminal value that far into the future,the assets
13 assigned would need to be utilized for some unknown
14 purpose.If they were utilized,there is good probability
15 there would be a cost associated that was not accounted for
16 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 million.When comparing this value to the
20 cost of the project,the value is small.However,when
21 comparing the cost to the medium gas,medium CO2 price-
22
23
24 5 Information provided by the Company in IPUC Data RequestResponse78,sub response (:k)
25 6 Value from Company witness Link confidential work papers,
file "EV2020 Workpapers Second Supp Results Summary File -
VOM adjusted CONF
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)904/11/18 STAFF
1 policy scenario with benefits of $1677 million,the
2 terminal value makes up approximately of the project
3 benefits.If the terminal value was excluded from the
4 nominal analysis,the benefits for the medium gas,medium
5 CO2 scenario would be reduced to million.
6 Q·Please explain how the Combined Projects may not
7 be least-cost least-risk when compared to the solar
8 generation projects?
9 A.The Company's solar RFP,known as 2017S RFP,
10 creates additional uncertainty whether or not the Combined
11 Projects are the least-cost least-risk option for a
12 capacity deficit that occurs 10 years in the future.The
13 results of the 2017S RFP
14
15
16 I also believe that the solar projects are lower
17 risk than the Combined Projects for three reasons:the
18 solar projects have lower capital project expense than the
19 Combined Projects;the construction of a new transmission
20 line,which has high cost-overrun potential,is not
21 required;and all solar bids are PPAs so the developer
22 takes on the risk for the projects.Table 2 shows the
23 nominal analysis comparison between the Combined Projects
24 and solar as an alternative.It only includes two price-
25
7 Value from CORRECTED Link,Di-Second Supp,page 17,
CORRECTED Table 3-SS.
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1004/11/18 STAFF
1 policy scenarios since the 2017S RFP analysis only studied
2 two scenarios for the solar only portfolio.Based on the
3 nominal analysis in the 2017S RFP,a solar only portfolio
4 has the potential
5
6
7
8 Table 2-Solar vs Wind Nominal PVRR(d)
(Benefit)/Cost ($million)
Solar Wind Change in10Price-Policy Scenario PVRR(d)PVRR(d)PVRR(d)
11 Low Gas,Zero CO2
12 Medium Gas,Medium CO2
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 hybrid
20 levelized analysis methodology.As discussed earlier in my
21 testimony,the Company's hybrid analysis overstates net
22 benefits and is not the best comparison between
23 alternatives.The nominal analysis should be the analysis
24 used when comparing how alternatives would impact rates.
25
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1104/11/18 STAFF
1 The Company confirms this statement:"Using nominal revenue
2 requirements is the best representation of what the actual
3 revenue requirement costs and benefits would be if the
4 Combined Projects were placed in base rates during the same
5 period."8
6 The continued use of the Company's flawed hybrid
7 levelized analysis in the 2017S RFP makes the Combined
8 Projects appear more beneficial than solar by introducing
9 additional benefits from nominal PTC treatment and by
10 shifting a greater amount of project cost outside of the
11 modeling timeframe.The additional benefits from the
12 nominal PTC treatment in the levelized analysis is the same
13 $214 million I discussed previously.When projects with a
14 large capital cost such as the Combined Projects are put
15 into a modeling timeframe that only capture half of the
16 project life,a large amount of the project cost is shifted
17 outside of the modeling timeframe due to levelization.The
18 solar PPAs in the 2017S RFP have a lower project cost and a
19 more uniform yearly cost so less of the project cost is
20 shifted outside of the modeling timeframe.
21 There is approximately three times the amount of
22 project cost that is shifted outside of the modeling
23 timeframe for the Combined Projects as compared to the
24 solar projects in the Company's inaccurate hybrid analysis.
25
6 Response to IPUC Data Request 80.
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1204/11/18 STAFF
1 Table 3 illustrates this effect.It shows that 36%of the
2 nominal project costs are excluded from the Company's
3 Combined Projects levelized analysis as compared to only
4 10%for the solar projects.
5 Table 3 -20 Year Project Cost NPV Comparison
6 ($million)
20 yearLevelized Difference %Change7NominalProjectProjectinProjectinProjectProjectCost
8 Cost NPV Cost CostNPV
9 Combined Projects
Solar
10
11 The Company decided to not select any of the
12 2017S RFP bids due to expected cost reductions in the
13 future and to avoid the current risk premium associated
14 with tariff and tax reform uncertainties.The Company
15 stated it plans to reassess the solar option in the 2019
16 IRP.9 Staff agrees that the solar option needs more study,
17 but believes the 2017S RFP results create additional
18 uncertainty whether or not the Combined Projects are the
19 least-cost least-risk option.
20 Q.Please explain the additional future cost risk to
21 the transmission portion of the project.
22 A.In addition to the cost risk to the transmission
23 project identified in Mr.Keller's testimony,new
24
25
9 Information from confidential attachment IPUC 76-1.
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1304/11/18 STAFF
1 transmission cost risks have been identified related to
2 mineral development,surface use agreements,and abandoned
3 mines along the transmission route.Andrew Wurdack on
4 behalf of Anadarko Land Corporation has brought this
5 information before the Public Service Commission of Wyoming
6 (Wyoming Commission)in his supplemental response
7 testimony."Mr.Wurdack's testimony states,"the language
8 used in the FEIS11 clearly intended that future mineral
9 development would be protected.""He also requested that
10 the commission adopt a stipulation that the Company enter
11 into surface use agreement with split-estate owners
12 providing for active and future mineral development."
13 Abandoned mines create a safety and cost risk to
14 the transmission line.Mr.Wurdack identified several more
15 abandoned mines which were previously not identified or
16 disclosed by the Company that are in the path of the
17 proposed transmission line.
18 The information provided in Mr.Wurdack's
19 testimony creates significant additional future
20
21 1°Docket No.20000-520-EA-17 (Record No.14781)Supplemental Response Testimony.
22 11 Final Environmental Impact Statement
12 Page 8,lineS 14-15,Andrew Wurdack Supplemental
23 Response Testimony,Docket No.20000-520-EA-17 (Record No.14781)
24 2 Page 8,lines 15-17,Andrew Wurdack SupplementalResponseTestimony,Docket No.20000-520-EA-17 (Record No.
25 14781)
14 Page 9,Andrew Wurdack Supplemental Response Testimony,
Docket No.20000-520-EA-17 (Record No.14781)
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1404/11/18 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 owners
5 creates cost risk in the wind projects."Anadarko remains
6 concerned that the Company may attempt to use the wind
7 power projects to block all mineral development leading to
8 costly litigation."is Anadarko has interest in the wind
9 projects because they own mineral rights under the private
10 land sections of some of the wind projects.Anadarko has
11 estimated the total to be at least 58,82016 acres of split-
12 estate lands.As a solution,Anadarko is recommending the
13 Wyoming Commission adopt a condition to secure agreements
14 to address surface use and recognition of rights of split-
15 estate owners.17 These previously unidentified or
16 undisclosed issues increase the risk of additional costs
17 not previously identified in the Company's ecomomic
18 analysis.
19 Q.How much of an increase in total project capital
20 cost results in the Combined Projects providing no economic
21 benefit?
22
15 Page 20,lines 9-11,Andrew Wurdack Supplemental
23 Response Testimony,Docket No.20000-520-EA-17 (Record No.
1478)
24 16 Page 11,line 15,Andrew Wurdack Supplemental ResponseTestimony,Docket No.20000-520-EA-17 (Record No.1478)
25 17 Page 20,lines 13-16,Andrew Wurdack SupplementalResponseTestimony,Docket No.20000-520-EA-17 (Record No.1478))
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1504/11/18 STAFF
1 A.The amount of benefits compared to the overall
2 capital cost is very small.A cost overrun of only
3 above the Company's proposed capital cost will eliminate
4 any net benefits for the Combined Projects.This is based
5 on the nominal analysis of the medium gas and medium CO2
6 price-policy scenario.Given that customers are already
7 taking on the risk that two of the nine price-policy
8 scenarios are showing negative net benefits,the Company
9 will need to execute the project very close to its
10 estimated costs and realize all the benefits assumed in its
11 PVRR(d)analysis in order for it to be worthwhile for
12 customers.
13 In Table 4,I have provided the amount above or
14 below budget the Company would have to achieve to break-
15 even for each price-policy scenario.
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CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1604/11/18 STAFF
l
2 Table 4-Capital Cost Breakeven Values for
Nominal PVRR(d)Analysis
3 ($million)
4 Breakeven $Breakeven %
.Capital Cost Capital CostPrice-Policy Scenario
5 Increase/Increase/
(Decrease)-Decrease
6 Low Gas,Zero CO2
Low Gas,Medium CO27LowGas,High CO2
8 Medium Gas,Zero CO2
Medium Gas,Medium CO2
Medium Gas,High CO2
10 High Gas,Zero CO2
High Gas,Medium CO211HighGas,High CO2
12
13 Q.Please explain the schedule delay risk due to the
14 potential need for a supplemental EIS.
