20180216Link 2nd Suppl Direct - Redacted.pdf

Idaho Public Utilities CommissionOfficeoftheSecretaryRECEIVED
FEB 1 6 2018
Boise,idaho
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )CASE NO.PAC-E-17-07
OF ROCKY MOUNTAIN POWER FOR A )CERTIFICATE OF PUBLIC )SECOND SUPPLEMENTAL DIRECT
CONVENIENCE AND NECESSITY AND )TESTIMONY OF RICK T.LINK
BINDING RATEMAKING TREATMENT )REDACTED
FOR NEW WIND AND TRANSMISSION )
FACILITIES )
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ROCKY MOUNTAIN POWER
CASE NO.PAC-E-17-07
February2018
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1 Q.Are you the same Rick T.Link who previously provided testimony in this case on
2 behalf of Rocky Mountain Power,a division of PacifiCorp?
3 A.Yes.
4 PURPOSE AND SUMMARY OF TESTIMONY
5 Q.What is the purpose of your second supplemental direct testimony?
6 A.I summarize the updated results of the 2017R Request for Proposals ("RFP").I also
7 provideupdatesto the economic analysis that demonstrate increasing customer benefits
8 from the new wind resources ("Wind Projects")and construction of the Aeolus-to-
9 Bridger/Anticline line and network upgrades ("Transmission Projects")(collectively,
10 the "Combined Projects").
11 Q.Please summarize your second supplemental direct testimony.
12 A.The updated 2017R RFP final shortlist replaces the company's McFadden Ridge IIO13benchmarkbidwiththeEkolaFlatsbenchmarkbid.All of the other winning bids
14 included in the original final shortlist remain in the updated final shortlist.The total
15 capacity of the winning bids in the updated final shortlist is 1,311 MW,which includes
16 three of the benchmark facilities (TB Flats I and II,now combined as a single project,
17 and Ekola Flats),and two new facilities (Cedar Springs and Uinta).Uinta is a build-
18 transfer agreement ("BTA")totaling 161 MW,Cedar Springs is one-half BTA and one-
19 half power-purchase agreement ("PPA"),for a total of 400 MW,and TB Flats I and II
20 and Ekola Flats are company-built facilities,totaling 500 MW and 250 MW,
21 respectively.
22 The updated results ofthe 2017R RFP and the extensive modeling that supports
23 it continue to confirm that the Combined Projects are the least-cost,least-risk path
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1 availableto serve the company's customers by meeting both near-term and long-term
2 needs for additional resources.My second supplemental direct testimony explains the
3 following:
4 The Combined Projects continue to provide net customer benefits under all
5 scenarios studied through 2036,and in seven of the nine scenarios through
6 2050.
7 Customer benefits increase to $196 million in the medium case through 2050
8 (as compared to $177 million in the supplemental direct filing),and range from
9 $333 million to $405 million in the medium case through 2036.
10 The analysis reflects consideration of an interconnection-restudy process,that:
11 1)eliminated certain bids,including the company's McFadden Ridge II
12 benchmark bid,from consideration in the 2017R RFP;and 2)supported an
13 increaseto the assumed level of interconnection capacity in the constrained area
14 of PacifiCorp's system in eastern Wyoming.
15 Sensitivity analysis continues to show substantial benefits of the Combined
16 Projects persist when paired with PacifiCorp's wind repowering project and are
17 not displaced or reduced when considering the potential procurement of solar
18 PPA bids,updated with best-and-final pricing,submitted into the on-going RFP
19 for solar resources,the 2017S RFP.
20 UPDATED 2017R RFP FINAL SHORTLIST
21 Q.Did the company update the list of winning bids from the 2017R RFP?
22 A.Yes.The company's 109 MW McFadden Ridge II benchmark resource was removed
23 from the final shortlist and replaced with the company's 250 MW Ekola Flats
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1 benchmark resource.All of the other winning bids included in the original final shortlist
2 remain in the updated final shortlist.The total capacity of the winning bids in the
3 updated final shortlist is 1,311 MW.The winning bids included in the updated final
4 shortlist are listed in Table 1-SS.
5 Table 1-SS.Updated 2017R RFP Final Shortlist
Project Name (Bidder)Location Capacity (MW)
TB Flats I &II (PacifiCorp)Carbon &Albany 500Counties,WY
Cedar Springs (NextEra Converse County,400EnergyAcquisitions)WY
Ekola Flats (PacifiCorp)Carbon County,WY 250
Uinta (InvenergyWind Uinta County,WY 161
Development)
6 The TB Flats I &II and Ekola Flats projects are company-benchmark resources
7 that will be developed under engineer,procure,and construction ("EPC")agreements.
8 The Uinta project is being developed by Invenergy Wind Development under a BTA.
9 The Cedar Springs project is being developed by NextEra Energy Acquisitions as a 50-
10 percent BTA and a 50-percent PPA.In total,the updated final shortlist includes 361
ll MW that will be developed under BTAs,750 MW of benchmark capacity that will be
12 developed under EPC agreements,and 200 MW that will deliver energy and capacity
13 under a PPA.
14 Q.Please summarize the cost-and-performance attributes of the winning bids.
15 A.The total in-service capital cost for the winning bids is $1.46 billion.Considering that
16 the winning bids represent an increase in total owned-wind capacity (from just over
17 860 MW in the company's initial filing to approximately 1,111 MW),the per-unit
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l capital cost for the updated final shortlist is down approximately 18 percent from
2 $1,590/kW to $1,310/kW.
