20170705Link Direct - Redacted.pdf

O
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 )DIRECT TESTIMONY OF
CONVENIENCE AND NECESSITY AND )RICK T.LINK
BINDING RATEMAKING TREATMENT )REDACTED
FOR NEW WIND AND TRANSMISSION )
FACILITIES )
O
ROCKY MOUNTAIN POWER
CASE NO.PAC-E-17-07
June 2017
O
l Q.Please state your name,business address,and position with PacifiCorp.
2 A.My name is Rick T.Link.My business address is 825 NE Multnomah Street,Suite 600,
3 Portland,Oregon 97232.My position is Vice President,Resource and Commercial
4 Strategy.I am testifying on behalf of Rocky Mountain Power,a division of PacifiCorp.
5 Q.Please describe the responsibilities of your current position.
6 A.I am responsible for PacifiCorp's integrated resource plan ("IRP"),structured
7 commercial business and valuation activities,long-term commodity price forecasts,
8 long-term load forecasts,and environmental strategy and policy activities.Most
9 relevant to this docket,I am responsible for the economic analysis used to screen
10 system resource investments and for conducting competitive request for proposal
11 ("RFP")processes consistent with applicable state procurement rules and guidelines.
12 Q.Please describe your professional experience and education.
13 A.I joined PacifiCorp in December 2003 and assumed the responsibilities of my current
14 position in September 2016.Over this time period,I held several analytical and
15 leadership positions responsible for developing long-term commodity price forecasts,
16 pricing structured commercial contract opportunities and developing fmancial models
17 to evaluate resource investment opportunities,negotiating commercial contract terms,
18 and overseeing development of PacifiCorp's resource plans.I was responsible for
19 delivering PacifiCorp's 2013,2015,and 2017 IRPs;have been directly involved in
20 several resource RFP processes;and performed economic analysis supporting a range
21 of resource investment opportunities.Before joining PacifiCorp,I was an energy and
22 environmental economics consultant with ICF Consulting (now ICF International)
23 from 1999 to 2003,where I performed electric-sector financial modeling of
O
REDACTED Link,Di -1
Rocky Mountain Power
l environmental policies and resource investment opportunities for utility clients.
2 I received a Bachelor of Science degree in Environmental Science from the Ohio State
3 Universityin 1996 and a Masters of EnvironmentalManagement from Duke University
4 in 1999.
5 Q.Have you testified in previous regulatory proceedings?
6 A.Yes.I have testified in proceedings before the Wyoming Public Service Commission,
7 the Utah Public Service Commission,the Public Utility Commission of Oregon,and
8 the Washington Utilities and TransportationCommission.
9 PURPOSE AND SUMMARY OF TESTIMONY
10 Q.What is the purpose of your testimony?
11 A.I present and explain the economic analysis that supports PacifiCorp's decision to
12 construct or procure four new Wyoming wind resources with a total capacity of
13 860 megawatts ("MW")(collectively,the "Wind Projects"),and the decision to
14 construct the "Aeolus-to-Bridger/Anticline Line"and construct the 230 kV Network
15 Upgrades (collectively,the "Transmission Projects").'The Transmission Projects
'As more specifically described in the testimony of Mr.Rick A.Vail,the Transmission Projects include:(1)a
new 140-mile,500 kV transmission line segment and associated infrastructure running from the new Aeolus
substation near Medicine Bow,Wyoming,to the new Anticline substation located near the existing Jim Bridger
substation,which includes construction of the new Aeolus and Anticline substations;(2)a new five-mile,345
kV transmission line that will extend from the proposed Anticline substation to the existing Jim Bridger
substation,which includes modifications at the existing Jim Bridger substation to allow termination of the new
345 kV line;(3)installation of a voltage control device at the Latham substation;(4)a new 16-mile,230 kV
transmission line running from the Company's existing Shirley Basin substation to the proposed Aeolus
substation,which requires modifications to the Shirley Basin substation and interconnection facilities in the new
Aeolus substation to accommodate the new line;(5)reconstruction of four miles of an existing 230 kV
transmission line between the proposed Aeolus substation and the Freezeout substation,which requires
modifications to the Freezeout substation and interconnection facilities in the new Aeolus substation to
accommodate the rebuilt line;and (6)reconstruction of 14 miles of an existing 230 kV transmission line
between the Freezeout substation and the Standpipe substation,which requires modifications to the Freezeout
and Standpipe substations to accommodate the rebuilt line.Items 1 through 3 are collectively referred to as theO"Aeolus-to-Bridger Anticline Line,"and items 4 through 6 are collectively referred to as the "230 kV Network
Upgrades."
REDACTED Link,Di -2
Rocky Mountain Power
l enable interconnection of the new wind resources.My testimony demonstrates that
2 PacifiCorp's proposals to construct or acquire approximately 860 MW of new Wind
3 Projects and construct the Transmission Projects (collectively,the "Combined
4 Projects")is in the public interest.My testimony also summarizes PacifiCorp's
5 assessment of new Wyoming wind resources and the Aeolus-to-Bridger/Anticline Line
6 in its 2017 IRP.
7 Q.Please summarize your testimony.
8 A.PacifiCorp's economic analysis supports investments in the Combined Projects.The
9 Wind Projects,which are enabled by the Transmission Projects,will generate federal
10 production tax credits ("PTCs")for ten years;produce zero-fuel-cost energy that will
ll lower net power costs ("NPC");generate renewable-energy credits ("RECs"),which
12 can be sold in the market to create additional revenues that would lower net customer
13 costs;and help decarbonize PacifiCorp's resource portfolio,which will mitigate long-
14 term risk associated with potential future state and federal policies targeting carbon
15 dioxide ("CO2")emiSsions reductions from the electric sector.
16 The Transmission Projects will relieve congestion on the current transmission
17 system in eastern Wyoming,enable new wind resource interconnections,provide
18 critical voltage support to the Wyoming transmission network,improve overall
19 reliability of the transmission system,enhance PacifiCorp's ability to comply with
20 mandated reliability and performance standards,and reduce line losses.Moreover,the
21 proposed transmission-system investments create an opportunity for further increases
22 to the transfer capability across the Aeolus-to-Bridger/Anticline Line with the
23 construction of additional segments of Energy Gateway.
O
REDACTED Link,Di -3
Rocky Mountain Power
l The Combined Projects will produce customer benefits that significantly
2 outweigh costs.The change in revenue requirement due to the Combined Projects was
3 analyzed using two different modeling tools across nine different scenarios,each with
4 varying natural-gas and CO2 price assumptions.For each of these scenarios,the
5 present-value revenue requirement differential ("PVRR(d)")was calculated from
6 system revenue requirement forecasts through 2050 (through the 30-year life of the
7 Wind Projects),reflecting nominal capital revenue requirement from the Combined
8 Projects,and from system revenue requirement forecasts over a 20-year period,where
9 capital revenue requirement is levelized.
10 The Combined Projects show PVRR(d)benefits in seven of the nine scenarios
11 (all scenarios except two using the lowest natural-gas price assumptions)when
12 calculated from system revenue requirement forecasts through 2050.The present-value
13 reduction to the change in system revenue requirement through 2050 is $137 million
14 when assuming medium natural-gas and medium CO2 price assumptions.
15 In seven of the nine scenarios (all scenarios except two using the lowest natural-
16 gas price assumptions),the Combined Projects show PVRR(d)benefits when
17 calculated from system revenue requirement forecasts over a 20-year period.Over this
18 20-year forecast period,the present-value reduction to the change in system revenue
19 requirement due to the Combined Projects ranges between $85 million and $124
20 million when assuming medium natural-gas and medium CO2 price assumptions.
21 The customer benefits from the Combined Projects increase substantiallywith
22 higher natural-gas price assumptions and higher CO2 price assumptions.These benefits
23 conservatively do not assign any value to the RECs that will be generated by the Wind
O
REDACTED Link,Di -4
Rocky Mountain Power
l Projects.For every dollar assigned to the incremental RECs that will be generated by
2 the Wind Projects,present-value benefits would improve for all scenarios by an
3 additional $34 million when calculated from the change in system revenue requirement
4 through 2050.When calculated from the change in system revenue requirement over a
5 20-year period,each dollar assigned to the incremental RECs from the Wind Projects
6 would increase PVRR(d)benefits by $26 million.
7 Sensitivity analysis shows that substantial benefits of the Combined Projects
8 persist when paired with PacifiCorp's plans to upgrade or "repower"certain wind
9 resources,which is the subject of a concurrently filed application.Sensitivity analysis
10 also shows that there is additional upside to customer benefits if the new equipment is
11 depreciated over a longer life.
12 2017 INTEGRATED RESOURCE PLAN
13 Q.Did PacifiCorp analyze new Wyoming wind resources and the Aeolus-to-
14 Bridger/Anticline Line in its 2017 IRP?
15 A.Yes.The 2017 IRP preferred portfolio,representing PacifiCorp's least-cost,least-risk
16 plan to reliably meet customer demand over a 20-year planning period,includes
17 1,100 MW of new wind resources located in Wyoming.This wind capacity is enabled
18 by the Aeolus-to-Bridger/Anticline Line,which is also included in the 2017 IRP
19 preferred portfolio.The new wind and Aeolus-to-Bridger/Anticline Line are assumed
20 to be placed in service by the end of 2020 so that the new wind resources can qualify
21 for the full value of PTCs.