15 A.A supplemental EIS may be required since the
16 transmission line and the wind project are now dependent
17 upon one another.The initial 2013 Federal Environmental
18 Impact Study (FEIS)assumed the transmission line was
19 independent of wind projects.Anadarko believes "that a
20 supplement to the 2013 FEIS is necessary to disclose and
21 analyze the new connected actions under National
22 Environmental Policy Act (NEPA)."18 In addition,Anadarko
23 is requesting the Company ask the Bureau of Land Management
24
25
le Page 28,lines 6-7,Andrew Wurdack Supplemental ResponseTestimony,Docket No.20000-520-EA-17 (Record No.1478)
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1704/11/18 STAFF
1 (BLM)to prepare a supplemental EIS."Mr.Wurdack's
2 opinion is that a supplemental EIS is unlikely to delay the
3 Combined Projects.2°However,I believe a supplemental EIS
4 could condense the already compressed schedule and lead to
5 an increase in cost to finish the project by the end of
6 2020,which is required to qualify for the full amount of
7 PTC benefits.
8 Q.Does this conclude your supplemental testimony in
9 this proceeding?
10 A.Yes,it does.
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3 Page 28,lines 7-9,Andrew Wurdack Supplemental Response
25 Testimony,Docket No.20000-520-EA-17 (Record No.1478)
20 Page 27,lines 20,Andrew Wurdack Supplemental ResponseTestimony,Docket No.20000-520-EA-17 (Record No.1478)
CASE NO.PAC-E-17-07 ELDRED,M.(Supp)1804/11/18 STAFF
BATES
WHITE
ECONOMICCONSULTING
PUBLIC VERSION
THE INDEPENDENT EVALUATOR'S
FINAL REPORT ON
PACIFICORP'S
2017R REQUEST FOR PROPOSALS
Presented to:
OREGON PUBLIC UTILITY COMMISSION
Prepared by
Frank Mossburg
Vincent Musco
Karen Morgan
February 16,2018
Exhibit No.103
Case No.PAC-E-17-07M.Eldred,Staff
04/11/18 Page l of42
1300 Eye Street NW,Suite 600
Washington,DC 20005
202-408-6110
TABLE OF CONTENTS
I.I NTRODUCT ION ANDSUMM ARY..............................................................................1
A.INTRODUCTION ....................................................................................l
B.RECOMMENDATION REGARDING THE FINAL SHORTLIST ......................l
C.ADDITIONAL RECOMMENDATIONS TO PROTECT RATEPAYERS...........4
D.ADDITIONAL COMMENTS AND RECOMMENDATIONS..............................5
II.RFP ISSUANCE TO BID RECEIPT...............................................................................6
III.BENCHM A RK BID ANALYS IS ...................................................................................10
IV.BID RECEIPT AND QUALIFICATION......................................................................11
V.INITIAL SHORTLIST DEVELOPMENT ...................................................................14
A.RANKING THE BIDS ..................................................................................l 6
B.INITIAL SHORTLIST ........................................................................................22
VI.B I D RE VIEW ANDP RI CEUPD ATES ........................................................................2 2
VI I.FIN A LSHORTL I STMODEL IN G ...............................................................................2 6
A.INITIAL MODELING....................................................................................26
B.IE SENSITIVITY ........................................................................................29
C.INTERCONNECTION ANALYSIS................................................................32
D.REVISED FINAL SHORTLIST ANALYSIS .....................................................35
E.OTHER SENSITIVITIES..................................................................................36
VI I I.CONCLUS IONS A NDRECOMMEND AT I ON S.........................................................37
A tt a chmentOne ...........................................................................................................................4 1
A tt a chmentTwo ...........................................................................................................................4 3
A tt achmentThree ........................................................................................................................4 4
A tt achmentFour ..........................................................................................................................4 5
A tt achmentF iv e ...........................................................................................................................4 6
A tt achment Six .............................................................................................................................4 7
A ppendix A ...................................................................................................................................4 8
i Pabe
Exhibit No.103
Case No.PAC-E-17-07
M.Eldred,Staff
04/11/18 Page 2 0f42
I.INTRODUCTION AND SUMMARY
A.INTRODUCTION
This is Bates White's Final Closing Report on PacifiCorp's 2017R Renewables RFP
("2017R RFP"or the "RFP").Bates White served as the Independent Evaluator ("IE")for this
RFP.The primary purpose of this report is to provide the Oregon Public Utility Commission
("Commission")with the IE's recommendation with respect to the acknowledgement of
PacifiCorp's ("the Company's")selection of a Final Shortlist.This report is also intended to
provide the Commission with a record of the development and evaluation process for both the
Initial and Final Shortlists.
B.RECOMMENDATION REGARDING THE FINAL SHORTLIST
Bates White recommends that the Commission acknowledge the Final Shortlist as
presented.Based on the results of portfolio optimization modeling,stochastic risk analysis,and
review of viability factors,the Company has selected four projects for the Final Shortlist
representing approximately 1,300 MW.These projects are
TB Flats I &II -A proposed 500 MW wind project located in Carbon and Albany
Counties,Wyoming.This project is to be developed by PacifiCorp's Benchmark team
based on a site developed by Invenergy.
Cedar Springs -A 400 MW wind project located in Converse County,Wyoming.This
project is to be developed by NextEra Energy Acquisitions.Half of the project will be
sold to PacifiCorp under a Build-Transfer Agreement ("BTA")while the other half will
sell power to PacifiCorp under a Power Purchase Agreement ("PPA").
l|Page
Exhibit No.103
Case No.PAC-E-17-07
M.Eldred,Staff
04/11/18 Page 3 of42
Ekola Flats -a proposed 250 MW project located in Carbon County,Wyoming.This
project is to be developed by PacifiCorp's Benchmark team based on a site developed by
Invenergy.
Uinta -A proposed 161 MW wind project located in Uinta County,Wyoming from
InvenergyWind Development.The project will be sold to PacifiCorp under a BTA
Agreement.Unlike the top three projects this project does not require the completion of
the Aeolus-to-Bridger/Anticline Segment ("D2 Segment")in order to be deliverableto
PacifiCorp's system.
Our recommendation is based on the followingpoints.
The selected bids represent the top offers that are viable under current transmission
planning assumptions and provide the greatest benefit to ratepayers as determined by
the Company's System Optimizer ("SO")and Planning and Risk ("PaR")models.
The selected bids represent the best viable options from a competitiveprocess.The
RFP received bids from 13 suppliers offering a total of 18 projects representing about
4,900 MW.Some of these projects offered multiple options.In total there were 59
bid options presented.Offers were received from projects both inside and outside the
Company's constrained area in Wyoming and included variations in design such as
different turbines and contract structures.
Our independent analysis confirmed that the selected bids were reasonably priced
and,while not the lowest-cost offers,were the lowest-cost offers that were viable
under current transmission planningassumptions.Our analysis included the creation
of our own cost models for each bid option,a review of PacifiCorp's models and a
review of the terms and conditions of each bid.
Two company-sponsored Benchmark bids were chosen and we took special care to
confirm those selections.We confirmed the accuracy of the Benchmark costs and
scoring and provided the Commission with a complete review of all costs of each
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Case No.PAC-E-17-07
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project prior to bid receipt.We also confirmed the Benchmark's status by:(a)
reviewing the project's Initial and Final Shortlist scores and models,(b)
independently scoring the project's non-price characteristics,(c)comparing the cost
and output of the project to recent third-party bids,and (d)evaluatingthe bid costs in
our own cost model.The bids were also disciplined by the fact that a third-party
bidder submitted a competing offer for a BTA for each project.
To the best of our knowledge the RFP aligns with the Company's Integrated
Resource Planning ("IRP")process,as well as its 2017 IRP Plan,which was filed on
April 4,2017 ("2017 IRP").The Initial and Final Shortlist analyses used current
assumptions from the IRP.The models used to select the Final Shortlist were the
same models that the Company uses in its IRP process.While it is our understanding
that the action plan from the 2017 IRP (which includes this resource acquisition
strategy)is approved,we have yet to see a final approval order and are unaware of
any potentialconditions that may come with such an order.For the purposes of this
report,we assume that the 2017 IRP will be approved without any conditions that
may alter our recommendation here.
Additionally,we base our recommendation on our participationin the entire RFP process
from design,through bid receipt and analysis,to selection of the Initial and Final Shortlists.
During that time we:
1.Reviewed and commented on drafts of the RFP;
2.Attendedthe pre-bid conference;
3.Monitored bidder contact,including the answers to bidder questions;
4.Confirmed the assumptions used in the analyses;
5.Confirmed the initial qualification of bidders and the confirmation of
proposal details;
6.Provided input with respect to bidder disqualifications;
7.Reviewed the price and non-price scores and models for the Company's
Initial Shortlist process and confirmed the Company's selection of an
Initial Shortlist;and
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8.Reviewed the models for the selection of the Initial and Final Shortlist and
confirmed the Company's selection of the Initial and Final Shortlist.
Throughoutthe process we were in constant contact with PacifiCorp's evaluation team.
The Company was transparent in their discussions with us and provided all information that we
asked within a reasonable timeframe.
We note that we will also be monitoring the negotiations of final contracts with the
winning bidders to ensure that actual signed contracts match the offers submitted and evaluated.
In the case of the Benchmark resources we will monitor the negotiationof EPC contracts for the
facilities.