3 In addition to these capital costs,the PPA price that will be paid to NextEra
4 Energy Acquisitions for 50 percent of the output from the Cedar Springs project is
5 expected to add approximately to total-system net power
6 costs ("NPC").These costs are
7 significantly lower than proxy PPA costs that were based off of certain qualifying
8 facility ("QF")projects that were included in the company's initial filing,which were
9 assumed to add to total-system NPC beginning 2022,
10 rising to by the end of2041.This proxy QF project,which
ll requires interconnection facilities beyond the Aeolus-to-Bridger/Anticline
12 transmission line that cannot be built until 2024,is no longer included in the company's
13 economic analysis of the Combined Projects.
14 In aggregate,the winning bids are expected to operate at a capacity-weighted
15 average annual capacity factor of 39.4 percent.
16 The in-service cost for network upgrades required to interconnect the final
17 shortlist projects total ,and the cost to build the Aeolus-to-
18 Bridger/Anticline transmission line remains at .The expected cost-and-
19 performance attributes for the winning bids and the Transmission Project is
20 summarized in more detail in Confidential Exhibit No.54.
21 Q.Why was the 2017R RFP final shortlist updated?
22 A.The 2017R RFP final shortlist was updated to account for the results of an
23 interconnection-restudy process.As described in Mr.Rick A.Vail's second
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l supplemental direct testimony,the company completed an interconnection-restudy
2 process to ensure that interconnection studies reflected the most current long-term
3 transmission plan to construct the Aeolus-to-Bridger/Anticline D.2 segment of the
4 Energy Gateway project by the end of 2020.PacifiCorp transmission restudied,in serial
5 interconnection-queue order,interconnection requests that do not already have an
6 interconnection agreement to determine whether the staging of the Energy Gateway
7 West project would affect the cost or timing of projects whose previous interconnection
8 studies depended on Gateway West in its entirety.Affected projects located in the
9 constrained area of PacifiCorp's transmission system in eastern Wyoming were
10 restudied through the point in the interconnection queue where additional segments of
11 the Energy Gateway project beyond just the Aeolus-to-Bridger/Anticline D.2 segment
12 would be required to interconnect.O 13 PacifiCorp transmission posted the restudied system-impact studies ("SISs")on
14 PacifiCorp's open access same-time information system ("OASIS")on January 29,
15 2018,as well as certain updated restudied SISs on February 9,2018.
16 Q.How did the interconnection-restudy process affect 2017R RFP winning bid
17 selections?
18 A.As described by Mr.Vail,the interconnection-restudy process confirmed that 2017R
19 RFP bids located in eastern Wyoming with an interconnection-queue position greater
20 than Q0712 trigger the need for Energy Gateway South,which is not planned to be
21 placed in service by the end of 2020.Consequently,any bid proposing a project in the
22 constrained area of PacifiCorp's transmission system with an interconnection-queue
23 position greater than Q0712 cannot receive interconnection service and achieve
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l commercial operation by the end of2020 as required in the 2017R RFP.This includes
2 the company's McFadden Ridge II benchmark bid that was originally selected to the
3 final shortlist.All other bids originally selected to the final shortlist can secure
4 interconnection service either because they hold an interconnection-queue position that
5 does not require Energy Gateway South (Ekola Flats,TB Flats I and II,and Cedar
6 Springs)or because the project is not located in the constrained area of the company's
7 eastern Wyoming transmission system (Uinta).
8 Q.Were there other findings from the interconnection-restudy process that affected
9 selection of winning bids to the updated 2017R RFP final shortlist?
10 A.Yes.As noted by Mr.Vail,the interconnection-restudy process shows that the Aeolus-
11 to-Bridger/Anticline transmission line will enable interconnection of up to 1,510 MW
l2 of new wind capacity within the constrained area of PacifiCorp's transmission system
13 in eastern Wyoming.This is up from the 1,270 MW assumed in the bid-selection
14 process summarized in my supplemental direct testimony.
15 As stated in my supplemental direct testimony,there is a 240 MW QF project
16 with an executed interconnection agreement that does not require construction of
17 Energy Gateway West and South to accommodate the QF's interconnection.To honor
18 this agreement,the company must reserve sufficient interconnection capacity for this
19 interconnection customer.After setting aside interconnection capacity for this
20 interconnection customer,the interconnection-restudy process shows that the Aeolus-
21 to-Bridger/Anticline transmission line can enable interconnection of up to 1,270 MW
22 of new wind located in the constrained area of PacifiCorp's transmission system in
23 eastern Wyoming.This is up from the 1,030 MW assumed in the bid-selection process
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l summarized in my supplemental direct testimony.
2 Q.Why did the company not consider the interconnection-queue position of bids
3 when it originally identified bids selected to the final shortlist?
4 A.The company has been aware that it would need to factor interconnection requirements
5 into its evaluation of the 2017R RFP bids since the beginning of the RFP process.
6 Indeed,the company originally included a completed SIS as one of the minimum bid-
7 eligibility requirements.In response,however,to recommendations from the Utah
8 independent evaluator ("IE"),the company agreed to remove the requirement that a
9 bidder have a completed SIS to be eligible to submit a proposal.
10 Q.Did elimination of the SIS requirement benefit the 2017R RFP process?
11 A.Yes.While the removal of the SIS requirement meant that the company could not fully
12 evaluate the relative interconnection requirements of the bids early in the process,it
13 agreed to relax the requirement that bidders have a completed SIS to broaden market
14 participationin the 2017R RFP because bidders could participate without regard to their
15 interconnection queue position.This enhances competition and provides an incentive
16 for bidders to offer low-cost proposals.In addition,the interconnection queue can
17 change over time as generator-interconnection customers change project details,
18 request commercial operation date extensions or suspensions,or even withdraw from
19 the queue altogether.Had the requirement that bidders have a SIS been retained,the
20 pool of eligible bidders would have been limited based on the then-current snapshot of
21 the interconnection queue,which would have reduced competitive forces that drive
22 least-cost bidding.