O
REDACTED Link,Di -5
Rocky Mountain Power
l Q.What led PacifiCorp to include 1,100 MW of new Wyoming wind resources and
2 the Aeolus-to-BridgerAnticline Line in its 2017 IRP preferred portfolio?
3 A.All of the resource portfolios produced during the initial stages of the portfolio-
4 development phase of the 2017 IRP contained new Wyoming wind resources in 2021,
5 which for modeling purposes was used as a proxy on-line date for PTC-eligible wind
6 achieving commercial operation by the end of 2020.At the same time,the load-and-
7 resource balance developed for the 2017 IRP shows that PacifiCorp would not require
8 incremental system capacity to meet its 13-percent planning-reservemargin until 2028,
9 accounting for assumed coal unit retirements,incremental energy ef5ciency savings,
10 and availablewholesale-powermarket purchase opportunities.These results indicated
ll that PTC-eligible wind resources located in wind-rich areas like Wyoming provide
12 customer benefits.
13 During the initial stages of portfolio development for the 2017 IRP,the amount
14 of Wyoming wind capacity that routinelyappeared in 2021 was limited by transmission
15 congestion on PacifiCorp's existing 230 kV transmission system.This congestion
16 affects energy output from resources in eastern Wyoming where there is substantial
17 potential to develop high-quality,low-cost wind resources.Wyoming resource
18 selections at or near the limitation on Wyoming wind capacity caused by transmission
19 constraints indicated clear potential for incremental customer benefits if incremental
20 transmission is added to accommodate more PTC-eligible wind resources located in
21 Wyoming.
22 To assess these potential incremental benefits,PacifiCorp reviewed
23 components of its Energy Gateway transmission project to identify specific sub-
O
REDACTED Link,Di -6
Rocky Mountain Power
l segments that could access additional new Wyoming wind resources.In performing
2 this review,PacifiCorp looked at the transmission interconnection queue and
3 determined that sub-segment D2 (the Aeolus-to-Bridger/Anticline Line)of the Energy
4 Gateway transmission project could access a sizable volume of new wind projects
5 being developed in the Aeolus area.PacifiCorp then developed an initial,high-level
6 cost estimate for the Aeolus-to-Bridger/Anticline Line that was used for an initial
7 Aeolus-to-Bridger/Anticline sensitivity assuming 650 MW of incremental transfer
8 capability and 900 MW of new Wyoming wind resources.
9 Q.Why did PacifiCorp assume new wind resource capacity in excess of the assumed
10 incremental transfer capability of the Aeolus-to-Bridger/Anticline Line in this
11 initial sensitivity?
O 12 A.The Aeolus-to-Bridger/Anticline Line can enable new resource interconnections in
13 excess of the transfer capability of the line.PacifiCorp's preliminary sensitivity in the
14 2017 IRP assumed the Aeolus-to-Bridger/Anticline Line would support at least
15 900 MW of new resource interconnections.The assumed level of new wind resources
16 is higher than the assumed incremental transfer capability of the transmission line
17 because wind resources do not generate at their full capability in all hours of the year.
18 At times when wind resources in southeastern Wyoming are operatingnear full output,
19 other resources in the area can be re-dispatched to accommodate PTC-producing wind
20 generation.
21 Q.What were the results of this initial Aeolus-to-Bridger/Anticlinesensitivity?
22 A.The initial sensitivity indicated that there could be economic benefits from aligning
23 development of the Aeolus-to-Bridger/Anticline Line with new,PTC-eligible
O
REDACTED Link,Di -7
Rocky Mountain Power
l Wyoming wind resources.Based on the promising results from this initial sensitivity,
2 PacifiCorp reviewed its initial,high-level assumptions to determine how refined inputs
3 would affect potential benefits from the incremental new Wyoming wind resources and
4 the Aeolus-to-Bridger/Anticline Line.
5 PacifiCorp completed power flow and dynamic-stability studies to refine its
6 Aeolus-to-Bridger/Anticline Line assumptions.These studies supported increasing the
7 assumed incremental transfer capability of the new transmission line from 650 MW to
8 750 MW and suggested that it could enable up to 1,270 MW of new resource
9 interconnections.PacifiCorp also refined its initial,high-level cost assumptions,
10 reducing the estimated capital cost of the project by over $100 million.
11 In addition,PacifiCorp reviewed its new wind resource cost-and-performance
12 assumptions,initially developed to represent proxy Wyoming wind resources,to focus
13 on specific projects that could be developed in the Aeolus area.Based on this review,
14 PacifiCorp determined that the estimated capital cost for new wind resources could be
15 lowered by 10.7 percent from its initial proxy cost assumptions and that its wind
16 capacity factor assumptions should be reduced from 43 percent to 41.2 percent.
17 In addition to refining its transmission and new wind resource assumptions,
18 PacifiCorp reviewed whether additionalbenefits from the wind enabled by the Aeolus-
19 to-Bridger/Anticline Line could be quantified.PacifiCorp identified and quantified
20 three additional value streams associated with its participation in the energy imbalance
21 market ("EIM"),improved transmission reliability,and reduced transmission line
22 losses.
O
REDACTED Link,Di -8
Rocky Mountain Power
l The results from this additional review and analysis were applied in the final
2 2017 IRP resource-portfolioscreening process,where PacifiCorp conducted additional
3 studies that considered analysis performed in earlier resource-portfolio screening
4 stages.
5 Q.What type of analysis did PacifiCorp consider from earlier resource-portfolio
6 screening stages?
7 A.In earlier stages of its resource-portfolio screening process,PacifiCorp developed a
8 wind repowering sensitivity,where certain existing wind resources qualify for an
9 additional ten years of PTCs after they are upgraded with modern equipment.The wind
10 repowering project,the subject of a concurrently filed application,showed significant
11 net customer benefits across a range of assumptions related to forward market prices
12 and federal CO2 policy based on the Clean Power Plan ("CPP").Considering the
13 significant customer benefits associated with the wind repowering project,PacifiCorp
14 combined its refined assumptions for incremental new Wyoming wind and the Aeolus-
15 to-Bridger/Anticline Line in a study that included wind repowering.
16 Q.What were the results of PacifiCorp's final 2017 IRP resource-portfolioscreening
17 process that incorporated refined and expanded input assumptions for
18 incremental new Wyoming wind resources and the Aeolus-to-Bridger/Anticline
19 Line?
20 A.Studies developed for the final 2017 IRP resource-portfolioscreening process showed
21 significant net customer benefits relative to other resource-portfolio alternatives.Based
22 on these results,the Aeolus-to-Bridger/Anticline Line and the 1,100 MW of new
O
REDACTED Link,Di -9
Rocky Mountain Power
l Wyoming wind resources,both assumed to be placed in service by the end of 2020,
2 were included in the 2017 IRP preferred portfolio.
3 Q.What are the benefits associated with the new Wyoming wind assumed to come
4 online by the end of 2020 that was included in the 2017 IRP preferred portfolio?
5 A.This new wind,which was included in the 2017 IRP preferred portfolio,will deliver
6 several different benefits for customers.First,these new wind resources will generate
7 PTCs for ten years after being placed in service.The current value of federal PTCs,
8 which is adjusted annually for inflation by the Internal Revenue Service,is $24 per
9 megawatt-hour ("MWh").At a federal and state effective tax rate of 37.95 percent,the
10 current PTC equates to a $38.68 per MWh reduction in revenue requirement that can
11 be passed through to customers.Second,these zero-fuel-cost assets will provide
12 incremental NPC benefits for customers.Third,the new wind facilities will generate
13 RECs,which can be sold in the market to create additional revenues that would lower
14 net customer costs.Fourth,these zero-emissions assets will help to decarbonize
15 PacifiCorp's resource portfolio and mitigate long-term risk associated with potential
16 future state and federal policies targeting CO2 emissions reductions from the electric
17 sector.
18 Q.What are the benefits associated with the Aeolus-to-Bridger/Anticline Line
19 included in the 2017 IRP preferred portfolio?
20 A.As is the case with the new wind resources,the Aeolus-to-Bridger/Anticline Line will
21 also deliver several benefits for customers.The new line will relieve congestion on the
22 current transmission system in eastern Wyoming and enable the additional wind
23 resource interconnections.As discussed by Mr.Rick A.Vail,the Aeolus-to-
O
REDACTED Link,Di -10
Rocky Mountain Power
l Bridger/Anticline Line will also provide critical voltage support to the Wyoming
2 transmission network,improve overall reliability of the transmission system,enhance
3 PacifiCorp's ability to comply with mandated reliability and performance standards,
4 reduce line losses,and creates an opportunity for further increases to the transfer
5 capability across the Aeolus-to-Bridger/Anticline Line with the construction of
6 additional segments of Energy Gateway.