C.ADDITIONAL RECOMMENDATIONS TO PROTECT RATEPAYERS
We have additional recommendations related to the RFP to help protect ratepayers from
bearing undue risk.First,in order to protect ratepayers and ensure that they receive the benefits
promised during this RFP we would recommend that all selected resources to be owned by the
Company (i.e.,BTAs and Benchmark resources)be held to their capital and operations and
maintenance ("O&M")cost projections as provided with the bid.These amounts should be
considered a "hard"cap,meaning that there will be no opportunity for the Company to collect
additional costs even if they believe such expenditures were prudent.Doing so will help give the
offers a risk profile much closer to that of a PPA,requiring the Company to take risks that
typical wind developers take,and insulate ratepayers from the risk of cost overruns.Because the
majority of construction costs will be covered under the BTA agreement or,in the case of
Benchmarks,a negotiated engineering,procurement,and construction ("EPC")agreement,we
feel this is a reasonable requirement.
Second,ratepayers should not be harmed if either PacifiCorp or the project developers
fail to acquire 100%of the value of the Production Tax Credit ("PTC").PacifiCorp should
provide an unconditional guarantee (i.e.,not subject to force majeure or change in law)that
ratepayers will receive the full projected value of the Production Tax Credit.This includes
situations where (a)PacifiCorp cannot claim full PTC value or (b)PacifiCorp does not have the
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taxable income to use the full PTC value.Again,this is similar to what is expected of a third-
party developer.
Third,the Company should similarly be held to their cost projections for the Aeolus-to-
Bridger D2 Segment.PacifiCorp's resource acquisition strategy here -which includes three
projects that rely on the D2 Segment's construction for economic viability -is based on a certain
cost promise for this segment and the Company should be held to its promises.
D.ADDITIONAL COMMENTS AND RECOMMENDATIONS
Based on our work in this RFP we have several observations and recommendations to
assist parties moving forward.First,parties should make more effort in the future to align the
RFP process with the IRP process.This process was rushed in order to meet deadlines for
qualification for full value of the PTC.However,the PTC's sunset has been known since the
end of 2015.We were not involved in the IRP process but are unaware of any reason whythis
fact could not have been incorporated into planning at an earlier time.Moreover,as of today
there is still no written order approving the Company's IRP,which cast additional uncertainty
over this RFP process.
Second,and related to the above point,transmission planningshould better align with
IRP planning.One troubling aspect of this RFP was that the initial system impact studies
provided to bidders did not incorporate the early completion of the D2 Segment.After revisions
to account for the earlier in-service date of the D2 Segment were incorporated it was determined
that onlyprojects with early queue positions could be deliverable to load without the completion
of the entire Gateway South project in 2024.These evaluations by PacifiCorp's transmission
group essentially left us with only about four potential offers in the transmission-constrained area
served by the D2 Segment.We realize that there are functional separations within the Company
but having alignment between the planning side and the transmission side will help make more
informed decisions in the future.
Third,future RFPs using the Company's production cost modeling should examine (as a
sensitivity)resource choice with levelized benefits as well as costs.While the issue ultimately
had no impact on winning projects selected in this RFP due to the transmission issues noted
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REDACTED
above,the Company's modeling method,which levelized cost but not the benefits of PTC
acquisition,could have biased the bid selection to less favorable offers.
Fourth,regarding the winning Cedar Springs project,which is 50%BTA and 50%PPA
of 200 MW each (for a total of 400 MW),we note that the
.Additional analysis shows this option to be preferable to the selected
option across several years,but slightlyless preferable over the entire 30-year expected life of
the facility.We believe the Company's selection of the 50-50 BTA/PPA option is reasonable,
but note that the PPA option would also be a reasonable choice given its superior risk protections
and additional portfolio flexibility.
Fifth,becausethe selected portfolio contains mostly options to be owned by the
company,the selected portfolio generates significant PTC benefits within the first ten years of
operation.These benefits credit against revenue requirements and serve to lower costs in this
initial period.However,after the end of the ten-year PTC window these credits disappear and
costs increase.PacifiCorp currently projects a $125 million cost increase in 2031.If the
Commission believes such an increase would be unreasonable they should consider enacting
some form of rate mitigation efforts in the future.
II.RFP ISSUANCE TO BID RECEIPT
PacifiCorp's RFP was approved by the Commission,with modifications,in a special
public meeting on August 29,2017.The Commission ordered modifications to the RFP
regarding IRP acknowledgement,eligibility of existing resources,minimum bid requirements,
credit requirements and terms in thepro forma PPA.PacifiCorp made the required changesto
the RFP and provided a revised RFP to the IE prior to issuance of the final RFP to the market.
We reviewed the changes made,had no objections,and the final RFP was approved by the
Commission on September 26,2017.
The final RFP was issued on September 27,2017 and was subject to an accelerated
schedule.The accelerated schedule was designed to allow winning bidders to capture the full
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value of the PTC by placing their projects into service prior to December 31,2020,1 and to align
with the Company's Certificate of Public Convenience and Necessity ("CPCN")process to
expand its transmission system in Wyoming in order to accommodate projects selected in this
RFP.
Since PacifiCorp issued the RFP in late September the followingsteps have been
completed:
Table l Milestone Events to Date
RFP Issued to Market 9/27/2017
1"*Bidder's Conference 10/02/2017
Notice of Intent (NOI)to Bid Due 10/09/2017
Last Day for RFP Questions to IEs for Q&A 10/10/2017
Benchmark Bids Due 10/10/2017
RFP Bids Due -Wyoming Wind 10/17/2017
RFP Bids Due -Non-WyomingWind only 10/24/2017
Bid EligibilityScreening Completed 10/30/2017
Initial Shortlist (ISL)Evaluation/ScoringCompleted 11/7/2017
Capacity Factor Evaluationon ISL started 11/12/2017
IEs'Review of ISL Completed 11/17/2017
ISL Price Update 11/22/2017
Capacity Factor Evaluationon ISL Completed 11/27/2017
Price update for Tax Reform Bill 12/21/2017
Final Shortlist EvaluationCompleted 2/12/2018
IE Report submitted to OPUC 2/16/2018
Bates White has actively participated at each step of the RFP process.We have been in
constant contact with the Company,Commission Staff and have had multiple discussions on
many issues.In addition,throughout the process we have coordinated with Utah's independent
evaluator to ensure that the rules of the RFP were applied consistently across both states.
PacifiCorp held a Bidder's Conference on October 2,2017.The conference was
simulcast in Portland,Salt Lake City,and online.Bates White attended the conference in
RFP,page 1.
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Portland.PacifiCorp personnel walked through the RFP process,including bid qualification and
evaluation.Several questions were raised regarding a range of issues including bid fees,contract
requirements,schedule,and submission requirements.PacifiCorp answered most of these
questions at the conference and the reminder of the questions later via a posting on the RFP
website.Bidders asked questions up until the final day for questions of October 9,2017.Bates
White reviewed all questions and answers prior to posting.
After the bid conference,PacifiCorp presented us with the assumptions to be used in bid
evaluation.These included items such as cost of capital,asset lives,and forward market values.
We reviewed the assumptions file and asked PacifiCorp questions in order to determine that the
numbers used were consistent with the most recent IRP process or (for certain items)reflected
the most recent Company forecasts.
Bidders were to submit NOIs by October 9,2017.Submissions were made electronically
and Bates White was copied on all submissions.In total,19 companies indicated their intentions
to bid by submitting NOIs.We received no indications that there were companies who wanted
to submit an NOI but failed to do so.A list of those companies providing NOIs is presented in
Table 2.
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REDACTED
lable 2 Summan of VQl Submis ions
ÌGivnärship»TBiddefilBiodefiëne if differenty 5tate
In the NOI bidders were asked to identify the types of proposals they might submit as
well as the project size.Table 3 summarizes the indicated bids by state,type,(BTA or PPA)and
size (in MW).The potential response was heavily weighted toward Wyoming wind offers and
far in excess of the RFP's targeted solicitation of 1,270 MW.
lable 3 Summarv of Indicated ßids
ID 2 200 1 110
MT 3 400 --
OR 1 187 1 187
UT 2 180 1 100
WA 1 145 1 145
WY 21 6,194 12 3,365
Total 30 7,305 16 3,906
2 Listing for ownership is name of entity providingcredit support.
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REDACTED
III.BENCHMARK BID ANALYSIS
On October 10,in accordance with the RFP timeline,PacifiCorp's Benchmark team
submitted their offers to the IE and the PacifiCorp evaluation team.In total,there were four
benchmark offers submitted.These projects are shown in Table 4.
Table 4 BenchmarA Project Summan Data
Ekola Flats 250 Carbon 11/1/2020
McFaddenRid e II 110 Alb Carbon 11/1/2020
TB Flats I 250 Carbon 11/1/2020
TB Flats I &II 500 Alban Carbon 11/1/2020
Source:Project Applications,Appendix C
Bates White next undertook a review of the offers.In assessing a utility'sown bids in
response to the RFP,our greatest concern is that the utilitywill incorporate cost estimates that
have been aggressively estimated and do not characterize the costs of the project accurately.To
determine whether this had occurred,we looked at a detailed breakdown of each of the
benchmarks costs to determine if any items have been improperly omitted from the cost
calculation,and at overall capital cost levels by comparing them to publicly-available data on
recent wind generation capital costs.Such a comparison provided a measure of the overall
reasonableness of the Benchmark capital costs and capacity factors.
We found that the Benchmarks were acceptable based on three items.First,the
benchmarks were not deliberatelyunderpriced through omission of any capital cost components.