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l Q.How did the company establish its updated final shortlist that accounts for the
2 findings from the interconnection-restudy process?
3 A.The company produced updated portfolio-development studies using the System
4 Optimizer ("SO")model to create a bid portfolio containing the least-cost combination
5 of viable bids.In choosing the least-cost combination of bids,the SO model was
6 configured to select from all viable bid alternatives,excluding bids located in the
7 constrained area of PacifiCorp's transmission system in eastern Wyoming,that have an
8 interconnection-queue position greater than Q0712.Consistent with the increased
9 interconnection capability identified during the interconnection-restudy process,the
10 SO model was also configured to select up to 1,270 MW of bids located in this area of
11 PacifiCorp's transmission system.The updated portfolio-development studies were
12 developed under two price-policy scenarios-low natural gas,zero CO2 and medium
13 natural gas,medium CO2.
14 Q.Did the company update its price-policy scenario assumptions?
15 A.No.The price-policy scenario assumptions summarized in my supplemental direct
16 testimony remain valid and were not updated for this analysis.
17 Q.Why did the company update its portfolio-development studies using only the low
18 natural gas,zero CO2 and medium natural gas,medium CO2 price-policy
19 assumptions?
20 A.As described in my supplemental direct testimony,the company originally produced
21 least-cost bid portfolios for all nine price-policy scenarios.That analysis identified a
22 bid portfolio that included the original final shortlist of projects plus an additionalbid.
23 The additional bid was included in the bid portfolio only in the medium natural gas,
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1 high CO2 price-policy scenario and in the three price-policy scenarios that assume high
2 natural gas price assumptions.The bid portfolio with the incremental bid did not
3 generate favorable net benefits for customers relative to the portfolio containing the
4 original final shortlist of projects when applying low natural gas price-policy
5 assumptions or when applying price-policy assumptions paring medium natural gas
6 prices with zero or medium CO2 prices.Based on these results,the company evaluated
7 bid selections assuming base case (medium natural gas,medium CO2 price)and worst
8 case (low natural gas,zero CO2)price-policy assumptions.
9 Q.Did the company update any bid-cost assumptions when developing its updated
10 portfolio-developmentstudies?
11 A.Yes.The company updated bid-cost assumptions to align interconnection network
12 upgrade costs with those identified in the SISs posted on PacifiCorp's OASIS.The
13 company also updated sales-tax estimates for all bids submitted by
14 -replacing the company's sales-tax estimates assumed when establishing
15 the original final shortlist with sales-tax costs supplied by the bidder.
16 Q.What bids were selected by the SO model in the updated portfolio-development
17 studies?
18 A.The SO model selected the same four bids,included in the company's updated final
19 shortlist as summarized in Table 1-SS,in the low natural gas,zero CO2 and the medium
20 natural gas,medium CO2 price-policy scenarios.
21 Q.Did the company update its economic analysis to account for the updated final
22 shortlist?
23 A.Yes.The economic analysis among all nine price-policy scenarios was refreshed to
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l reflect those bids selected in the updated 2017R RFP final shortlist.This analysis was
2 updated using the SO model and the Planning and Risk model ("PaR").I describe the
3 company's updated economic analysis later in my testimony.
4 Q.Did the company inform the Utah and Oregon IEs of changes to the 2017R RFP
5 final shortlist resulting from the interconnection-restudyprocess described
6 above?
7 A.Yes.On January 19,2018,the company discussed the potential impacts of the
8 interconnection-restudy process with the Utah and Oregon IEs.Specifically,the
9 company explained that,although no definitive determinations could be made until
10 restudy process was completed,certain bids with a relatively high interconnection-
ll queue position located in eastern Wyoming,including the company's McFadden Ridge
12 II benchmark,may not be viable.On February 12,2018,after the interconnection-O 13 restudy process and bid-selection analysis was completed,the company submitted its
14 updated final shortlist recommendation to the Utah and Oregon IEs.
15 Q.Did the Utah and Oregon IEs request any additional sensitivity studies as the
16 company was finalizingits updated final shortlist recommendation?
17 A.Yes.The Utah and Oregon IEs requested a sensitivity to assess how projected net
18 benefits from the updated final shortlist would be affected if
19
20 The Utah and Oregon IEs requested that this sensitivity be developed using the SO
21 model with medium natural gas,medium CO2 price-policy scenario assumptions.
22 Q.What were the findings from this IE sensitivity?
23 A.The present-value revenue requirement differential ("PVRR(d)")based on SO model
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l results through 2036 under the IE sensitivity showed a $25 million reduction in net
2 customer benefits if
3 .The IE sensitivity also showed customer
4 costs would increase over both the near term and long term if
5
6 Q.Did the company change its updated 2017R RFP final shortlist based on the IE
7 sensitivity?
8 A.No.
9 Q.Does the Utah IE report on the 2017R RFP final shortlist,dated February 15,
10 2018,support the final shortlist?
11 A.Yes.The IE concluded that the Company conducted the 2017R RFP in a consistent
12 and fair manner and agreed that the Company's final shortlist was reasonable.
13 UPDATED ECONOMIC ANALYSIS
14 Q.Did the company refresh any other assumptions not already identified above in
15 the updated final shortlist economic analysis?
16 A.No.
17 Q.Did the company continue to apply production tax credit ("PTC")benefits
18 applicable to BTAs and benchmark-EPC bids on a nominal basis in its system
19 modeling using the SO model and PaR configured to forecast system costs through
20 2036?