7 Q.Did PacifiCorp include an action item for new Wyomingwind resources in its 2017
8 IRP action plan?
9 A.Yes.The 2017 IRP action plan,which lists the specific steps PacifiCorp will take over
10 the next two to four years to deliver resources in the preferred portfolio,includes the
11 followingaction item associated with the new Wyoming wind resources:
O 12 PacifiCorp will issue a wind resource request for proposals (RFP)for at
13 least 1,100 MW of Wyoming wind resources that will qualify for federal
14 wind production tax credits and achieve commercial operation by
15 December 31,2020.
16 April 2017,notify the Utah Public Service Commission of intent
17 to issue the Wyoming wind resource RFP.
18 May-June,2017,file a draft Wyoming wind RFP with the Utah
19 Public Service Commission and the Washington Utilities and
20 Transportation Commission.
21 May-June,2017,file to open a Wyoming wind RFP docket with
22 the Public Utility Commission of Oregon and initiate the
23 Independent Evaluator RFP.
24 June-July,2017,file a draft Wyoming wind RFP with the Public
25 Utility Commission of Oregon and file a Public Convenience and
26 Necessity (CPCN)application with the Public Service
27 Commission of Wyoming.
28 By August 2017,obtain approval of the Wyoming wind resource
29 RFP from the Public Utility Commission of Oregon,the Utah
30 Public Service Commission and the Washington Utilities and
31 Transportation Commission.
32 By August 2017,issue the Wyoming wind RFP to the market.
33 By October 2017,Wyoming wind RFP bids are due.
34 November-December,2017,complete initial shortlist bid
35 evaluation.
REDACTED Link,Di -11
Rocky Mountain Power
l By January 2018,complete final shortlist bid evaluation,seek
2 acknowledgment of the final shortlist from the Public Utility
3 Commission of Oregon,and seek approval of winning bids from
4 the Utah Public Service Commission.
5 By March 2018,receive CPCN approval from the Wyoming
6 Public Service Commission.
7 Complete construction of new wind projects by December 31,
8 2020.2
9 Q.Please describe the resource procurement requirements in PacifiCorp's Oregon
10 and Utah jurisdictions applicable to the new Wyomingwind resource action item
11 included in the 2017 IRP action plan.
12 A.The Public Utility Commission of Oregon established competitive bidding
13 requirements for certain resource acquisitions applicable to Oregon's investor-owned
14 utilities (the Competitive Bidding Guidelines).3 Because of the multi-state regulatory
15 approach for cost recovery of PacifiCorp's generation assets and NPC,the new
16 Wyoming wind resources will be subject to these Competitive Bidding Guidelinesas it
17 relates to cost recovery for Oregon's allocated share of costs.The new Wyoming wind
18 resources described in the 2017 IRP action plan could exceed the 100 MW threshold
19 size for any given project as established by the Competitive Bidding Guidelines.
20 Therefore,procurement of these Wyoming wind resources is governed by these
21 guidelines.
22 In addition,Utah's Energy Resource Procurement Act requires a competitive
23 solicitation process before the acquisition of renewable resources greater than
24 300 MW.4 While it is not certain whether a single wind resource acquired through a
25 competitive bidding process will exceed 300 MW,PacifiCorp is proceeding with filings
2 PacifiCorp 2017 Integrated Resource Plan,Volume I at 16-17 (Apr.4,2017).O 3 The Competitive Bidding Guidelines were established by OPUC Order No.06-446 in Docket UM 1182.
4 See Utah Code Ann.§54-17-201 et.seq.
REDACTED Link,Di -12
Rocky Mountain Power
l under the Utah Energy Resource Procurement Act because the total new wind resource
2 capacity assumed to come online by the end of 2020 that is in the 2017 IRP preferred
3 portfolio exceeds the 300 MW threshold established by Utah's statute.
4 Q.Please summarize PacifiCorp's progress with the Wyomingwind resource
5 procurementaction item outlined in the 2017 IRP action plan.
6 A.PacifiCorp notified the Utah Public Service Commission ("UPSC")ofits intentto issue
7 the Wyoming wind resource RFP (the "2017R RFP")on April 17,2017.This
8 notification initiated the process for the UPSC to hire an independent evaluator("IE")
9 to oversee the 2017R RFP process.PacifiCorp subsequently filed its draft 2017R RFP
10 with the UPSC on June 16,2017.The draft 2017R RFP is seeking bids for Wyoming
11 wind resources that can be placed in service by the end of 2020 and that are capable of
12 interconnecting to,and/or delivering energy and capacity across,PacifiCorp's
13 transmission system in Wyoming.PacifiCorp is encouraging bidders to offer proposals
14 under a range of different structures,including power purchase agreements ("PPAs")
15 and build-transfer agreements.
16 PacifiCorp also filed an application with the Public Utility Commission of
17 Oregon requesting that a docket be opened to approve the 2017R RFP and to appoint
18 its own IE to oversee the 2017R RFP process.
19 Since the 2017 IRP was filed,PacifiCorp determined that the 2017R RFP does
20 not need to be filed and approved by the Washington Utilities and Transportation
21 Commission.
22 In his testimony,Mr.Chad A.Teply addresses the construction schedule for the
23 new Wyoming wind resources.
O
REDACTED Link,Di -13
Rocky Mountain Power
l Q.What is the timing of the 2017R RFP and how does it compare with
2 PacifiCorp's proposed Wyoming CPCN schedule?
3 A.PacifiCorp anticipates releasing the 2017R RFP to the market by the end of August
4 2017 and receiving bids in the first half of October 2017.PacifiCorp plans to have its
5 analysis of bids completed in early January 2018.After finalizing its bid analysis,
6 PacifiCorp will make a supplemental filing in this docket,so that parties and the
7 Commission can review and respond to project-specific information and the associated
8 economic analysis confirming the net customer benefits from the Combined Projects.
9 Maintaining implementation schedules for the Wind Projects,the Transmission
10 Projects,and the 2017R RFP will require a conditional Wyoming CPCN,subject to
11 final acquisition of all rights-of-ways,for the Transmission Projects under the schedule
12 included in the application.
13 Q.Why will PacifiCorp's benchmark resources play an importantrole in the
14 2017R RFP?
15 A.PacifiCorp's benchmark resources will provide an alternative contracting-and-
16 implementation cost basis that reflects competitive market-equipment-and-
17 construction costs while promoting participation from market bids offering other
18 project-delivery structures.PacifiCorp anticipates receiving bids in response to the
19 2017R RFP under a range of structures.Development and submittal of benchmark
20 resources expand competitive-market offerings under a commercial structure that
21 would otherwise not be available.
O
REDACTED Link,Di -14
Rocky Mountain Power
1 Q.Why is PacifiCorp not waitinguntil completion of the 2017R RFP to file its
2 applications with states for approval of the Wind Projects?
3 A.The Combined Projects under review in this Application are unique.The Wind Projects
4 and Transmission Projects are time-sensitive and codependent.These unique attributes
5 make it impossible to complete the 2017R RFP before initiating review of the
6 Transmission Projects without jeopardizing the in-service dates that are critical to
7 delivering the customer benefits summarized later in my testimony.As described by
8 Mr.Vail,the critical-path schedule for the Transmission Projects is the CPCN
9 procedural schedule.If PacifiCorp were to wait for the 2017R RFP to finish in the first
10 quarter of 2018 to begin lengthy resource review processes,it would not be possible to
11 place the Transmission Projects in service by the end of 2020,which would eliminate
12 the net customer benefits of this time-sensitive opportunity.
13 Nonetheless,PacifiCorp will fully and appropriately demonstrate the net
14 customer benefits of the Combined Projects using market-based information from
15 competitive procurement processes.To support this objective,PacifiCorp has initiated
16 this process with proxy benchmark resource information that can ultimately be
17 validated using project-specific information and associated economic analysis from the
18 2017R RFP.
19 Q.Did PacifiCorp include an action item for the Aeolus-to-Bridger/AnticlineLine in
20 its 2017 IRP action plan?
21 A.Yes.The 2017 IRP action plan includes the following action item associated with the
22 Aeolus-to-Bridger/Anticline Line:
23 By December 31,2020,PacifiCorp will build the 140-mile,500 kV
24 transmission line running from the Aeolus substation near Medicine Bow,
REDACTED Link,Di -15
Rocky Mountain Power
O l Wyoming,to the Jim Bridger power plant (a sub-segment of the Energy
2 Gateway West transmission project).This includes pursuing regulatory
3 review and approval as necessary.
4 June-July2017,file a CPCN applicationwith the Wyoming Public
5 Service Commission.
6 By March 2018,receive conditional CPCN approval from the
7 Wyoming Public Service Commission pending acquisition of
8 rights of way.
9 By December 2018,obtain Wyoming Industrial Siting permit and
10 issue EPC limited notice to proceed.
11 Complete construction of the transmission line by December
12 31,2020.6
13 Q.Please summarize PacifiCorp's progress with the Aeolus-to-Bridger/Anticline
14 Line action item in the 2017 IRP action plan.
15 A.This application is being filed consistent with the 2017 IRP action plan to pursue
16 regulatory review and approval.Mr.Vail addresses the construction schedule for the
17 Aeolus-to-Bridger/Anticline Line and the 230 kV Network Upgrades identified in this
18 Application.
19 SYSTEM MODELING METHODOLOGY
20 Q.Please summarize the methodology PacifiCorp used in its system analysis of the
21 Combined Projects.
22 A.PacifiCorp relied upon the same modeling tools used to develop and analyze resource
23 portfolios in its 2017 IRP to refine and update its analysis of the Combined Projects.