Second,the benchmark capital and operating costs appeared reasonable when compared with
public data on U.S.wind projects.Third,the capacity factors of the benchmarks were reasonable
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when compared with public data and were supported by credible third-party analysis.Bates
White's detailed assessment of the Benchmark bids is included as Appendix A to this report.
In addition,as required by the Oregon Competitive Bidding Guidelines,we reviewed
PacifiCorp's price and non-price scoring of the benchmarks prior to receipt of third-party offers.
The price score was based on a comparison of the bid's costs to the market value of the energy
the bid would replace.The non-price score was based on criteria laid out in the RFP.Bates
White confirmed the price scores by inputting key bid criteria into our own busbar levelized cost
model.Additional details about all scores,as well as the actual scores,are provided later in this
memo.All scoring was confirmed prior to the review of third-party offers,per Oregon's
Competitive Bidding Guidelines.
IV.BID RECEIPT AND QUALIFICATION
Bids from third-party bidders were due on two separatedates.Wyoming project
proposals were due on October 17.Non-Wyoming proposals were due a week later.Bates
White suggested this bifurcation,noting that the original draft RFP did not allow bids from
outside Wyoming.Only after a last-minute modification to the RFP were non-Wyoming bids
allowed to participate.Our suggestion to allow non-Wyoming bidders an extra week to prepare
their bids was meant to recognize the reduced notice afforded to them.
Bates White supervised in person in Portland the receipt and opening of the bids on both
third-party bid receipt dates.No bids were rejected for being untimely and there was no
indication that any bidder had offers they wished to submit but were unable to do so.
Ultimately,ignoring those who did not bid or whose bids were deemed to be non-
compliant (discussed below),13 suppliers submitted a total of 18 projects representing almost
4,900 MW-which is about 3.9 times the quantity solicited.The majority of these projects were
Wyoming wind projects.Specifically,14 projects representing around 4,400 MW were based in
Wyoming while four projects representing 485 MW were located outside of Wyoming.Some
projects contained several options,typicallydifferences in project size,equipment,or transaction
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type (i.e.,PPA versus BTA or a combination thereof).In total,bidders submitted 50 Wyoming
bid options and nine non-Wyoming bid options.
One notable set of submissions came from Invenergy.These submissions were notable
because they were third-party BTA offers for three of the four Benchmark sites (all sites except
McFadden Ridge).Invenergycurrently holds the development rights on these three sites and
under their agreement with PacifiCorp's development team,both parties were free to offer bids
into the RFP.We viewed this as a positive sign becauseit provides a transparent and above-
board market offer to compare with the Benchmarks.
Fees for proposals were structured such that the bidder paid a fee of $10,000 covering a
base proposal and two alternatives.Each bidder was permitted to offer up to three additional
alternatives to the base proposal (maximum of six)at a fee of $3,000 per alternative.After the
receipt of offers,PacifiCorp worked with bidders to confirm and collect bid fees.PacifiCorp and
the bidders were able to come to agreement on fee amounts.
Upon final receipt of bids and bid fee confirmation,PacifiCorp went to work confirming
bid details with bidders.Bidders provided and confirmed project information and provided
update information where their original response was lacking.Bates White participated in calls
with the bidders to make sure that all parties understood the terms and conditions of the bid and
any deficiencies encountered.
Once the bids were confirmed,PacifiCorp and the IEs reviewed the offers for
qualification purposes.Bids were held to several minimum requirements.Key requirements
included:(a)being wind powered offers,(b)demonstrating that the project could be
commercially operational by December 31,2020,(c)being located in or demonstrating
deliverability to PacifiCorp's system,(d)having requested interconnection with PacifiCorp's
system or a third-party system and (at a minimum)having a feasibility study in progress,(e)
compliance with and verification of major equipment availability (wind turbines),and (f)having
one to two years of wind data from the site.
We discussed potential disqualificationswith PacifiCorp and the Utah IE.Ultimately,
four bidders had projects disqualified from consideration for the Initial Shortlist.The
disqualified Wyoming projects were as follows:
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REDACTED
1.Farm was rejected for containing an unacceptable level of
development risk.The project was still in the conceptual stage,the bidder did not have
site control,and relied on "virtual"met tower data.
2.withdrew its proposal from consideration for the
short-list because the project was proposing an unacceptable transmission structure.The
project was located outside of PacifiCorp's system and proposed using a "pseudo-tie"for
delivery rather than securing firm delivery to the system.
The rejected non-Wyomingprojects were as follows:
1.Caithness Energy's Beaver Creek projects were disqualified as non-compliant as they did
not offer a wind-onlyoption as required by the RFP.Their offer was for a wind farm
mixed with battery storage.In addition,their proposal presented issues with transmission
service as their proposal required a third party to take title to the energy prior to receipt
by PacifiCorp.
2.project was rejected due to the fact that it was not a wind-onlyresource as
required by the RFP.had proposed a PPA from a pumped storage facility
which might possibly be combined with wind and solar projects at a later date.
Bates White was consulted on the decision to remove each of these bidders and bid
options and we agreedwith the decision to remove them.Caithness pronounced themselves
"verydisappointed"that PacifiCorp did not accept their option,which they believedhad real
value for bidders.During discussions with the bidder PacifiCorp made clear that the failure to
offer a wind-onlyoption was the primary reason for the disqualification.offer was
also rejected due to the fact they did not offer a wind-onlyresource (though their project
consisted of other resource types beyond storage).
In making the disqualification PacifiCorp had to point to a reference in the RFP that
supported this decision.While the RFP,plainlyread,asks only for "new wind resources",the
closest specific language in the RFP document is Section 3.H.13 which states:"proposal presents
an unacceptable level of development or technology risk."Caithness offered the argument,
which has some validity,that their project did not,in fact,pose any technology risk.However,
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REDACTED
the fact remains that the offer was not a wind-onlyproject and would not match the plan
resulting from PacifiCorp's approved IRP.If the RFP was interested in dispatchable wind then it
would have stated so clearly in the document.
It is true that PacifiCorp and the IEs could have decided to allow the offer.However,the
issue with this decision is that other developers may have claimed -based on a clear reading of
the RFP -that such an offer was not permitted and,had they known,they would have offered
into the RFP in a different manner than they ultimately did.Yet another issue with granting the
request is that the bid evaluationmethod would have to be re-examined in order to ensure it was
capturing the full value of a dispatchable wind offer.In our experience these offers typicallyare
not cost-competitive and only stand to succeed if the evaluation places a high value on the
storage component.
Another factor is whether or not a storage-aided facility would truly count as a
"renewable"resource.In California's Green Tariff Shared Renewable programs,which aim to
bring renewables to those who want a larger share than under California RPS standards or who
want to participate in community-based solar programs,storage is not allowed because it
typicallycharges from the grid.
We note here that a cursory glance at Caithness offer prices,which ranged from around
,would likely not have proven to be valuable when compared with the
prices offered by other resources.PacifiCorp did tell the Caithness team that they were welcome
to discuss the project in the context of a bilateral transaction and we share that sentiment.If the
Commission is interested in pursuing more storage we would recommend that a separate
procurement be held for such resources.
V.INITIAL SHORTLIST DEVELOPMENT
After the bids were received and bid details were confirmed,the Company began the
Initial Shortlist evaluation.Per the RFP,each bid was scored on price and non-price factors.
The total bid score was weighted at a maximum 80%for price and a maximum 20%for non-
price factors.The non-price factors were defined as follows:
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Table 5 Non-Price Factor Weighting
Non-Price
Factor
NotúPriceFactor Weighting
Price score was based on a comparison of the cost of the bid to the benefits of the bid.
Costs differed based on the type of bid.For BTA bids the costs were:
(a)the revenue requirement needed to cover the project's capital cost (less the full
Production Tax Credit),
(b)O&M costs,including maintenance capital and royaltypayments,
(c)property tax,
(d)wind integrationcost,
(e)network upgrade costs,and
(f)Wyoming generation taxes.
For PPA bids the costs included:
(a)the PPA price,
(b)network upgrades,and
(c)integration costs.
The major benefit for both types of offers was captured by the value of the energy
replaced by the project.This value was based on one of three forecasts of benefits based on
project location (Wyoming,Utah/Idaho,or Oregon/Washington).Each forecast was created by
PacifiCorp's IRP team by running production costs models with and without proxy wind
resources and measuring the increase in cost at each location.Energy benefits for each project
were calculated based on the specific generation output of a given project.Beyond energy value,
BTA bids were assigned a terminal value to account for the fact that PacifiCorp would own the
site at the end of the project's useful life.
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Bids were ranked in separate categories,"Wyoming Wind"and "Non-Wyoming Wind."
In this context,"Wyoming Wind"meant projects whose deliverability was enabled by the D2
Segment.This was done because PacifiCorp's evaluationdid not take into consideration the
cost of the Aeolus to Bridger transmission expansion (a cost that was included in the Final
Shortlist evaluation).We were concerned that ignoring this cost would place non-Wyoming
offers at a disadvantage.3
A.RANKING THE BIDS
Bates White independently verified the rankings in three ways.First,we reviewed each
model on a line-by-line basis to make sure that the details of the bids were properly input and
that all bids used the same default assumptions.Second,we reviewed the terms and conditions
of the bids and compiled our own non-price scores.Third,we tested PacifiCorp's models by
inputting key costs of each bid option into our own cost model,which determined an annual
$/MWh annuity cost for the bid option.After we reviewed the bids we conferred with both
PacifiCorp and the Utah IE to come to a consensus on shortlist candidates.