21 A.Yes.As described in my supplemental direct testimony,this approach better reflects
22 how the federal PTC benefits for these bids will flow through to customers and aligns
23 the treatment of federal PTC benefits in the system modeling results extending out
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l through 2036 with the nominal revenue requirement results extending out through
2 2050.It also ensures the 2017R RFP bid selections from the SO model more accurately
3 reflect the difference in how BTA and benchmark-EPC bids are expected to impact
4 customer rates.
5 Q.Did the company continue to apply revenue requirement associated with capital
6 costs on a levelized basis in its system modeling using the SO model and PaR
7 configured to forecast system costs through2036?
8 A.Yes.As discussed in my supplemental direct testimony,when setting rates,revenue
9 requirement from capital costs is depreciated over the book life of the asset,effectively
10 spreading the cost of capital investments over the life of the asset.Because revenue
11 requirement from capital projects is spreadover the life of the asset in rates,these costs
12 continue to be treated as a levelized cost in the SO model and PaR simulations.
13 Q.Did the company update its revenue-requirement modeling among different price-
14 policy scenarios to reflect the updated final shortlist and modeling updates
15 described above?
16 A.Yes.Using the same annual revenue-requirement modeling methodology described in
17 my direct and supplemental direct testimony,the company updated its forecast of the
18 change in nominal annual revenue requirement due to the Combined Projects.As was
19 done in the economic analysis summarized in my direct and supplemental direct
20 testimony,revenue requirement from capital associated with the Combined Projects is
21 treated as a nominal cost when the results are extrapolated out through 2050.
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1 UPDATED SYSTEM MODELING PRICE-POLICY RESULTS
2 Q.Please summarize the updated PVRR(d)results calculated from the SO model and
3 PaR through 2036.
4 A.Table 2-SS summarizes the updated PVRR(d)results for each price-policy scenario
5 alongside the same results summarized in my supplemental direct testimony.The
6 PVRR(d)between cases with and without the Combined Projects,reflecting the
7 updated final shortlist from the 2017R RFP,are shown for the SO model and for PaR,
8 which was used to calculate both the stochastic-mean PVRR(d)and the risk-adjusted
9 PVRR(d).The data used to calculate the updated PVRR(d)results shown in the table
10 are provided as Exhibit No.55.
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l Table 2-SS Updated SO Model and PaR PVRR(d)
(Benefit)/Cost of the Combined Projects ($million)
Second Supplemental Direct Supplemental Direct
(Und:ted Final Shrrtlist3 (Orivinal Final Shcrtlist)
PaR PaR
Stochastic PaR Risk-Stochastic PaR Risk-
SO Model Mean Adjusted SO Model Mean Adjusted
Price-Policy Scenario PVRR(d)PVRR(d)PVRR(d)PVRR(d)PVRR(d)PVRR(d)
Low Gas,Zero CO2 ($185)($126)($l32)($145)($104)($l09)
Low Gas,Medium CO2 ($208)($155)($164)($186)($124)($131)
Low Gas,High CO2 ($370)($313)($331)($297)($258)($272)
Medium Gas,Zero CO2 ($377)($295)($310)($306)($246)($258)
Medium Gas,Medium CO2 ($405)($333)($362)($343)($311)($327)
Medium Gas,High CO2 ($489)$(424)($445)($430)($388)($406)
High Gas.Zero CO2 ($699)($545)($572)($619)($509)($535)
High Gas,Medium CO2 ($716)($579)($609)($636)($539)($567)
High Gas,High CO2 ($781)($671)($705)($696)($605)($636)
2 Over a 20-year period,the Combined Projects reduce customer costs in all nine
3 price-policy scenarios.This outcome is consistent in both the SO model and PaR
4 results.Under the central price-policy scenario,when applying medium natural gas,
5 medium CO2 price-policy assumptions,the PVRR(d)net benefits range between $333
6 million (up from $311 million),when derived from PaR stochastic-mean results,and
7 $405 million (up from $343 million),when derived from SO model results.Net benefits
8 increase relative to those shown in my supplemental direct testimony.This is driven by
9 the increased interconnection capacity associated with the Aeolus-to-Bridger/Anticline
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l transmission line,which enables selection of the Ekola Flats benchmark resource.
2 Without this update,there was not sufficient interconnection capacity to accommodate
3 the Ekola Flats benchmark with the TB Flats I &II and Cedar Springs bids.
4 Q.Did you update the potential upside to these PVRR(d)results associated with
5 renewable energy credit ("REC")revenues?
6 A.Yes.Consistent with my direct and supplemental direct testimony,the PVRR(d)results
7 presented in Table 2-SS do not reflect the potential value of RECs generated by the
8 incremental energy output from the updated final shortlist projects.Accounting for the
9 performance estimates from the updated final shortlist projects,customer benefits for
10 all price-policy scenarios would improve by approximately $34 million (up from $31
11 million in my supplemental direct analysis)for every dollar assignedto the incremental
12 RECs that will be generated from the winning bids through 2036.Quantifying the
13 potential upside associated with incremental REC revenues is simply intended to
14 communicate that the net benefits from the winning bids could improve if the
15 incremental RECs can be monetized in the market.
16 Q.Did you update the potential upside to these PVRR(d)results associated with
17 reduced operations and maintenance ("O&M")costs?