24 These modeling tools calculate system PVRR by identifying least-cost resource
25 portfolios and dispatching system resources over a 20-year forecast period (2017-
26 2036).Net customer benefits are calculated as the PVRR(d)between two simulations
27 of PacifiCorp's system.One simulation includes the Combined Projects,and the other
28 simulation excludes the Combined Projects.Customers are expected to realize benefits
PacifiCorp 2017 Integrated Resource Plan,Volume I at 17 (Apr.4,2017).
REDACTED Link,Di -16
Rocky Mountain Power
l when the system PVRR with the Combined Projects is lower than the system PVRR
2 without the Combined Projects.Conversely,customers would experience increased
3 costs if the system PVRR with the Combined Projects were higher than the system
4 PVRR without the Combined Projects.
5 Q.What modeling tools did PacifiCorp use to perform its system analysis of the
6 Combined Projects?
7 A.PacifiCorp used the System Optimizer ("SO")model and the Planningand Risk model
8 ("PaR")to develop resource portfolios and to forecast dispatch of system resources in
9 simulations with and without the Combined Projects.
10 Q.Please describe the SO model and PaR.
11 A.The SO model is used to develop resource portfolios with sufficient capacity to achieve
O 12 a target planning-reserve margin.The SO model selects a portfolio of resources from a
13 broad range of resource alternatives by minimizing the system PVRR.In selecting the
14 least-cost resource portfolio for a given set of input assumptions,the SO model
15 performs time-of-day,least-cost dispatch for existing resources and prospective
16 resource alternatives,while considering the cost-and-performance characteristics of
17 existing contracts and prospective demand-side-management ("DSM")resources-all
18 within or connected to PacifiCorp's system.The system PVRR from the SO model
19 reflects the cost of existing contracts,wholesale-market purchases and sales,the cost
20 of new and existing generating resources (fuel,fixed and variable operations and
21 maintenance,and emissions,as applicable),the cost of new DSM resources,and
22 levelized revenue requirement of capital additions for existing coal resources and
23 potential new generating resources.
O
REDACTED Link,Di -17
Rocky Mountain Power
l PaR is used to develop a chronological unit commitment and dispatch forecast
2 of the resource portfolio generated by the SO model,accounting for operating reserves
3 and the volatilityand uncertainty in key system variables.PaR captures volatilityand
4 uncertainty in its unit commitment and dispatch forecast by using Monte Carlo
5 sampling of stochastic variables,which include load,wholesale electricity and natural-
6 gas prices,hydro generation,and thermal unit outages.PaR uses the same common
7 input assumptions that are used in the SO model,with resource-portfolio data provided
8 by the SO model results.The PVRR from PaR reflects a distribution of system variable
9 costs,including variable costs associated with existing contracts,wholesale-market
10 purchases and sales,fuel costs,variable operations and maintenance costs,emissions
ll costs,as applicable,and costs associated with energy or reserve deficiencies.Fixed
12 costs that do not change with system dispatch,including the cost of DSM resources,O 13 fixed operations and maintenance costs,and the levelized revenue requirement of
14 capital additions for existing coal resources and potential new generating resources,are
15 based on the fixed costs from the SO model,which are combined with the distribution
16 of PaR variable costs to establish a distribution of system PVRR for each simulation.
17 Q.How has PacifiCorp historically used the SO model and PaR?
18 A.PacifiCorp uses the SO model and PaR to produce and evaluate resource portfolios in
19 its IRP.PacifiCorp also uses these models to analyze resource-acquisition
20 opportunities,resource retirements,resource capital investments,and system
21 transmission projects.The models were used to support the successful acquisition of
22 the Chehalis combined-cycle plant,to support selection of the Lake Side 2 combined-
23 cycle resource through a RFP process,and to evaluate installation of emissions control
O
REDACTED Link,Di -18
Rocky Mountain Power
l equipment.These models will also be used to evaluate bids in the soon-to-be-issued
2 2017R RFP.
3 Q.Are the SO model and PaR the appropriate tools for analyzingthe net customer
4 benefits of the Combined Projects?
5 A.Yes.The SO model and PaR are the appropriate modeling tools when evaluating
6 significant capital investment that influence PacifiCorp's resource mix and affect least-
7 cost dispatch of system resources.The SO model simultaneously and endogenously
8 evaluates capacity and energy trade-offs associated with resource capital projects and
9 is needed to understand how the type,timing,and location of future resources might be
10 affected by the Combined Projects.PaR provides additional granularity on how the
11 Combined Projects are projected to affect system operations,recognizing that key
12 system conditions are volatile and uncertain.Together,the SO model and PaR are bestO13suitedtoperformanet-benefit analysis for the Combined Projects that is consistent
14 with long-standing least-cost,least-risk planning principles applied in PacifiCorp's
15 IRP.
16 Q.How did PacifiCorp use PaR to assess stochastic system-cost risk associated with
17 the Combined Projects?
18 A.Just as it evaluates resource portfolio alternatives in the IRP,PacifiCorp uses the
19 stochastic-mean PVRR and risk-adjusted PVRR,calculated from PaR study results,to
20 assess the stochastic system cost risk of the Combined Projects.With Monte Carlo
21 sampling of stochastic variables,PaR produces a distribution of system variable costs.
22 The stochastic-mean PVRR is the average of net variable operating costs from the
23 distribution of system variable costs,combined with system fixed costs from the SO
O
REDACTED Link,Di -19
Rocky Mountain Power
l model.PacifiCorp uses a risk-adjusted PVRR to evaluate stochastic system cost risk.
2 The risk-adjusted PVRR incorporates the expected value of low-probability,high-cost
3 outcomes.The risk-adjusted PVRR is calculated by adding five percent of system
4 variable costs,from the 956 percentile of the distribution of system variable costs,to
5 the stochastic-mean PVRR.
6 When applied to the analysis of the Combined Projects,the stochastic-mean
7 PVRR represents the expected level of system costs from cases with and without the
8 Wind Projects and the Transmission Projects.The risk-adjusted PVRR is used to assess
9 whether the Combined Projects cause a disproportionate increase to system variable
10 costs under low-probability,high-cost system conditions.
11 Q.Did PacifiCorp analyze how other assumptions affect its economic analysis of the
12 Combined Projects?O 13 A.Yes.In addition to assessing stochastic system cost risk,PacifiCorp analyzed the
14 Combined Projects under a range of assumptions regarding wholesale market prices
15 and CO2 policy ("price-policy")assumptions.These assumptions drive NPC-related
16 benefits,and so it is important to understand how the net-benefit analysis is affected
17 under a range of potential outcomes.PacifiCorp developed low,medium,and high
18 scenarios for the market price of electricity and natural gas and zero,medium,and high
19 CO2price scenarios.Each pair of model simulations-with and without the Combined
20 Projects,in both the SO model and PaR-was analyzed under each combination of
21 these price-policy assumptions.I summarize the assumptions for each price-policy
22 scenario later in my testimony.
O
REDACTED Link,Di -20
Rocky Mountain Power
1 PacifiCorp also completed two sensitivity studies to assess how certain factors
2 affect the net benefits of the Combined Projects.The first sensitivity quantifieshow the
3 net benefits of the Combined Projects are affected by the depreciable life assumed for
4 the new Wind Projects.PacifiCorp's base analysis assumes a 30-year depreciable life
5 when calculating revenue requirement associated with the Wind Projects.Considering
6 that wind facilities with modern equipment might continue operating over a longer
7 period,this sensitivity quantifies the economic impact if the depreciable life of the
8 Wind Projects were reset at 40 years.
9 The second sensitivity quantifieshow the net benefits of the Combined Projects
10 are affected when paired with the wind repoweringproject,the subject of a concurrent
11 application.Consistent with PacifiCorp's wind repowering application,this sensitivity
12 assumes approximately 999 MW of existing wind resource capacity is upgraded withO13modernequipmentinthe2019-to-2020time frame.
14 Q.How much new Wyoming wind capacity did PacifiCorp analyze in its economic
15 analysis of the Combined Projects for this Application?
16 A.PacifiCorp assumedapproximately 1,180 MW of new Wyoming wind resources for all
17 SO model and PaR simulations that include the Combined Projects.As described by
18 Mr.Teply,this includes approximately 860 MW from the Wind Projects,which can
19 achieve commercial operation by year-end 2020.The remaining 320-MW balance of
20 new wind resource capacity is associated with certain qualifyingfacility projects (the
21 "QF Projects")that are located in the Aeolus area,have executed PPAs with PacifiCorp,
22 and have preferential positions in the transmission interconnection queue.The QF
23 Projects are reasonably expected to interconnect with PacifiCorp's transmission system
O
REDACTED Link,Di -21
Rocky Mountain Power
l after the Aeolus-to-Bridger/Anticline Line is placed in service and are assumed to
2 achieve commercial operation at the end of 2021,consistent with the terms in their
3 PPAs.Because the QF Projects are not expected to be able to interconnect with
4 PacifiCorp's transmission system without the Aeolus-to-Bridger/Anticline Line,they
5 are only included in the SO model and PaR simulations that include the Combined
6 Projects.
7 Q.Why is the total capacity of the new Wyoming wind resources included in
8 PacifiCorp's economic analysis of the Combined Projects different from the
9 capacity included in the 2017 IRP preferred portfolio?