WyomingWind
The ranking of all the Wyoming Wind bid options is shown in Attachment One.Our
simplified cost models were able to match PacifiCorp's models reasonably well.On average
PacifiCorp's models showed a higher cost by $0.27/MWh and in 46 out of the 50 cases the
difference was less than a dollar per MWh.
The table below shows the offers for each project with the greatest net benefit,in other
words,options proposed for the same project with lower net benefit are removed for clarity.
3 Specifically,the Aeolus-to-Bridger transmission project -which has yet to be approved and built -will benefit all
Wyoming-based bids,including the Benchmark bids.It is important for the RFP evaluation process to consider the
cost of the transmission project in comparing bids,particularly in comparing Wyoming-based bids -which are most
likely to benefit from the transmission project -to non-Wyoming bids,which are less likely to benefit from the
transmission project.
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REDACTED
Table 6 allows us to make a few observations.First,the offers were very close in value.
Thirteen of the projects offered net benefits of between $25/MWh and $30/MWh.This bunching
means that small assumptions can have a large impact on ranking.Second,we see that
PacifiCorp's terminal value adders were fairly small,about $1.18/MWh on average.Third,term
length does have an effect on the net benefits.The average energy benefit for projects with
terms less than 30 years is $46.76/MWh while the average benefit for 30-year projects is
$48.74/MWh.This difference is mostly driven by the fact that the value of energy replaced
increases in later years.These latter two items give a small advantage to BTA bids (since all
BTA offers are assumed to last for 30 years).Again,the difference is not vast,but it can have an
impact when bids are bunched so close together.This is why the BTA offers from
and were ranked just ahead of the lower-cost PPA offer from
.Finally,the Invenergyoffers for the Benchmark sites were generally
To translate these net benefits into a price score and create a final ranking,PacifiCorp
utilized three scoring methods.First,the offers were "ranked'with the most beneficial bid
receiving a score of 80 points,a breakeven bid (i.e.,a bid with zero net benefit)receiving zero
points,and any scores in between being interpolated.Second,the offers were "force-ranked,"
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REDACTED
with the most beneficial bid receiving 80 points and the least beneficial receiving zero points,
with in-between scores being interpolated.Finally,PacifiCorp used the "force ranking"concept,
but used a "rank order"method to score all offers between the highest-and lowest-ranked offers.
So,if there were nine bids,the best would receive 80 points,the second-best bid would get 70
points,the third-best bid would get 60 points,and so on,with the worst bid receiving 0 points).
In each method PacifiCorp combined their scores with the non-price score to get a final
bid ranking.The results are shown in Table 7.
This table shows that regardless of the scoring system (e.g.,"Cases"1,2,and 3)utilized,
the actual project rankings did not change.This is an important point to underscore.
Nevertheless,there are a couple other points to draw out from Table 7.First,there was a
relatively big gap between the project and the project,which suggested
a logical threshold for determining the shortlist.Second,under the first scoring method price
scores were tightly bunched,with eight projects scored between 80 and 89 points.This meant
that non-price factors could have a larger impact on bid selection.Having said that,non-price
scores were relatively similar,with the exception of the ,which were lower than those
for other bidders.
In order to select bid options for the Initial Shortlist,PacifiCorp and the IEs proceeded
with the following goals in mind:
1.Selecting the bids with the greatest net benefit in terms of price and non-price
benefits,
2.A diversity of bidders and projects,4
4 This can minimize the risk of relying on the success of one given project or a given bidder.
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REDACTED
3.A mix of PPAs and BTAs,
4.A relatively clear split between the score of the last bid picked and the next bid that
was not selected,and
5.The RFP goal that there be a minimum of 2,000 MW selected.
PacifiCorp's recommended Initial Shortlist relative to other top-performing projects is
shown in .
Source:PacifiCorp,2017R RFP -Wyoming Initial Short List Update -2017-11-06 IE V4.pptx
The Initial Shortlist was comprised of nine projects including four PPAs,two BTAs,and
one PPA/BTA combination.All three Benchmark projects were selected to the shortlist.(Figure
1 above omits the becausethe offer for the same site
scored higher,but,as seen on Table 6,the offer scored among the top
offers,which earned it the right to move on to the next round.)If a project was selected,_all
alternatives for a given project were selected as well.
The nine projects represented a cumulative installed capacity of approximately 3,100
MW,significantly above the RFP's stated target shortlist size of 2,000 MWs.The reason for
such a large selection of projects was the tight bunching of the offers.As noted above,when
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REDACTED
looking for a selection of projects we typicallytry to identify "gaps"in value.The first such gap
appearsbetween the and projects.This is shown on both figure
one and above in Table 6.6 While the were also low scorers on the non-price side,
the gap appears in the price score as well.As can be seen on Table 6 there is about a g
gap between the project and the offer.
While we did consider imposing a stricter limit on the selection,ultimately,it was
considered more advantageous to include more projects in the Final Shortlist evaluation.This is
especially true given that all bids would be allowed to submit a best and final offer (BAFO)and
the offers were so tightly bunched that any changes resulting from the BAFO could certainly
alter the rankings.In addition,we did consider pushing for the exclusion of the McFadden Ridge
project on the grounds that it would not be included in the shortlist without the assistance of the
terminal value adder and the additional value resulting from its assumed 30 year operational life.
We ultimately decided to allow it because (a)the bid was scored properly according to the rules
of the RFP and (b)this was simply a selection to the Final Shortlist evaluation,not a selection for
a winning bid.
Non-WyomingWind
As noted above,the Non-Wyoming Wind category received substantially fewer offers
than the Wyoming category.This was not totallysurprising since the category was added at the
last minute per the decision of the Utah PSC.Onlyfour qualified projects were submitted in this
category.The table below shows all options considered in the evaluation
s Note that the values in Figure 1 differ slightly from the values in Table 6 above and in the Appendix.Figure 1
comes from PacifiCorp's presentation to the IEs and regulators while the numbers in the other sources are taken
straight from PacifiCorp's cost models.In any case,the bid order is the same.
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M.Eldred,Staff
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REDACTED
Table 8 makes it clear that these bids do not provide the same level of benefit as the
Wyoming Wind offers.This is not unexpected given both (a)the quality of the wind resource in
Wyoming and (b)PacifiCorp's projected energy market benefits -which are higher in Wyoming
than elsewhere.Of course,the Wyoming bids did not include the cost of the proposed
transmission upgrade-again,this was considered in the Final Shortlist evaluation.
The was the only non-Wyoming project which provided positive net
benefits.We note that this project is actually located in Southwestern Wyoming right near the
Utah border.However,because it lies outside of the constraint that is alleviatedby the Aeolus to
Bridger transmission segment it was valued as a Non-Wyoming resource.
PacifiCorp scored these bids using the same methods as the Wyoming bids.The ranking
of the offers did not change depending on the scoring method used and the non-price scores of
the bids were not a factor (i.e.,they did not change the ultimate project rankings).
In terms of bid selection,PacifiCorp recommended selecting all projects except the g
.This selection is shown in Figure 2.
Source:PacifiCorp,20l7R RFP -Non-Wyoming Initial Short List Update -2017-11-06 V6.pptx
PacifiCorp made this selection in order to achieve a balance of PPAs and BTAs.In
addition,there was a reasonable gap between the last bid selected and the rejected
bid.We agreed with this conclusion.
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Case No.PAC-E-17-07
M.Eldred,Staff
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REDACTED
B.INITIAL SHORTLIST
PacifiCorp placed the followingprojects and bidders on the Initial Shortlist.Again,if a
project was selected to the Shortlist,then all bid options from a project were selected.
VI.BID REVIEW AND PRICE UPDATES
Best and Final Offers from all offers on the Initial Shortlist were due on November 22,
2017.Most bidders took advantage of the opportunity to adjust their pricing.Shortly thereafter
it became clear that some form of tax reform legislationwould soon be passed by the Federal
Government.After discussions with the IEs,PacifiCorp sent a notice to all remaining bidders
informing the bidders that,once tax reform legislation was finalized,bidders would be allowed a
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Case No.PAC-E-17-07
M.Eldred,Staff
04/11/18 Page 24 of 42
REDACTED
brief opportunity to refresh their offers to reflect any changes they felt necessary.This
opportunity was extended to all bidders since parties could not be sure how the final law changes
would affect each bidder.
On December 18*after conference committee approval of the "Tax Cuts and Jobs Act,"
PacifiCorp notified bidders that they could revise their offers by December 21 to reflect any
changes they thought necessary as a result of the Act.Several bidders took advantage of the
opportunity to adjust their offers.
PacifiCorp made other adjustments to the offers as well.As described in the RFP,
PacifiCorp engaged a third-party consultant (Sapere Consulting)to review wind generation data
from each offer in order to assess the reasonablenessof data providedby the bidders.This was
done in accordance with Guideline 10(f)in Commission Order 14-149.Evaluations were
completed by November 17,2017.Sapere Consulting found that most offers had reasonable
output estimations.The exceptions were and bids,which
each were subject to an 8%reduction in their net capacity factors based on the consultant's
findings.
In addition,PacifiCorp found that the offers from had mistakenly omitted
Wyoming sales taxes in their offers.In order to perform production cost modeling the Company
adjusted their levelized cost models to reflect these developments.Adjusting for (a)offer
repricing,(b)capacity factor adjustments for offers,(c)inclusion of sales taxes in
offers,and (d)some revisions in interconnection costs,resulted in the following
changes in net benefits for all Wyoming shortlisted offers.