18 A.Yes.Consistent with my supplemental direct testimony,projects with large wind
19 turbines are expected to require less O&M costs because there are fewer turbines on a
20 given site.The default O&M assumptions applied to BTA and benchmark-EPC bids in
21 the updated economic analysis are based on the company's experience in operating and
22 maintainingthe existing fleet of owned-wind facilities,and do not reflect expected cost
23 savings associated with operating and maintaining wind facilities proposing to use
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1 larger wind turbines.Three of the winning bids-InvenergyWind Development's Uinta
2 project,the company's TB Flats I &II project,and the company's Ekola Flats project-
3 will use larger equipment for a portion of the wind turbines at each facility.If the O&M
4 cost elements applicable to the larger-turbine equipment are reduced by 42 percent,
5 which is equivalent to an approximately 18 percent reduction in total O&M costs,
6 beyond the proposed O&M agreement period,customer benefits calculated through
7 2036 for all price-policy scenarios would improve by approximately $19 million (up
8 from $13 million in my supplemental direct testimony).
9 Q.Is there additional upside to the net benefits shown in Table 2-SS?
10 A.Yes.The CO2 price assumptions used in the updated economic analysis were
11 inadvertently modeled in 2012 real dollars instead of nominal dollars.Consequently,
12 the PVRR(d)net benefits in the six price-policy scenarios that use medium and high
13 CO2 price assumptions are conservative.
14 UPDATED REVENUE REQUIREMENTMODELING PRICE-POLICY RESULTS
15 Q.Please summarize the updated PVRR(d)results calculated from the change in
16 annual revenue requirement through2050.
17 A.Table 3-SS summarizes the updated PVRR(d)results for each price-policy scenario
18 calculated off of the change in annual nominal revenue requirement through 2050
19 alongside the same results summarized in my supplemental direct testimony.The
20 annual data over the period 2017 through 2050 that was used to calculate the updated
21 PVRR(d)results shown in the table are provided as Exhibit No.56.
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l Table 3-SS.Updated Nominal Revenue Requirement PVRR(d)
(Benefit)/Cost of the Combined Projects ($million)
Second
Supplemental Supplemental
Direct Direct
(Updated Final (Original Final
Price-Policy Scenario Shortlist)Shortlist)
Low Gas,Zero CO2 $155 $169
Low Gas.Medium CO2 $98 $133
Low Gas,High CO2 ($176)($l05)
Medium Gas,Zero CO2 ($121)($60)
Medium Gas.Medium CO2 ($196)($l77)
Medium Gas,High CO2 ($333)($30 l)
High Gas.Zero CO2 ($477)($437)
High Gas,Medium CO2 ($528)($479)
High Gas.High CO2 ($664)($585)
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2 When system costs and benefits from the Combined Projects are extended out
3 through 2050,covering the full depreciable life of the owned-wind projects included in
4 the updated 2017R RFP final shortlist,the Combined Projects reduce customer costs in
5 seven out of nine price-policy scenarios.Customer net benefits range from $12l million
6 in the medium natural-gas,zero CO2 price-policy scenario (up from $60 million)to
7 $664 million in the high natural gas,high CO2 price-policy scenario (up from $585
8 million).Under the central price-policy scenario,when applying medium natural gas,
9 medium CO2 price-policy assumptions,the PVRR(d)benefits of the Combined
10 Projects are $196 million (up from $177 million).The Combined Projects provide
11 significant customer benefits in all price-policy scenarios,and the net benefits are
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1 unfavorable only when low natural-gas prices are paired with zero or medium CO2
2 prices.These results continue to show that upside benefits far outweigh downside risks.
3 As is the case with the system-modeling results,net benefits increase relative
4 to those shown in my supplemental direct testimony.As stated earlier,this is driven by
5 the increased interconnection capacity associated with the Aeolus-to-Bridger/Anticline
6 transmission line,which enables selection of the Ekola Flats benchmark resource.
7 Without this update,there was not sufficient interconnection capacity to accommodate
8 the Ekola Flats benchmark with the TB Flats I &II and Cedar Springs bids.
9 Q.Is there additional potential upside to these PVRR(d)results associated with REC
10 revenues?
ll A.Yes.Consistent with my direct and supplemental direct testimony,the PVRR(d)results
12 presented in Table 3-SS do not reflect the potential value of RECs generated by theO13incrementalenergyoutputfromtheWindProjects.Accounting for the performance
14 estimates from the updated final shortlist projects,customer benefits for all price-policy
15 scenarios would improve by approximately $43 million (up from $39 million in my
16 supplemental direct analysis)for every dollar assigned to the incremental RECs that
17 will be generated from the winning bids through 2050.
18 Q.Is there additional potential upside to these PVRR(d)results associated with
19 reduced O&M costs?
20 A.Yes.As discussed above,the company anticipates O&M costs for those projects that
21 will install larger-turbine equipment to be lower than what has been reflected in the
22 updated economic analysis.Accounting for these cost savings,customer benefits for
23 all price-policy scenarios would improve by approximately $31 million (up from $22
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l million in my supplemental direct testimony)when calculated from projected operating
2 costs through 2050.
3 Q.Is there additional potential upside to these PVRR(d)results shown in Table 3-SS?
4 A.Yes.As noted earlier,the updated CO2 price assumptions used in the updated economic
5 analysis were inadvertently modeled in 2012 real dollars instead of nominal dollars.
6 Consequently,the PVRR(d)net benefits in the six price-policy scenarios that use
7 medium and high CO2 price assumptions are conservative.
8 Q.Please describe the change in annual nominal revenue requirement from the
9 Combined Projects.
10 A.Figure 1-SS shows the updated change in nominal revenue requirement due to the
11 Combined Projects for the medium natural gas,medium CO2 price-policy scenario on
12 a total-system basis.These results are shown alongside the same results from theO13economicanalysissummarizedinmysupplementaldirecttestimony.The change in
14 nominal revenue requirement shown in the figure reflects updated costs,including
15 capital revenue requirement (i.e.,depreciation,return,income taxes,and property
16 taxes),O&M expenses,the Wyoming wind-productiontax,and PTCs.The project costs
17 are netted against updated system impacts from the Combined Projects,reflecting the
18 change in NPC,emissions,non-NPC variable costs,and system fixed costs that are
19 affected by,but not directly associated with,the Combined Projects.