10 A.As discussed in the testimony of Mr.Teply,PacifiCorp is seeking approvals for the
11 specific wind projects that it will offer as benchmark resources in the 2017R RFP.This
12 includes three projects (Ekola Flats,TB Flats I,and TB Flats II)being developed by a
13 third party totaling approximately 750 MW and a fourth,l10-MW project (McFadden
14 Ridge II),which PacifiCorp is developing on a site it controls.The capacity of the
15 specific Wind Projects that will be offered as benchmark resources in the 2017R RFP
16 (approximately 860 MW),when combined with the total capacity of the QF Projects
17 (320 MW),totals 1,180 MW.This level of procurement is consistent with PacifiCorp's
18 2017 IRP action item to procure at least 1,100 MW of Wyoming wind resources.
19 PacifiCorp will evaluate the level of Wyoming wind resource procurement that will
20 maximize customer benefits,up to approximately 1,270 MW of new resource
21 interconnections enabled by the Aeolus-to-Bridger/Anticline Line,based on specific
22 bids submitted in response to the 2017R RFP.
O
REDACTED Link,Di -22
Rocky Mountain Power
l Q.What key assumptions did PacifiCorp update since analyzingthe new Wyoming
2 wind resources and the Aeolus-to-Bridger/AnticlineLine in its 2017 IRP?
3 A.Beyond the price-policy assumptions used to analyze a range of NPC-related benefits,
4 PacifiCorp's economic analysis reflects updated assumptions for up-front capital costs,
5 run-rate operating costs,and energy output specific to the Wind Projects and QF
6 Projects described earlier in my testimony.PacifiCorp's analysis assumes an up-front
7 capital investment for the Wind Projects totaling approximately and are
8 assumed to operate at a capacity-weighted-average-annual capacity factor of
9 .The PPA price paid to the QF Projects add to total-system
10 NPC beginning 2022,rising to by the end of their contract terms in 2041.
11 The QF Projects are assumedto operate at an aggregate capacity factor of 40.7 percent.
12 The cost and performance assumptions for the Wind Projects and the QF Projects
13 studied for this application are summarized in Confidential Exhibit No.22.
14 The up-front capital investment for the Aeolus-to-Bridger/Anticline Line is
15 M,consistent with the capital cost assumed in PacifiCorp's 2017 IRP.The
16 assumed up-front capital investment for the 230 kV Network Upgrades,reflecting costs
17 to interconnect the Wind Projects,total .The cost and performance
18 assumptions for the Transmission Projects studied for this application are also
19 summarized in Confidential Exhibit No.22.
20 Q.Does PacifiCorp assume that all of the up-front capital costs of the Transmission
21 Projects will be paid by its retail customers?
22 A.No.While the up-front capital cost of the Transmission Projects will contribute to
23 retail-customer rate base,the revenue requirement for these investments will be
O
REDACTED Link,Di -23
Rocky Mountain Power
l partially offset by incremental revenue from other transmission customers.The up-
2 front transmission costs will flow into PacifiCorp's formula transmission rate under its
3 Open Access Transmission Tariff ("OATT")and generate revenue credits that offset
4 costs for retail customers.
5 PacifiCorp's merchant function,which uses PacifiCorp's transmission system
6 to serve retail-customer load and to manage retail-customer NPC through off-system
7 market sales and purchases,is the largest user of PacifiCorp's transmission system.
8 However,other transmission customers pay OATT-based transmission rates that
9 generate revenue credits and offset the cost of PacifiCorp's transmission revenue
10 requirement.As discussed in Mr.Vail's testimony,the Transmission Projects are
11 considered network transmission assets under PacifiCorp's OATT and therefore will be
12 given rolled-in treatment under PacifiCorp's transmission formula rate.Over recent
13 history,these revenue credits have accounted for approximately 12 percent of
14 PacifiCorp's transmission revenue requirement.Based on this recent history,
15 PacifiCorp's analysis assumes its retail customers pay 88 percent of the revenue
16 requirement from the up-front capital cost for the Transmission Projects after
17 accounting for an assumed 12 percent revenue credit from other transmission
18 customers.
19 Q.How did PacifiCorp model de-rates to its Wyoming 230 kV transmission system
20 when evaluatingthe Combined Projects?
21 A.In its final 2017 IRP resource-portfolio screening process,PacifiCorp identified and
22 quantified reliability benefits associated with the Aeolus-to-Bridger/Anticline Line.
23 This new transmission project will eliminate de-rates caused by outages on 230 kV
O
REDACTED Link,Di -24
Rocky Mountain Power
l transmission-system elements.Historical outages on this part of PacifiCorp's
2 transmission system indicate an average de-rate of 146 MW over approximately
3 88 outage days per year,which equates to approximately one 146-MW,twenty-four
4 hour outage every four days.Without knowing when these events might occur,de-rates
5 on the existing 230 kV transmission system were captured in the SO model and PaR as
6 a 36.5 MW reduction in the transfer capability from eastern Wyoming to the Aeolus
7 area.In simulations that include the Combined Projects,this de-rate assumption was
8 eliminated when the new transmission assets are placed in service at the end of October
9 2020.
10 Q.How did PacifiCorp model line-loss benefits associated with the Transmission
11 Projects when performing its economic analysis of the Combined Projects?
12 A.Line-loss benefits are only applicable in those simulations where the Transmission
13 Projects are built and therefore were only considered in the simulations that include the
14 Combined Projects.When the Aeolus-to-Bridger/Anticline Line is added in parallel to
15 the existing transmission lines,resistance is reduced,which lowers line losses.With
16 reduced line losses,an incremental 11.6 average MW ("aMW")of energy,which
17 equates to approximately 102 gigawatt hours ("GWh"),will be able to flow out of
18 eastern Wyoming each year.The line-loss benefit was reflected in the SO model and
19 PaR by reducing northeast Wyoming load by approximately 11.6 aMW each year.
20 Q.Did PacifiCorp analyze potential EIM benefits in its economic analysis of the
21 Combined Projects?
22 A.Yes.In its final 2017 IRP resource-portfolio screening process,PacifiCorp described
23 how the EIM can provide potential benefits when incremental energy is added to
O
REDACTED Link,Di -25
Rocky Mountain Power
l transmission-constrained areas of Wyoming.Unscheduled or unused transmission from
2 participating EIM entities enables more efficient power flows within the hour.With
3 increasing participation in the EIM,there will be increasing opportunities to move
4 incremental energy from Wyoming to offset higher-pricedgeneration in the PacifiCorp
5 system or other EIM participants'systems.The more efficient use of transmission that
6 is expected with growing participation in the EIM was captured in the economic
7 analysis of the Combined Projects by increasing the transfer capability between the east
8 and west sides of PacifiCorp's system by 300 MW (from the Jim Bridger plant to south-
9 central Oregon).The ability to more efficiently use intra-hour transmission from a
10 growing list of EIM participants is not driven by the Combined Projects;however,this
11 increased connectivity provides the opportunity to move low-cost incremental energy
12 out of transmission-constrained areas of Wyoming.O 13 ANNUAL REVENUE REQUIREMENTMODELING METHODOLOGY
14 Q.In addition to the system modeling used to calculate present-value net benefits
15 over a 20-year planning period,has PacifiCorp forecasted the change in nominal
16 revenue requirementdue to the Combined Projects?
17 A.Yes.The system PVRR from the SO model and PaR was calculated from an annual
18 stream of forecasted revenue requirement over a 20-year time frame,consistent with
19 the planning period in the IRP.The annual stream of forecasted revenue requirement
20 captures nominal revenue requirement for non-capital items (i.e.,NPC,fixed
21 operations and maintenance,etc.)and levelized revenue requirement for capital
22 expenditures.To estimate the annual revenue-requirement impacts of the Combined
O
REDACTED Link,Di -26
Rocky Mountain Power
l Projects,capital costs for the Wind Projects and the Transmission Projects need to be
2 considered in nominal terms (i.e.,not levelized).
3 Q.Why is the capital revenue requirement used in the calculation of the system
4 PVRR from the SO model and PaR levelized?
5 A.Levelization of capital revenue requirement is necessary in these models to avoid
6 potential distortions in the economic analysis of capital-intensive assets that have
7 different lives and in-service dates.Without levelization,this potential distortion is
8 driven by how capital costs are included in rate base over time.Capital revenue
9 requirement is generally highest in the first year an asset is placed in service and
10 declines over time as the asset depreciates.