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Exhibit No.103
Case No.PAC-E-17-07
M.Eldred,Staff
04/11/18 Page 25 0f42
REDACTED
Table 10 shows that almost all bids saw the net benefits of their offer reduced.In some
cases this was because the bidder raised their offer price.g,for example,did this for several
of their offers.In the case of BTAs,net benefits were reduced due to the lowering of the
corporate tax rate,which lowered the value of the PTC.Other bidders,for example,s
project and Project,left their offers relatively stable
and saw little change in their valuations.
The non-Wyoming offers saw similar changes as shown in Table 11.
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Exhibit No.103
Case No.PAC-E-l7-07
M.Eldred,Staff
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REDACTED
Putting together both lists,the table below shows the top offer for each project according
to PacifiCorp's net benefits calculation.
The top offer,by net benefits,was the PPA,followed by the
PPA,the PPA,and the and .Note
how close the offers are in price,with six projects net benefits in the $22-$27/MWhrange.
One issue that we note here is that PacifiCorp initially requested letters of commitment
from shortlisted bidders.During this process,PacifiCorp had objections to some of the forms of
6 Note that two bid options for the were removed from consideration due to the fact that
the bidder was not able to hold to their promise on-me ate as a result of delays in turbine manufacturing.
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Case No.PAC-E-17-07
M.Eldred,Staff
04/1 1/18 Page 27 of 42
commitment provided by bidders,while some bidders'financial backers objected to providing
such a letter of credit,since the letter compelled them to set aside collateral.Parties ultimately
decided to interpret the RFP rules as requiring credit commitments only 20 days after selection to
the Final Shortlist.We felt this was a reasonable compromise as it allowed PacifiCorp to
continue with the evaluation and select the best offers from a wide range before getting into a
discussion of what forms of collateral they would accept.
VII.FINAL SHORTLIST MODELING
A.INITIAL MODELING
To develop a Final Shortlist,bids on the Initial Shortlist were screened using the System
Optimizer Model ("SO Model").The SO analysis involved PacifiCorp creating a "base case"by
dispatching the system without new wind additions and the D2 Segment over a 20-year time
frame.The model added resources over the years in order to maintain a given reserve margin.
PacifiCorp then allowed the SO model to run again,this time allowing it to select a
combination of bids from the shortlisted offers that would minimize costs,including the D2
Segment,to ratepayers.One key assumption here was the amount of new supply from inside the
constrained area in Wyoming that would be enabled with the construction of the D2 segment.
PacifiCorp initially assumed 1,030 MW would be availablebut ultimately,as discussed later in
this report,decided that 1,270 MW could be incorporated onto the system with the addition of
the D2 Segment.
The SO Model can only analyze the least-cost resource choice under one scenario or
"path"of natural gas prices and CO2 OmiSSions costs at a time.PacifiCorp used three "paths"of
natural gas prices (high,medium and low).Medium natural gas price assumptions were based
on PacifiCorp's December forward price curve while high and low sensitivities were based on
consultation with third-party experts.The SO model also used three "paths"of CO2 COSts (high,
medium,and zero).The "medium"scenario started at $4.49/ton in 2030,rising to $7.95/ton in
2036 while the "high scenario"started at $3.62/ton in 2026 and rose to $19.23/ton in 2036.
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M.Eldred,Staff
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REDACTED
Taken together these three gas and three CO2 scenarios presented a total of nine specific "price-
policy"scenarios.
These nine cases produced just two distinct portfolios.The full analysis provided to the
IEs in January can be found in Attachment Two.
1.Under all scenarios the SO model selected the bid,
the Bids,the
bid and the bid.("Portfolio A")
2.In the medium gas,high CO2 case and in all three "high gas"cases the
model also selected the PPA.("Portfolio B")
All selected portfolios showed net benefits as compared to the base case,ranging
anywhere from $198 million to $782 million on a net present value basis.Benefits increased as
gas prices and emission costs increased.
Once the SO Model was run,the Company passed along these two distinct portfolios to
be assessed for stochastic risk.The term stochastic refers to assumptions being randomly varied
along a given distribution using a Monte Carlo method.Assumptions for five factors were
tested.Those five assumptions were load (electric demand),natural gas commodity prices,
wholesale electricity prices,hydro generation availability,and thermal generation availability.
Each portfolio was again assessed under the three CO2 price cases and three gas price paths.
The stochastic analysis was performed with the Planning and Risk ("PaR")Model.The
assumptions were randomly varied to result in 100 model runs for each case.This resulted in
100 different estimates of the cost -as measured by the present value of the revenue requirement,
or PVRR,over 20 years -for each case.The average (mean)of these 100 estimates was
provided as was the "risk-adjusted"mean which was equal to the average value plus the cost for
the case at the 95th PCTCCHÍÍÏC ÍÏmeS 5 percent.
7 Note that this run was prior to the discovery that offer had omitted W oming sales taxes.Subsequent
analysis incorporated this cost and resulted in the selection of the offer.
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M.Eldred,Staff
04/11/18 Page 29 of 42
Table 13 Modeling Results
SO Model PaR PaR Risk-Natural Gas CO2 Cost Portfolio (B i /ost P d)
Pa dd
($m)
Inw Zero A ($198)($153)($161)
Inw Medium A ($229)($162)($170)
Inw High A ($347)($306)($323)
Medium Zero A ($372)($319)($335)
Medium Medium A ($399)($349)($367)
Medium High B ($493)($445)($467)
High Zero B ($704)($572)($601)
High Medium B ($720)($604)($634)
High High B ($782)($689)($724)
Table 13 above shows that the stochastic analysis reduces benefits somewhat,but
benefits remain in each case.
The third step in the selection of the Final Shortlist was to use the SO Model to assess
how the cost of the two portfolios from the stochastic risk assessment vary with different
assumptions about fuel price and CO2 compliance costs.Recall that,unlike the PaR model,the
assumptions in the SO Model are definedoutright,not varied along a distribution.Unlike the
first step,where the SO Model was allowed to pick the ideal portfolio,in this analysis,each
portfolio is fixed,allowing the model to dispatch the resource as part of the portfolio.The
purpose of this step is to gather another data point regarding the risk of each portfolio.The result
is an estimate of how much a portfolio costs under less than ideal circumstances (i.e.,when key
risk factors do not move in its favor).The results of this analysis are presented in Table 14.Note
that table this does not include some costs for transmission improvements for Portfolio B that
PacifiCorp added after the fact,such costs tilted the selection to Portfolio A in the low and
medium gas scenarios.
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REDACTED
Tal>le 14 Scenario Modeling Results
Inw Zero ($198)($170)
Inw Medium ($229)($216)
Iow High ($347)($359)
Medium Zero ($372)($379)
Medium Medium ($399)($407)
Medium High ($493)($493)
High Zero ($692)($704)
High Medium ($709)($720)
High High ($770)($782)
This table shows that both portfolios produce positive benefits but that the portfolio with
more wind is slightlymore beneficial in higher gas price scenarios.This outcome make sense
since the cost of wind stays the same but the cost of other resources increases.Therefore,more
wind would generally be preferable in high gas price scenarios.
B.IE SENSITIVITY
We were somewhat surprised by the fact that the SO model would choose projects that
had lower net levelizednet benefits than other resources.Typically,we would expect resource
selection to mirror the levelizedcost analysis and,therefore,expected to see the and
PPAs selected before the Benchmark projects.
We questioned PacifiCorp regarding this outcome.One item that they identified as a
possible driver in the bid selection was the fact that,in order,to create the inputs for the SO
model,bid costs were levelizedbut any PTC benefits were not-that is,these credits were
flowed through as they were earned.Moreover,the SO Model covers the time period through
2036.Combined,these two factors meant that the SO Model spread the PTC benefits within the
period of study,instead of over a 30-year period as is done in the Company's levelization
models.This means that any offers earning PTCs would look more attractive than a levelized
cost model would otherwise indicate.
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M.Eldred,Staff
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REDACTED
To see if this was the case,we asked the Company to run the SO Model with medium gas
price and CO2 inputs and levelize PTCs over the 30-year life of BTA and Benchmark bids,
instead of treating them as earned.The results were more in line with the levelized cost models.
The SO model selected the PPA,the PPA,and the g
project.
At this point,PacifiCorp made the observation that the non-levelizedPTC selection
would more closely reflect how they planned to pass PTC benefits through to ratepayers.While
this was a reasonable assertion,we also noted that we had some concern that costs for their
selection would not be levelized in real life but would,in fact,be front-loadedas well due to the
way in which the costs for rate-based assets are recovered.Therefore,we had some concern that
the front-loadednature of rate recovery would cancel out the front-loadedbenefits of the PTC
recovery,and that the PPA-heavy portfolio was truly a better selection.
In response to this concern PacifiCorp produced an analysis looking at the actual flow of
cost recoveries,treating both PTCs and costs as incurred.The table below compares the two
portfolios,PacifiCorp's selected offers (PAC Portfolio)versus the PPA-heavy portfolio.Even
though the SO Model only covers through 2036 PacifiCorp extended the analysis out through the
2050 -the end of the BTA project's useful life -by assuming market energy prices would
simply increase with inflation each year after 2036.Note that PacifiCorp did not assume that
any new supply replaces expiring contracts.