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l Figure 1-SS Updated Total-System Annual Revenue Requirement
With the Combined Projects (Benefit)/Cost ($million)
$80
$40
$20
$0 
($60)
($80)
($100)
($120)
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2ndSupplemental ---Supplemental Direct
2 The data shown in this figure for the updated economic analysis have the same
3 basic profile as the data from the economic analysis summarized in my supplemental
4 direct testimony.Despite a reduction in PTC benefits associated with changesin federal
5 tax law,the reduced costs from winning bids from the 2017R RFP continue to generate
6 substantial near-term customer benefits and continue to contribute to customer benefits
7 over the long term.The Combined Projects produce net benefits in 23 years out of the
8 30 years that the proposed owned-wind resources selected to the 2017R RFP final
9 shortlist are assumed to operate.
10 As noted in my supplemental direct testimony,the year-on-year reduction in net
11 benefits from 2036 to 2037 is driven by the company's conservative approach to
12 extrapolate benefits from 2037 through 2050 based on modeled results from the 2028-
13 through-2036 time frame.This leads to an abrupt reduction in the benefits in 2037,and
14 a subsequent year-on-year reduction to net benefits,which breaks from the trend
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l observed in the model results over the 2035-to-2036 time frame.This extrapolation
2 methodology is conservative because it results in project benefits not matching the
3 levels observed in the model results for 2036 until 2047.
4 SOLAR SENSITIVITY
5 Q.Did the company update its solar sensitivity analysis?
6 A.Yes.The solar sensitivity analysis was updated to reflect the updated final shortlist from
7 the 2017R RFP and to reflect best-and-final pricing supplied by bidders participating
8 in the 2017S RFP on February 1,2018.
9 Q.Please describe the sensitivity studies that analyzed the impact of the solar bids
10 received in the 2017S RFP on the economics of the Combined Projects.
11 A.Consistent with the methodology summarized in my supplemental direct testimony,the
12 company's solar sensitivity analysis used the SO model and PaR simulations to
13 determine the PVRR(d)based on two model runsone with solar PPA bids and the
14 Combined Projects and one with solar PPA bids but without the Combined Projects.
15 Q.What were the results of the solar sensitivity where solar PPA bids are assumed to
16 be pursued in lieu of the Combined Projects?
17 A.Table 4-SS summarizes PVRR(d)results for the solar sensitivity where solar PPA bids
18 are assumed to be pursued without any investments in the Combined Projects.This
19 sensitivity was developed using SO model and PaR simulations through 2036 for the
20 medium natural gas,medium CO2 and the low natural gas,zero CO2 price-policy
21 scenarios.The results are shown alongside the benchmark study in which the Combined
22 Projects were evaluated without solar PPA bids.
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1 Table 4-SS Updated Solar Sensitivity with Solar PPAs Included
in lieu of the Combined Projects (Benefit)/Cost ($million)
Sensitivity Benchmark Change in
PVRR(d)PVRR(d)PVRR(d)
Medium Gas,Medium CO7
SO Model ($343)($405)$61
PaR Stochastic Mean ($206)($333)$127
PaR Risk Adjusted ($216)($362)$146
Low Gas,Zero CO,
SO Model ($196)($185)($11)
PaR Stochastic Mean ($123)($126)$3
PaR Risk Adjusted ($130)($132)$3
2 In this sensitivity,the SO model selects 1,122 MW of solar PPA bids in the low
3 natural gas,zero CO2 price-policy scenario and 1,419 MW of solar PPA bids in the
4 medium natural gas,medium CO2 price-policy scenario.All of the selected solar PPA
5 bids are for projects located in Utah.
6 In the medium natural gas,medium CO2 price-policy scenario,a portfolio with
7 the Combined Projects delivers greater customer benefits relative to a portfolio that
8 adds solar PPA bids without the Combined Projects.Customer benefits are greater
9 when the resource portfolio includes the Combined Projects without solar PPA bids by
10 $146 million in the medium natural gas,medium CO2 price-policy scenario based on
11 the risk-adjusted PaR results.In the low natural gas,zero CO2 price-policy scenario,
12 the portfolio with the Combined Projects delivers slightly greater customer benefits
13 relative to a portfolio that adds solar PPA bids without the Combined Projects when
14 modeled in PaR,and slightly lower customer benefits when analyzed with the SO
15 model.The decrease in net benefits in the solar PPA portfolio is $3 million based on
16 the risk-adjusted PaR results.
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l When analyzed without the Combined Projects,the solar PPA bids produce net
2 customer benefits that are lower than the benefits expected from the Combined Projects
3 in the medium natural gas,medium CO2 price-policy scenario.While the sensitivity
4 with a portfolio containing solar PPAs without the Combined Projects produces
5 PVRR(d)results that are similar to the PVRR(d)results with only the Combined
6 Projects in the low natural-gas,zero CO2 price-policy scenario,both portfolios deliver
7 customer benefits.This sensitivity does not support an alternative resource
8 procurement strategy to pursue solar PPA bids in lieu of the Combined Projects.This
9 would leave the significant benefits from the Combined Projects,which include
10 building a much-needed transmission line,on the table.