11 Consider the potential implications of modeling nominal capital revenue
12 requirement for a future generating resource needed in 2036,the last year of the 2017
13 IRP planning period.If nominal capital revenue requirement were assumed,the model
14 would capture in its economic assessment of resource alternatives the highest,first-
15 year revenue requirement capital cost without having any foresight into the potential
16 benefits that resource would provide beyond 2036.If nominal capital costs were
17 applied,the model's economic assessment of resource alternatives for the 2036
18 resource need would inappropriately favor less capital-intensive projects or projects
19 having longer asset lives,even if those alternatives would increase system costs over
20 their remaining life.Levelized capital costs for assets that have different lives and in-
21 service dates is an established way to address these types of distortions in the
22 comparative economic analysis of resource alternatives.
O
REDACTED Link,Di -27
Rocky Mountain Power
l Q.How did PacifiCorp forecast the annual revenue-requirementimpacts of the
2 Combined Projects?
3 A.In the simulations that include the Combined Projects,the annual stream of costs for
4 the Wind Projects,including levelized capital and PTCs,the QF Projects,and the
5 Transmission Projects are temporarily removed from the annual stream of costs used
6 to calculate the stochastic-mean PVRR.The differential in the remaining stream of
7 annual costs,which includes all system costs except for those associated with the
8 Combined Projects and the QF Projects,represents the net system benefit caused by
9 the Combined Projects.
10 These data are disaggregated to isolate the estimated annual NPC benefits,other
11 non-NPC variable-cost benefits (i.e.,variable operations and maintenance and
12 emissions costs for those scenarios that include a CO2 price assumption),and fixed-
13 cost benefits.To complete the annual revenue-requirement forecast,the change in costs
14 for the Combined Projects and the QF Projects,including nominal capital revenue
15 requirement and PTCs,are added back in with the annual system net benefits caused
16 by the Combined Projects.
17 Q.Over what time frame did PacifiCorp estimate the change in annual revenue
18 requirementdue to the Combined Projects?
19 A.The change in annual revenue requirement was estimated through 2050.This captures
20 the full 30-year life of the Wind Projects.
21 Q.What is the assumed life of the Transmission Projects?
22 A.PacifiCorp assumed a 62-year life for the Transmission Projects.The Transmission
23 Projects will continue to provide system benefits well beyond 2050 when the Wind
O
REDACTED Link,Di -28
Rocky Mountain Power
l Projects are fully depreciated.These additional benefits are not reflected in
2 PacifiCorp's economic analysis.
3 Q.How did PacifiCorp calculate the annual net benefits caused by the Combined
4 Projects beyond the 20-year forecast period used in PaR?
5 A.The PaR-forecast period runs from 2017 through 2036.The change in net system
6 benefits caused by the Combined Projects over the 2028-through-2036 time frame,
7 expressed in dollars-per-MWh of incremental energy output from the Wind Projects
8 and the QF Projects,were used to estimate the change in net system benefits from 2037
9 through 2050.This calculation was performed in several steps.
10 First,the net system benefits caused by the Combined Projects were divided by
11 the change in incremental energy expected from the Wind Projects and the QF Projects,
12 as modeled in PaR over the 2028-through-2036 time frame.Next,the net system
13 benefits per MWh of incremental energy from the Wind Projects and the QF Projects
14 over the 2028-through-2036time frame were levelized.These levelized results were
15 extended out through 2050 at inflation.The levelized net system benefits per MWh of
16 incremental energy output from the Wind Projects and the QF Projects over the 2037-
17 through-2050 time frame were then multiplied by the change in incremental energy
18 output from the Wind Projects and the QF Projects over the same period.
19 Q.Why did PacifiCorp use PaR results from the 2028-through-2036 time frame to
20 extend system cost impacts out through 2050?
21 A.Consistent with the 2017 IRP,PacifiCorp's economic analysis of the Combined
22 Projects assumes the Dave Johnston coal plant,located in eastern Wyoming,retires at
23 the end of 2027.When this plant is assumed to retire,transmission congestion affecting
O
REDACTED Link,Di -29
Rocky Mountain Power
1 energy outputfrom resources in eastern Wyoming,where the Wind Projects and the QF
2 Projects are located,is reduced.The incremental energy output from the Wind Projects
3 and the QF Projects provides more system benefits when not constrained by
4 transmission limitations.Consequently,the net-system benefits caused by the
5 Combined Projects over the 2028-through-2036time frame,after Dave Johnston is
6 assumed to retire,is representative of net system benefits that could be expected beyond
7 2036.
8 Q.Did PacifiCorp calculate a PVRR(d)for the Combined Projects using its estimate
9 of annual revenue requirementimpacts projected out through 2050?
10 A.Yes.
11 PRICE-POLICY SCENARIOS
12 Q.Please explain why price-policy scenarios are important when analyzing the
13 Combined Projects.
14 A.Wholesale-power prices,often set by natural-gas prices,and the system cost impacts
15 of potential CO2 policies influence the forecast of net system benefits from the
16 Combined Projects.Wholesale-power prices and CO2 policy outcomes affect the value
17 of system energy,the dispatch of system resources,and PacifiCorp's resource mix.
18 Consequently,wholesale-power prices and CO2 policy assumptions affect the NPC
19 benefits,non-NPC variable-cost benefits,and system fixed-cost benefits of the
20 Combined Projects.Because wholesale-powerprices and CO2policy outcomes are both
21 uncertain and important drivers to the economic analysis,PacifiCorp studied the
22 economics of the Combined Projects under a range of different price-policy scenarios.
O
REDACTED Link,Di -30
Rocky Mountain Power
l Q.What price-policy scenarios did PacifiCorp use in its economic analysis of the
2 Combined Projects?
3 A.PacifiCorp analyzed the Combined Projects under nine different price-policy scenarios.
4 PacifiCorp developed three wholesale-powerprice scenarios (low,medium,and high),
5 and similarly developed three CO2policy scenarios (zero,medium,and high).The nine
6 price-policy scenarios developed for the economic analysis of the Combined Projects
7 reflect different combinations of these scenario assumptions.
8 Considering that there is a high level of correlation between wholesale-power
9 prices and natural-gas prices,the wholesale-power price scenarios were based on a
10 range of natural-gas price assumptions.This ensures consistency between power price
11 and natural-gas price assumptions for each scenario.PacifiCorp implemented its CO2
12 policy assumptions through a CO2 price,expressed in dollars-per-ton.O 13 While it is unlikely that the CPP will be implemented in its current form,it is
14 possible that future CO2 policies targeting electric-sector emissions could be adopted
15 and impose incremental costs to drive emissions reductions.CO2 price assumptions
16 used in the price-policy scenarios are not intended to mimic a specific type of policy
17 mechanism (i.e.,a tax or an allowance price under a cap-and-trade program),but are
18 intended to recognize that there might be future CO2 policies that impose a cost to
19 reduce emissions.Table 1 summarizes the nine price-policy scenarios used to analyze
20 the Combined Projects.
O
REDACTED Link,Di -31
Rocky Mountain Power
Tab e 1.Price-Policy Scenarios
Price-Policy Scenario Natural-Gas Prices CO2 Price Description(Levelized$/MMBtu)*
Low Gas,Zero CO2 $3.19 $0/ton
$3.41/ton in 2025 growing toLowGas,Medium CO2 $3.19 .$14.40/ton in 2036
$4.73/ton in 2025 growing toLowGas,High CO,$3.19 .$38.42/ton m 2036
Medium Gas,Zero CO2 $4.07 $0/ton
$3.41/ton in 2025 growing toMediumGas,Medium CO2 $4.13 $14.40/ton in 2036
.$4.73/ton in 2025 growing toMediumGas,High CO2 $4.13 .$38.42/ton in 2036
High Gas,Zero CO2 $5.83 $0/ton
.$3.41/ton in 2025 growing toHighGas,Medium CO2 $5.83 .$14.40/ton in 2036
$4.73/ton in 2025 growing toHighGas,High CO2 $5.83 $38.42/ton in 2036
*Nominal levelized Henry Hub natural-gas price from 2018 through 2036.
1 Q.Please describe the natural-gas price assumptions used in the price-policy
2 scenarios.
3 A.The medium-natural-gas-price assumptions that are paired with zero CO2 prices reflect
4 natural-gas prices from PacifiCorp's official forward price curve ("OFPC")dated
5 April 26,2017.The OFPC uses observed forward market prices as of April 26,2017,
6 for 72 months,followed by a 12-month transition to natural-gas prices based on a
7 forecast developed by .The low-,medium-,and high-natural-gas price
8 assumptions used for all other scenarios were chosen after reviewing a range of credible
9 third-party forecasts developed by ,and the U.S.Department of
10 Energy's Energy Information Administration.Exhibit No.23 shows the range in
11 natural-gas price assumptions from these third-party forecasts relative to those adopted
12 for the price-policy scenarios to evaluate the Combined Projects.
13 The low-natural-gas price assumption was derived from a low-price scenario
14 developed by ,which is based on surging growth in price-inelastic associated gas,
O
REDACTED Link,Di -32
Rocky Mountain Power
l technology improvements,stagnant liquefied-natural-gas exports,and an ever-
2 expanding resource base.The medium-natural-gas price assumption,which is used
3 beyond month 84 in the April 2017 OFPC,and in all months when medium-natural-gas
4 prices are paired with medium or low CO2price assumptions,is based on a base-case
5 forecast from that is reasonably aligned with other base-case forecasts.The
6 high-natural-gasprice assumption was based on a high-price scenario from .