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M.Eldred,Staff
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Table 15 Comparison of benefits ($m)
2017 ($0)($0)($0)($0)
2018 $0 $0 ($0)($0)
2019 ($0)($0)($0)($0)
2020 $7 $13 $5 $10
2021 $58 $46 $46 $42
2022 $40 $38 $73 $68
2023 $22 $31 $87 $87
2024 $1 $20 $88 $98
2025 ($17)$5 $78 $101
2026 ($25)$4 $65 $103
2027 ($34)($3)$49 $102
2028 ($57)($20)$24 $93
2029 ($88)($52)($13)$71
2030 ($96)($78)($51)$41
2031 ($0)($79)($51)$12
2032 ($4)($82)($53)($16)
2033 ($19)($97)($59)($48)
2034 ($31)($109)($68)($80)
2035 ($41)($141)($80)($120)
2036 ($56)($156)($95)($161)
2037 ($30)($108)($102)($188)
2038 ($36)($114)($110)($214)
2039 ($42)($120)($119)($240)
2040 ($49)($126)($129)($265)
2041 ($20)$39 ($133)($258)
2042 ($25)$37 ($137)($251)
2043 ($30)$35 ($142)($245)
2044 ($34)$34 ($147)($240)
2045 ($38)$32 ($153)($236)
2046 ($41)$31 ($158)($231)
2047 ($42)$30 ($163)($228)
2048 ($40)$30 ($168)($224)
2049 ($46)$28 ($173)($221)
2050 ($484)($28)($223)($224)
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M.Eldred,Staff
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REDACTED
While the PPA portfolio is more expensive in the early years,as we might assume since
the value of the PTC in a PPA is spread out over a longer period of time,by 2034 it has greater
cumulative benefits than PacifiCorp's selected portfolio.Even over the entire lifetime of all
projects,the PPA portfolio produced more net benefits.Note also that the onlyreason the
PacifiCorp portfolio was even close in net benefits over the entire time period was due to a large
terminal value applied to company-owned bids totaling about $374 million in 2050.Without the
terminal value the PPA portfolio produced a net cumulative benefit of $219 million versus $185
million for PacifiCorp's chosen portfolio.
C.INTERCONNECTION ANALYSIS
At this point we believedthat the PPA-heavy portfolio should be the top choice.
However,when we voiced this opinion to the Company they claimed that they had concerns
regarding interconnection costs for some of the offers.
Specifically,the original system impact studies for most bids assumed completion of
Gateway West and South projects by 2024.Because the Company had decided to move up the
completion date for the D2 Segment they had a concern that projects located farther back in the
interconnection queue would only be feasible to come online with the entire Gateway West and
South projects complete.
As background,PacifiCorp's transmission arm,which assesses interconnection costs,
must,by law,assume that each queue project is interconnected in order received so each project
assumes that all projects ahead of it in the queue are interconnected.As more projects in the
Wyoming area are interconnected it puts more strain on the transmission system until eventually
major upgrades such as the Gateway West and South projects are needed.
Based on this analysis PacifiCorp believedit was highlyunlikelythat projects higher up
in the queue would be able to interconnect with the D2 Segment alone.was one
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Exhibit No.103
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REDACTED
such project,as was PacifiCorp's McFadden Ridge Project.The ,andg
projects were noted to have low queue positions and would likely be safe.
The Company said that PacifiCorp transmission was in the process of restudying
interconnection costs assuming the accelerated completion schedule for the D2 Segment.At the
end of January PacifiCorp transmission issued revised system studies.PacifiCorp transmission
found that the Project with Queue number 713 triggered the need for major upgrades,stating:
"Additionally,the Q0713 project triggers the need for the Transmission Provider's planned
Energy Gateway South project.This project consists of a new 400 mile 500 kV transmission
line from the planned Aeolus substation in Wyoming to the Transmission Provider's existing
Clover substation in central Utah,with ancillary improvements."(See Attachment Three,page 8)
This meant that,in effect,any bid within the constrained area in Wyoming with a higher
queue number than 712 would require extensive new transmission investment to be deliverable
and likely would not be deliverableby the end of 2020.To see the effect on bids we can return
to our earlier table showing the best offers from each project.Again,any offers higher than 712
located in the constrained area in Wyoming would need the completion of the Gateway South
Project.
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M.Eldred,Staff
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REDACTED
From this table we see that based on this analysis a majority of offers are no longer viable
without major transmission investment.The g,and projects
are onlyviable because they are outside the constrained area in Wyoming.Inside the constraint
onlythree projects -,,and|-are viable.
PacifiCorp claimed that this was why they proposed in their initial RFP that bids must
have a completed system impact study;however,such a requirement would not have solved this
issue.The fact is that even for projects that had completed system impact studies at the time of
bid submission,those studies needed to be redone to account for the accelerated completion
schedule for the D2 Segment.And,once those studies were redone,the same result would have
occurred:projects with queue positions above 713 would have been effectively eliminated from
further consideration.
To its credit,PacifiCorp dropped pursuit of McFadden Ridge after this analysis.
However,these restudies showed more transfer capability from the constrained area than
PacifiCorp had been assuming.Earlier studies assumed about 1,030 MW of new supply was
enabled by the D2 Segment but PacifiCorp revised the number to 1,270 MW based on the sum of
the wind projects in the constrained area that could be accommodated prior to Gateway South
improvements."With this revision,PacifiCorp stated that the larger Ekola Flats project was now
selected as part of the optimal portfolio in the SO Model.Prior to this revision Ekola was not
selected because,at 250 MW,there was not enough transfer capability to accommodate it.
The net result of these adjustments calls for consideration of the overall context of the
RFP.Recall that in its RFP as originally drafted,PacifiCorp proposed to select onlyprojects
from the constrained area and offered three Benchmark projects.Based on the final analysis laid
out above,only one other third party bid on the shortlist (the project)could even
compete with these offers.In fact,only one other Wyoming wind offer -the
"Specifically,the company assumed Q542 (240 MW),Q706 (250 MW),Q707 (250 MW),Q 708 (250 MW),Q 712
(520 MW)could be accommodated for a total of 1,510 MW of interconnection capability.PacifiCorp then
subtracted 240 MW to account for a customer that already has an executed interconnection agreement,leaving a
total of 1,270 MW.
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Case No.PAC-E-17-07
M.Eldred,Staff
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wind proposal -had a high enough queue position to be viable.So this entire RFP really boiled
down to two viable benchmarks and two third-party offers,meaning a lot of the analysis
presented here was of questionable value.
To be clear,the remaining viable offers were competitive offers,but were not the best the
market could provide based on cost or risk,but for the transmission constraint issue.We
understand and appreciate PacifiCorp's position and do not disagree with their transmission
department's findings (beyond noting the obvious fact that many projects will likely drop out of
the queue and that actual interconnection costs will differ from projected).To go forward with
projects that cannot meet the proposed online date without major accelerated transmission
investment would not seem to be the wisest course of action
The real issue here is that PacifiCorp's procurement (in the form of this RFP)got out
ahead of its resource and transmission planning.If PacifiCorp had identified this plan earlier,
then all aspects of this work (IRP,transmission planning and resource acquisition)could have
worked together in a more coherent fashion.
D.REVISED FINAL SHORTLIST ANALYSIS
Based on these findings PacifiCorp completed additional analysis to confirm the Final
Shortlist selection.PacifiCorp updated their analysis to remove all non-viableoffers,update
interconnection costs,increase transfer capability from the D2 Segment and adjust the Invenergy
offer to include Wyoming sales taxes.The updated presentation is included here as Attachment
Four.
With these revisions,the SO Model selected a portfolio that included the Benchmark TB
Flats I and II bid,the Ekola Flats benchmark,the Cedar Springs BTA/PPA,and the Uinta BTA.
Benefits generally increased due to the larger amount of total supply selected (as the 109 MW
McFadden project was replaced by the 250 MW Ekola Flats project).
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M.Eldred,Staff
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REDACTED
Again,the outcome was not surprising given the fact that there were so few bids to
choose from and that,with the revised and increased costs for the Invenergybid options,the
Benchmark options generally were lower cost.
E.OTHER SENSITIVITIES
Along with the analysis described above PacifiCorp also provided additional sensitivities,
including a solar sensitivity and a wind repowering sensitivity.The goal of each analysis was to
ensure that other procurement activities did not lessen the benefits of this procurement.
For the solar sensitivity PacifiCorp ran the SO Model for two scenarios:(a)medium gas
and medium CO2 prices and (b)low gas no CO2 prices.PacifiCorp looked at value of adding
about 1,000 MW of new solar PPAs (a)instead of the shortlisted bids from the RFP and (b)
along with the shortlisted bids.Prices and quantities were based on initial results from
PacifiCorp's current solar RFP.
In all cases the combination of solar and shortlisted resources providedmore net benefits.
For example,in the medium gas medium CO2 Scenariobenefits of just solar were $343 million
on net whereas solar and the shortlisted bids provided $647 million of net benefits in the SO
Model.In the low gas zero CO2 Scenario solar PPAs alone provided $196 milliön of net benefits
but $312 million when combined with the shortlisted offers.