11 Q.What were the results of the solar sensitivity where solar PPA bids are pursued
12 with the Combined Projects?O 13 A.Table 5-SS summarizes PVRR(d)results for the solar sensitivity where solar PPA bids
14 are assumed to be pursued along with the proposed investments in the Combined
15 Projects.This sensitivity was developed using SO model and PaR simulations through
16 2036 for the medium natural gas,medium CO2 and the low natural gas,zero CO2 price-
17 policy scenarios.The results are shown alongside the benchmark study in which the
18 Combined Projects were evaluated without solar PPA bids.
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l Table 5-SS Updated Solar Sensitivity with Solar PPAs Included
With the Combined Projects (Benefit)/Cost ($million)
Sensitivity Benchmark Change in
PVRR(d)PVRR(d)PVRR(d)
Medium Gas,Medium CO,
SO Model ($647)($405)($242)
PaR Stochastic Mean ($455)($333)($122)
PaR Risk Adjusted ($479)($362)($116)
Low Gas,Zero CO,
SO Model ($312)($185)($127)
PaR Stochastic Mean ($l97)($126)($71)
PaR Risk Adjusted ($206)($l32)($74)
2 In this sensitivity,the SO model continues to choose the winning bids included
3 in the updated 2017R RFP final shortlist as part of the least-cost bid portfolio.In
4 addition to these wind resource selections,the SO model selects 1,042 MW of solar
5 PPA bids in the low natural gas,zero CO2 price-policy scenario and 1,419 MW of solar
6 PPA bids in the medium natural gas,medium CO2 price-policy scenario.Again,all of
7 the selected solar PPA bids are for projects located in Utah.
8 When the solar PPAs are assumed to be pursued in addition to the Combined
9 Projects,total net customer benefits increase.This result is consistent with the
10 company's expectation expressed during the technical conference conducted on
11 January 17,2018 that cost-effective solar opportunities would not displace the
12 Combined Projects,but would only potentially add to incremental resource
13 procurement opportunities that might provide net customer benefits.Importantly,this
14 sensitivity produces net benefits that are greater than the net benefits from the
15 Combined Projects without the solar PPAs.This confirms that near-term renewable
16 procurement is not a matter of whether the company should pursue the Combined
17 Projects or the solar PPAs,but whether the company should consider both
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1 opportunities.At this time,it is clear that the Combined Projects provide significant net
2 benefits,and that these benefits are not eliminated if the company were to also pursue
3 solar PPA bids through the 2017S RFP.
4 WIND-REPOWERING SENSITIVITY
5 Q.Has the company updated its sensitivity analysis related to the wind repowering
6 project?
7 A.Yes.The wind repowering sensitivity was updated to reflect the updated final shortlist
8 and to reflect the most recent cost-and performance estimates for the wind repowering
9 project as described in my supplemental direct testimony filed in Case No.
10 PAC-E-17-06.
11 Q.What were the results of the updated wind-repoweringsensitivity?
12 A.Table 6-SS summarizes PVRR(d)results for this wind-repowering sensitivity.ThisO13sensitivitywasdevelopedusingSOmodelandPaRsimulationsthrough2036forthe
14 medium natural-gas,medium CO2 and the low natural-gas,zero CO2 price-policy
15 scenarios.The results are shown alongside the benchmark study in which the Combined
16 Projects were evaluated without wind repowering.
17 Table 6-SS Wind-Repowering
Sensitivity (Benefit)/Cost ($million)
I Sensitivity Benchmark Change in
PVRR(d)|PVRR(d)|PVRR(d)
Medium Gas,Medium CO2
SO Model ($608)($405)($204)
PaR Stochastic Mean ($517)($333)($184)
PaR Risk Adjusted ($543)($362)($181)
Low Gas,Zero CO2
SO Model ($334)($185)($149)
PaR Stochastic Mean ($257)($126)($131)
PaR Risk Adjusted ($271)($132)($138)
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l In the updated wind-repowering sensitivity,customer benefits increase
2 significantly when the wind repowering project is implemented with the Combined
3 Projects in both the medium natural-gas,medium CO2.and the low natural-gas,zero
4 CO2 price-policy scenarios.These results continue to demonstrate that customer
5 benefits not only persist,but also increase,if both the wind-repoweringproject and the
6 Combined Projects are completed .
7 TURBINE-EQUIPMENT SENSITIVITY
8 Q.Did the company perform any other additional sensitivity analysis to support
9 selection of bids to the updated 2017R RFP final shortlist?
10 A.Yes.The company produced an SO model sensitivity to analyze the PVRR(d)impact
11 of
12 .O 13 Q.Why did the company develop this sensitivity?
14 A.Technical discussions and preliminary modeling of in the
15 interconnection-restudy process raised concerns that a synchronous condenser or other
16 electrical compensation equipment might be required at the Aeolus substation if the
17 to address
18 system performance in a low stiffness-factor environment.Considering that
19
20
21 the company produced this sensitivityto estimate the incremental
22 amount of network upgrade costs that would
23 .
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1 Q.What were the results of this turbine-equipmentsensitivity?
2 A.Table 7-SS summarizes PVRR(d)results for the turbine-equipment sensitivity.This
3 sensitivity was developed using the SO model through 2036 for the medium natural-
4 gas,medium CO2 and the low natural-gas,zero CO2 price-policy scenarios.The results
5 are shown alongside the benchmark study in which the Combined Projects were
6 evaluated with the updated final shortlist of bids.
7 Table 7-SS Turbine-Equipment
Sensitivity (Benefit)/Cost ($million)
Sensitivity Benchmark Change in
PVRR(d)PVRR(d)PVRR(d)
Medium Gas,Medium CO2 ($381)($405)$24
Low Gas,Zero CO2 ($143)($185)$42
8 Considering that the SO model uses levelized capital costs,the reduction in
9 PVRR(d)net benefits in this sensitivity would require at least
10 in incremental in-service transmission upgrade costs attributable tg
11
12 .