7 The high-price scenario is based on risk-aversion,whereby natural-gas developers are
8 reluctant to commit capital before demand,and the associated price response,
9 materializes.This gives rise to exaggerated boom-bust cycles (cyclical periods of high
10 prices and low prices).PacifiCorp smoothed the boom-bust cycle in the third party's
11 high-price scenario because the specific timing of these cycles are extremely difficult
12 to project with reasonable accuracy.
13 Figure 1 shows Henry Hub natural-gas price assumptions from the April 2017
14 OFPC,low-,medium-,and high-natural-gas price scenarios.The April 2017 OFPC
15 forecast only differs from the medium-natural-gas-price assumption in that it reflects
16 observed-market forwards through the first 72 months followed by a twelve-month
17 transition to 's base-caseforecast.
O
REDACTED Link,Di -33
Rocky Mountain Power
Figure 1.Nominal Natural-Gas Price Scenarios
$11
$10 O
$9 /
-G-Low Gas -Aled Gas (Apiil 2013 OFPC)
·--Aled Gas -e-High Gas
1 Q.Please describe the CO2 price assumptions used in the price-policy scenarios.
2 A.As with natural-gas prices,the medium-and high-CO2 price assumptions are based on
3 third-party projections from and .Both forecasters assume CO2prices
4 start in 2025.To bracket the low end of potential-policy outcomes,PacifiCorp assumes
5 there are no future policies adopted that would require incremental costs to achieve
6 emissions reductions in the electric sector.In this scenario,the assumed CO2 price is
7 zero.Figure 2 shows the three CO2 price assumptions used to analyze the Combined
8 Projects.
O
REDACTED Link,Di -34
Rocky Mountain Power
Figure 2.Nominal CO2-Price Scenarios
$45
$40
$30 µ&
--Zero -Medium -4-High
l SYSTEM MODELING PRICE-POLICY RESULTS
2 Q.Please summarize the PVRR(d)results calculated from the SO model and PaR
3 through 2036.
4 A.Table 2 summarizes the PVRR(d)results for each price-policy scenario.The PVRR(d)
5 between cases with and without the Combined Projects are shown from the SO model
6 and from PaR,which was used to calculate both the stochastic-mean PVRR(d)and the
7 risk-adjusted PVRR(d).The data that was used to calculate the PVRR(d)results shown
8 in the table are provided as Exhibit No.24.
O
REDACTED Link,Di -35
Rocky Mountain Power
Table 2.SO Model and PaR PVRR(d)
(Benefit)/Cost of the Combinet Projects ($millit n)
PaR Risk-
.SO Model PaR Stochastic-AdjustedPrice-Policy Scenario PVRR(d)Mean PVRR(d)
Low Gas,Zero CO2 $121 $77 $74
Low Gas,Medium CO2 $73 $32 $26
Low Gas,High CO2 ($84)($133)($147)
Medium Gas,Zero CO2 ($19)($57)($66)
Medium Gas,Medium CO2 ($85)($111)($124)
Medium Gas,High CO2 ($156)($224)($242)
High Gas,Zero CO2 ($304)($260)($280)
High Gas,Medium CO2 ($318)($272)($293)
High Gas,High CO2 ($396)($409)($437)
1 Over a 20-year period,the Combined Projects reduce customer costs in seven
2 out of nine price-policy scenarios price-policy scenarios.This trend occurs in the
3 PVRR(d)calculated from both the SO model and PaR.The onlyprice-policy scenarios
4 without net customer benefits are those assuming the lowest natural-gas prices when
5 paired with either medium or zero-CO2 price assumptions.Under the central price-
6 policy scenario,assuming medium-natural-gas prices and medium-CO2 prices,the
7 PVRR(d)benefits range between $85 million,when based upon SO model results,and
8 $124 million,when based upon PaR-risk-adjusted results.
9 The PVRR(d)results show that the benefits of the Combined Projects increase
10 with natural-gas prices and CO2 prices,which increase NPC and other system variable
11 cost benefits.
12 Q.Is there incremental customer upside to the PVRR(d)results calculated from the
13 SO and PaR models through 2036?
14 A.Yes.The PVRR(d)results presented in Table 2 do not reflect the potential value of
15 RECs generated by the incremental wind energy output from the Wind Projects.
O 16 Customer benefits for all price-policy scenarios would improve by approximately $26
REDACTED Link,Di -36
Rocky Mountain Power
l million for every dollar assigned to the incremental RECs that will be generated from
2 the Wind Projects through2036.Beyond potential REC-revenue benefits,the economic
3 analysis of the Combined Projects does not reflect PacifiCorp's enhanced ability to
4 comply with mandated reliabilityand performance standards the opportunity for further
5 increases to the transfer capability across the Aeolus-to-Bridger/Anticline Line with the
6 construction of additional segments of the Energy Gateway project.
7 Q.Why do the PaR results tend to show a different level of benefits from Combined
8 Projects when compared to the results from the SO model?
9 A.The two models assess the system impacts of the Combined Projects in different ways.
10 The SO model is designed to dynamically assess system dispatch,with less granularity
11 than PaR,while optimizing the selection of resources to the portfolio over time.PaR is
12 able to dynamically assess system dispatch,with more granularity than the SO model
13 and with consideration of stochastic risk variables;however,PaR does not modify the
14 type,timing,size and location of resources in the portfolio in response to its more
15 detailed assessment of system dispatch.
16 Q.Does one of these two models provide a better assessment of the Combined
17 Projects relative to the other?
18 A.No.The two models are simply different,and both are useful in establishing a range of
19 benefits from the Combined Projects through the 20-year forecast period.Importantly,
20 the PVRR(d)results from both models show customer benefits across all price-policy
21 scenarios with consistent trends in the difference in PVRR(d)results between price-
22 policy scenarios.The consistency in the trend of forecasted benefits between the two
23 models,each having its own strengths,shows that the benefits from the Combined
O
REDACTED Link,Di -37
Rocky Mountain Power
l Projects are robust across a range of price-policy assumptions and when analyzed using
2 different modeling tools.
3 Q.How do the risk-adjusted PVRR(d)results compare to the stochastic-mean
4 PVRR(d)results?
5 A.The risk-adjusted PVRR(d)results consistently show a slight increase in the benefits
6 of the Combined Projects when compared to the stochastic-mean PVRR(d)results.This
7 indicates that the Combined Projects reduce the risk of high-cost,low-probability
8 outcomes that can occur due to volatilityin stochastic variables like load,wholesale-
9 market prices,hydro generation,and thermal-unit outages.
10 ANNUAL REVENUE REQUIREMENTPRICE-POLICY RESULTS
11 Q.Please summarize the PVRR(d)results calculated from the change in annual
12 revenue requirementthrough 2050.
13 A.Table 3 summarizes the PVRR(d)results for each price-policy scenario calculated off
14 of the change in annual nominal revenue requirement through 2050.The annual data
15 over the period 2017 through 2050 that was used to calculate the PVRR(d)results
16 shown in the table are provided as Exhibit No.25.
Table 3.Nominal Revenue RequirementPVRR(d)
(Benefit)/Cost of the Combined Projects ($million)
Price-Policy Scenario Annual Revenue RequirementPVRR(d)
Low Gas,Zero CO2 $174
Low Gas,Medium CO2 $93
Low Gas,High CO2 ($194)
Medium Gas,Zero CO2 ($53)
Medium Gas,Medium CO2 ($137)
Medium Gas,High CO2 ($317)
High Gas,Zero CO2 ($341)
High Gas,Medium CO2 ($351)
High Gas,High CO2 ($595)
O
REDACTED Link,Di -38
Rocky Mountain Power
l When calculated through 2050,which covers the 30-year life of the Wind
2 Projects,the Combined Projects reduce customer costs in seven out of nine price-policy
3 scenarios.The only price-policy scenarios without net customer benefits are those
4 assuming the lowest natural-gas prices when paired with either medium or zero-CO2
5 price assumptions.The PVRR(d)results show customer benefits under the price-policy
6 scenario with low natural-gas prices and high-CO2 prices,in all three of the medium-
7 natural-gas price scenarios,and in all three of the high-natural-gas price scenarios.
8 Under the central price-policy scenario,assuming medium-natural-gas prices and
9 medium-CO2 prices,the PVRR(d)benefit is $137 million.
10 Consistent with the PVRR(d)results calculated from the SO model and PaR
ll through 2036,the PVRR(d)results show that the benefits of the Combined Projects
12 increase with natural-gas prices and CO2 prices,which increase NPC and other system
13 variable cost benefits.
14 Q.What causes the decrease in PVRR(d)benefits when calculated off of nominal
15 revenue requirement through 2050 relative to the PVRR(d)results calculated
16 from the SO model and PaR results through 2036?