In the wind repowering scenario PacifiCorp allowed additionalrepowering of existing
units up to their large generator interconnection agreement ("LGIA")limits.Running the same
scenarios as with the solar sensitivity PacifiCorp found that benefits increased when repowering
was added to the shortlisted bids.For example,in the medium gas medium CO2 scenario
benefits increase to $608 million on net versus $405 million with justthe Final Shortlist offers
alone.
PacifiCorp also provided a sensitivity which tried to account for the fact that the turbines
used by the might require the installation of a synchronous condenser or other
equipment at the Aeolus substation to address performance issues.PacifiCorp ultimately
determined that upgrade costs would have to be in the
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M.Eldred,Staff
04/11/18 Page 38 of 42
REDACTED
.It was PacifiCorp's judgment that costs would not be
higher than this level.
Finally,per our request,PacifiCorp looked at the as-earnedcosts and benefits of the Final
Shortlist portfolio versus a portfolio in which the Cedar Springs PPA/BTA bid was replacedg
.Our reason
for requesting this was that we wanted to see if,as we found before,the actual recovery of costs
and benefits truly favored the full PPA option.
PacifiCorp calculated costs and benefits under the medium-gas medium CO2 cost
scenario for each portfolio as they had done before,looking at as-earnedcosts and benefits and
extendingthe analysis out to 2050 by assuming that energy benefits increase with inflation.
They found that theirpreferred portfolio had a cumulative net benefit of $298 million on a net
present value basis and the portfolio with had a value of $280 million
on a net present value basis.Removing the terminal value brings the numbers closer together,
but the company's preferred portfolio still has a greater net benefit,$255 to $250 million on a net
present value basis.
We do note that the portfolio with has a lower cumulative net
benefit from about 2033 through 2048,better risk protections,and offers the Company future
flexibility,making it a reasonable choice.However,given the fact that the total net benefits
favor PacifiCorp's selection we cannot conclude that the selection of the BTA/PPA bid is
unreasonable.
VIII.CONCLUSIONS AND RECOMMENDATIONS
We recommend that the Commission acknowledge PacifiCorp's Final Shortlist.The bids
do represent the top viable offers and are projected to provide net benefits.With proper risk
mitigation the offers can provide value to ratepayers.While it is our understanding that the 2017
IRP is approved,we have yet to see a final approval order and are unaware of any potential
conditions that may come with the approval order.For the purposes of this report,we assume
there are no conditions that alter our recommendation here.
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M.Eldred,Staff
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A majority of the selected offers here are BTAs and Benchmark resources.These bids
offer at least two risks that are not generally present in power purchase agreements:(a)the risk
of capital and operating cost overruns and (b)failure to claim the full value of the Production
Tax Credit.Some of these risks can and will be managed in the BTA and EPC contracts the
company will sign,but the protection will not be as strong as in a PPA.Developers can promise
to deliver PTC complaint equipment and install by a certain time,but,several of these projects
are dependent on PacifiCorp's transmission arm completing the D2 Segment in order to achieve
deliverability.
In order to achieve a level of risk protection similar to a PPA for ratepayers,PacifiCorp
must guarantee that capital and O&M costs will not exceed the amounts forecasted here and that
ratepayers will be credited the full PTC values projected here as well regardless of whether or
not PacifiCorp has the taxable income to utilize the credits.For reference,we include the final
cost projections for each resource from the Company here as Attachment Five.
To be clear these should be "hard"guarantees as would be found in a commercial
contract.PacifiCorp should not be permitted to recover additional costs or not credit full value
of the PTC due to force majeure or change in law events.The risk regarding the PTC is
exceptionally important.As we have just seen with corporate tax reform (and the debate that
took place prior to the law's passage in which the PTC was considered briefly for major
overhaul),the value of the credit can change rapidly.
Again,the reason that the Company should take this risk without exception is that a
commercial developer will take this risk in a PPA.By way of example,the pro forma PPA in
this RFP has this to say about tax credits:
ii."Seller shall bear all risks,financial and otherwise throughoutthe Term,
associated with Seller's or the Facility's eligibility to receive PTCs,ITCs
or other Tax Credits,or to qualify for accelerated depreciation for Seller's
accounting,reporting or tax purposes.The obligations of the Parties
hereunder,including those obligationsset forth herein regarding the
purchase and price for and Seller's obligation to deliver Net Output,shall
be effective regardless of whether the sale of Output or Net Output from
38|Page
Exhibit No.103
Case No.PAC-E-17-07
M.Eldred,Staff
04/11/18 Page 40 of42
the Facility is eligible for,or receives,PTCs,ITCs or other Tax Credits
during the Term.""
A related risk that was not analyzed is the risk of cost overruns for the D2 Segment.
Because there is no real competition for this service it is more likely that cost overruns would
occur here.These cost projections are important becausethey are a major driver of selection in
this RFP.If actual costs are higher it may turn out that a better solution would have been to
select more supply from outside the constrained area in Wyoming.Therefore,PacifiCorp should
also be held to its cost projection for the D2 Segment.The revenue requirement numbers used in
this analysis are included in Attachment Six.
In addition,the selected portfolio contains mostly options to be owned by the company.
As a result PTC benefits are projected to flow to customers for the first ten years of operation as
incurred.However,after the end of the ten-year PTC window these credits disappear and costs
increase.PacifiCorp currently projects a $125 million cost increase in 2031.If the Commission
believes such an increase would be unreasonable they should consider enacting some form of
rate mitigation efforts in the future.
Going forward,many of the issues in this RFP were primarily caused by the resource
acquisition function getting ahead of the resource planning and transmission planning function.
Soon after the PTC sunset was established at the end of 2015,PacifiCorp's IRP team should
have begun to consider if this change would drive them to pursue more renewable supply.
Earlier consideration of this fact could have spurred debate about the proposal and possibly
achieved earlier IRP approval as well as earlier revision of transmission planning in system
impact studies.As it was the process was rushed and ultimately very few bids could be called
viable.
In the future parties should seek better alignment of all these functions.Other tax credits
(e.g.,the Investment Tax Credit)are also planned to sunset and PacifiCorp has more
transmission investment planned.As the next IRP process gets started parties should be asking
what schedule PacifiCorp plans to pursue.Will they pursue additional solar with the sunset of
9 Draft PPA section 2.8
39)Page
Exhibit No.103
Case No.PAC-E-17-07
M.Eldred,Staff
04/11/18 Page 41 of42
the ITC?Would it make sense to accelerate any other portions of the Gateway project?Earlier
consideration of these questions can lead to better and more transparent outcomes for all.
Finally,from a bid analysis standpoint any future modeling should at least consider the
effect of unleveling of tax credit benefits.As demonstrated in our requested sensitivities if the
production cost modeling does not consider the entire life of an asset then leveledbenefits can
force a choice of a suboptimal offer.
40|Page
Exhibit No.103
Case No.PAC-E-17-07
M.Eldred,Staff
04/11/18 Page 42 of42
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 11th DAY OF APRIL 2018,
SERVED THE FOREGOING NON-CONFIDENTIAL SUPPLEMENTAL TESTIMONY
OF MICHAEL ELDRED,IN CASE NO.PAC-E-17-07,BY MAILING A COPY
THEREOF,POSTAGE PREPAID,TO THE FOLLOWING:
TED WESTON YVONNE R HOGLE
ROCKY MOUNTAIN POWER ASSISTANT GENERAL COUNSEL
1407 WEST NORTH TEMPLE STE 330 ROCKY MOUNTAIN POWER
SALT LAKE CITY UT 84116 1407 WN TEMPLE STE 320
E-MAIL:[e-mail] SALT LAKE CITY UT 84116
(Non-ConfidentialTestimony)E-MAIL:[e-mail]
(Confidential Testimony)
DATA REQUEST RESPONSE CENTER RANDALL C BUDGE
E-MAIL ONLY:RACINE OLSON NYE &BUDGE
[e-mail] PO BOX 1391
(Non-ConfidentialTestimony)POCATELLO ID 83204-1391
E-MAIL:[e-mail]
(Non-Confidential Testimony)
BRUBAKER &ASSOCIATES RONALD L WILLIAMS
16690 SWINGLEY RIDGE RD #140 WILLIAMS BRADBURY PC
CHESTERFIELD MO 63017 PO BOX 388
E-MAIL:[e-mail] BOISE ID 83701
[e-mail] E-MAIL:[e-mail]
(Non-ConfidentialTestimony)(Non-ConfidentialTestimony)
ELECTRONIC ONLY ELECTRONIC ONLY
JIM DUKE KYLE WILLIAMS
IDAHOAN FOODS BYU IDAHO
E-MAIL:[e-mail] E-MAIL:[e-mail]
(Non-ConfidentialTestimony)(Non-Confidential Testimony)
ELECTRONIC ONLY ERIC L OLSEN
VAL STEINER ECHO HAWK &OLSEN
NU-WEST INDUSTRIES INC PO BOX 6119
E-MAIL:[e-mail] POCATELLO ID 83205
(Non-ConfidentialTestimony)E-MAIL:[e-mail]
(Non-ConfidentialTestimony)
ANTHONY YANKEL BRADLEY MULLINS
UNIT 2505 333 SW TAYLOR
12700 LANE AVENUE SUITE 400
LAKEWOOD OH 44107 PORTLAND OR 97204
E-MAIL:[e-mail] E-MAIL:[e-mail]
(Non-ConfidentialTestimony)(Non-Confidential Testimony)
SECRETAlkY
CERTIFICATE OF SERVICE