13 The company does not anticipate that incremental in-service transmission costs
14 would exceed should a synchronous condenser or other electrical
15 compensation equipment be required.Moreover,
16
17 Based on these findings
18 ,PacifiCorp did not
19
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l INDEPENDENT EVALUATORS
2 Q.Has the company compiled summaries of all bids received?
3 A.Yes.The Combined Projects have proceedings simultaneously occurring in Utah,
4 Idaho,and Wyoming.While the Idaho Commission does not have statutes or rules that
5 pertain to requests for proposals,other states do.In order to provide as much
6 information as possible to allow a thorough review in all states,the company is
7 providing Confidential Exhibit No.57,which summarizes the bids that were received
8 and reviewed as part of the 2017R RFP.The Utah IE's monthly reports,which are
9 attached as Highly Confidential Exhibit No.58,also include a summary of all of the
10 bids that were included on the 2017R RFP initial shortlist.The non-conforming bids
ll that were received and rejected are described in Highly Confidential Exhibit No.59.
12 Q.Is the company providingsummaries of its rankings and evaluations of bids?O 13 A.Yes.Highly Confidential Exhibit No.60 provides a summary of the company's
14 rankings and evaluation of bids.In addition,my rebuttal testimony filed December 18,
15 2017,supplemental direct testimony,filed January 16,2018,and my testimony above
16 describes how the company evaluated bids using the SO model and PaR to identify the
17 fmal-shortlist projects.
18 Q.Is the company providing the reports prepared by the Utah IE?
19 A.Yes.Highly Confidential Exhibit No.58 provides copies of all the monthly status
20 reports prepared by the IE.The exhibit also includes the Utah IE's fmal report on the
21 assessment of the Company's benchmark resources (i.e.,TB Flats I and II,Ekola Flats,
22 and McFadden Ridge II),which was prepared by the IE on November 2,2017,and the
23 Utah IE's report on the 2017R RFP final shortlist,which was prepared by the IE on
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1 February 15,2018.
2 Q.What were the Utah IE's conclusions related to the benchmark resources?
3 A.The IE found that the company "developed detailed cost information about the
4 benchmark resources and provided their proposals along with the background
5 information and spreadsheetsdetailing the cost by line item to the IEs for review and
6 assessment of the benchmark resources."
7 The IE concluded that the "benchmark proposals contain all the information
8 required of other bidders and will be evaluated consistent with the methodology used
9 to evaluate all bids submitted."According to the IE,the "level and detailofinformation
10 provided by [the Company]is very thorough and exceeds industry standards for
11 benchmark resources at this stage in the process."(emphasis added).
12 Regarding the cost estimates for the benchmark resources,the IE concluded
13 that,"[o]verall,we feel that the capital costs are reasonable for the benchmark resources
14 but if there is any deviationfrom the average we feel it would be on the low side of the
15 cost spectrum."Similarly,the IE concluded that the O&M costs are reasonable.
16 Overall,the IE concluded that the company's treatment of benchmark resources
17 in the 2017R RFP conformed to the requirements of Utah Admin.Rule R746-420 and
18 that the "review,assessment and scoring of the benchmark resources was conducted in
19 a fair and equitable manner with no outward perception of bias."
20 Q.What were the Utah IE's conclusions related to the 2017R RFP final shortlist?
21 A.As noted above,the IE agreed with the Company's final shortlist and specifically
22 concluded the following:
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l The responseto the 2017R RFP was robust-the capacity bid into the
2 RFP was more than five times the capacity requested,and bidders
3 offered a variety of commercial structures;
4 The Company used a consistent evaluation process and treated all
5 proposals equally;
6 The Company made a compelling case that it reasonably accounted for
7 the interconnection queue position of project bids and eliminated
8 projects with bid positions higher than Q0712.1
9 The Company's modeling demonstrates that pursuit of the Wind
10 Projects should result in significant customer benefits,particularly in
11 the near-term as PTC benefits flow through rates;
12 The final revised evaluation and shortlist is reasonable;
13 Q.Does Highly Confidential Exhibit No.58 include the IE's final report?
14 A.No.The company has not received a copy of the IE's final report.But once the report
15 is completed,the company will ensure that it is promptly filed with the commission.
16 Q.Has the company included any reports filed by the IE appointed by the Public
17 Utility Commission of Oregon (Oregon Commission)?
18 A.Yes.The Oregon Commission appointed Bates White,LLC as its IE.At this time,the
19 Oregon IE has provided an assessment of the final draft RFP and a letter confirming its
20 agreement with changes made to the final 2017R RFP,which are provided as Exhibit
21 No.61.The Oregon IE will file its closing report with the Oregon Commission on
'While the details of the IE's report,particularly the summaries of bid information,is designated highly
confidential,the IE's conclusions are non-confidential.
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1 February 16,2017.The company will file the Oregon IE's closing report with the Idaho
2 Commission once it is available.
3 Q.Is the 2017R RFP publicly available?
4 A.Yes.The 2017R RFP,along with all appendices and exhibits,has been available on the
5 Company's website (http://www.pacificorp.com/sup/rfps/2017-rfp.html)since it was
6 issued.In addition,although it is not the subject of this case,the 2017S RFP and all
7 appendices are also publicly available on the Company's website
8 (http://www.pacificorp.com/sup/rfps/2017S-RFP.html).
9 Q.Does this conclude your second supplemental direct testimony?
10 A.Yes.
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