17 A.The PVRR(d)calculated from estimated annual revenue requirement through 2050
18 reflects reduced incremental wind energy output beginning in 2042 after the QF
19 Projects'PPAs end.Confidential Figure 3 shows the incremental change in wind energy
20 output from the Wind Projects and the QF Projects.Incremental energy output
21 associated with the Combined Projects is steady at approximately GWh over the
22 2022-through-2041 period.Beyond 2041,energy output is approximately
23 GWh .This
O
REDACTED Link,Di -39
Rocky Mountain Power
l reduction in incremental wind energy output reduces NPC benefits and other system
2 variable costs benefits over the last nine years of the PVRR(d)calculated off the change
3 in nominal revenue requirement estimates through 2050.Consequently,the PVRR(d)
4 calculated off the change in nominal revenue requirement through 2050 does not
5 capture likely benefits associated with a potential extension of the QF Projects'PPAs
6 or incremental procurement of additional Wyoming wind resources after the term of
7 these PPAs end.
Confidential Figure 3.Change Incremental Wind Energy
Out ut from the Wind Pro°ects and F Pro°ects GWh
O
8 Q.Is there incremental customer upside to the PVRR(d)results calculated from the
9 change in estimated annual revenue requirementthrough 2050?
10 A.Yes.As in the case with the PVRR(d)results calculated from the SO model and PaR
11 results through 2036,the PVRR(d)results presented in Table 3 do not reflect the
12 potentialvalue of RECs produced by the Wind Projects.Customer benefits for all price-
13 policy scenarios would improve by approximately $34 million for every dollar assigned
O 14 to the incremental RECs that will be generated from the Wind Projects through 2050.
REDACTED Link,Di -40
Rocky Mountain Power
l Q.Please describe the change in annual nominal revenue requirement from the
2 Combined Projects.
3 A.Figure 4 shows the estimated change in annual nominal-revenuerequirement due to the
4 Combined Projects for the medium-natural-gas and medium-CO2-price-policyscenario
5 on a total-system basis.The annual revenue requirement shown in the figure reflects
6 all costs for the Combined Projects,including capital revenue requirement
7 (i.e.,depreciation,return,income taxes,and property taxes)net of transmission
8 revenue credits,operations and maintenance expenses,the Wyoming wind-production
9 tax,incremental wind integration costs,and PTCs.The project costs are netted against
10 system impacts of the Combined Projects,reflecting the change in NPC,emissions,
11 non-NPC variable costs,and system fixed costs that are affected by,but not directly
O 12 associated with,the Combined Projects.
Figure 4.Total-System Change in Annual Revenue Requirement
Due to the Combined Projects ($million)
$60
$40
$20
$0
($40)
($60)
($80)
($100)
13 In the initial year the Combined Projects come online,net system benefits offset
14 partial-year capital revenue requirement.In 2021,the first full year the Combined
15 Projects are in service,the change in total-system nominal revenue requirement
REDACTED Link,Di -41
Rocky Mountain Power
l increases by $51 million.This figure rapidly declines and crosses over from a net
2 increase in nominal revenue requirement to a decreasein nominal revenue requirement
3 beginning 2024-just four years after the first full year of operation.The net revenue
4 requirement benefits persist and grow through 2030 as PTC benefits increase with
5 inflation and the new equipment continues to depreciate.On a total-system basis,the
6 change in annual revenue requirement is down by $109 million in 2030-the last year
7 the Wind Projects produce PTCs.After the PTCs expire,annual revenue requirement
8 increases.However,as the assets continue to depreciate,the Combined Projects once
9 again begin producing annual revenue requirement savings beginning 2036.These
10 annual benefits persist through 2050.
11 SENSITIVITY STUDY RESULTS
12 Q.Please summarize the results of the sensitivity that assumes the Wind Projects
13 have a 40-year-depreciable life.
14 A.Table 4 summarizes the PVRR(d)results for the sensitivity assuming a 40-year life for
15 the Wind Projects.To assess the relative impact of the 40-year life,the PVRR(d)results
16 were calculated through 2036 based on SO model and PaR results and are presented
17 alongside the benchmark study in which the Combined Projects were evaluated
18 assuming a 30-year life for the Wind Projects.Medium-natural-gasand medium-CO2
19 price-policy assumptions were applied to this sensitivity.
Table 4.40-Year-Life Sensitivity
(Benefit)/Cost of the Combined Pro,ects ($million)
Model Sensitivity Benchmark Change in
PVRR(d)PVRR(d)PVRR(d)
SO Model ($106)($85)($21)
PaR Stochastic-Mean ($132)($111)($21)
PaR Risk-Adjusted ($145)($124)($21)
O
REDACTED Link,Di -42
Rocky Mountain Power
l If the Wind Projects are depreciated over a 40-year life,reduced book
2 depreciation would drive lower annual revenue requirement.In this sensitivity,
3 PVRR(d)benefits increase by approximately $21 million relative to the benchmark
4 case assuming a 40-year life for the Wind Projects.
5 Q.Please summarize the results of the sensitivity that analyzes the Combined
6 Projects with wind repowering.
7 A.Table 5 summarizes the PVRR(d)results for the sensitivity assuming the Combined
8 Projects are implemented along with wind repowering of approximately 999 MW of
9 existing wind capacity.To assess the relative impact of wind repowering on the
10 Combined Projects,the PVRR(d)results were calculated through 2036 based on
11 SO model and PaR results and are presented alongside the benchmark study in which
12 the Combined Projects were evaluated without repowering.Medium-natural-gas and
13 medium-CO2 price-policy assumptions were applied to this sensitivity.
Table 5.The Combined Projects with Wind Repowering Sensitivity
(Benefit)/Cost ($million)
Model Sensitivity Benchmark Change in
PVRR(d)PVRR(d)PVRR(d)
SO Model ($114)($85)($29)
PaR Stochastic-Mean ($104)($111)$8
PaR Risk-Adjusted ($116)($124)$8
14 When the Combined Projects are analyzed with the wind repowering project,
15 PVRR(d)benefits increase by $29 million when assessed with the SO model.PaR
16 shows a slight $8 million increase to the PVRR(d).
17 Q.Do the PaR results for this sensitivity indicate that the wind repowering project
18 lowers customer benefits if implemented in parallelwith the Combined Projects?
19 A.No.The sensitivity does not capture any of the incremental benefits from the wind
20 repowering project that will occur just beyond the 2036 period,which is the last year
REDACTED Link,Di -43
Rocky Mountain Power
l simulated in the SO model and PaR.Consequently,the PVRR(d)results from the
2 SO model and PaR do not capture the significant increase in the benefits from
3 repowering that is associated with increased incremental energy output that will occur
4 beyond2036.
5 The change in wind energy output between cases with and without repowering
6 experiences a step change in the 2036-through-2040 time frame,when the wind
7 facilities within the repowering project scope that were originally placed in-service
8 during the 2006-through-2010time frame would otherwise have hit the end of their
9 depreciable life.Before the 2036-through-2040time frame,the period captured in the
10 PVRR(d)results summarized in Table 5,the change in wind energy output from
11 repowering reflects the incremental energy production that results from installing
12 modern equipment on repowered wind assets.Beyond the 2036-through-2040 time
13 frame,a period that is not captured in the PVRR(d)results reported in Table 5,the
14 change in wind energy output between a case with and without repowering reflects the
15 full energy output from the repowered wind facilities that would otherwise be retired.
16 Figure 5 shows the incremental change in wind energy output resulting from
17 the repowering project.Incremental energy output associated with wind repowering
18 progressivelyincreases over the 2036-through-2040period,as wind facilities originally
19 placed in service in the 2006-through-2010time frame would have otherwise hit the
20 end of their lives.Before 2036,and once all of the wind resources within the project
21 scope are repowered,the average annual incremental increase in wind energy output is
22 approximately 551 GWh.Beyond 2040,and before the new equipment hits the end of
23 its depreciable life,the average annual incremental increase in wind energy output is
O
REDACTED Link,Di -44
Rocky Mountain Power
l approximately 3,283 GWh.The value of this incremental wind-energy output
2 associated with repowering adds substantial incremental benefits not reflected in the
3 PVRR(d)results for this sensitivity that would more than offset the modest $8 million
4 PVRR(d)incremental cost based on PaR results through 2036.
Figure 5.Change in Incremental Wind EnergyOutput
Due to Repowering (GWh)
3,000
2,500
2,000
1,000
'°°IIIIIIIIIIIIIIIIII .O °·
5 CONCLUS I ON
6 Q.Please summarize the conclusions of your testimony.
7 A.PacifiCorp's analysis supports proceeding with its planned investments in the Wind
8 Projects and Transmission Projects.The Wind Projects,which are enabled by the
9 Transmission Projects will:(1)qualifyfor ten years of federal PTCs;(2)produce zero-
10 fuel-cost energy that will lower NPC;(3)generate RECs,which can be sold in the
11 market to create additional revenues that would lower net customer costs;and (4)help
12 to decarbonize PacifiCorp's resource portfolio,which mitigates long-term risk
O
REDACTED Link,Di -45
Rocky Mountain Power
l associated with potential future state and federal policies targeting CO2 emissions
2 reductionhse
T
hsemsericretoerets
will:(1)relieve congestion on the current
4 transmission system in eastern Wyoming;(2)enable the additional wind resource
5 interconnections;(3)provide critical voltage support to the Wyoming transmission
6 network;(4)improve overall reliability of the transmission system and enhance
7 PacifiCorp's ability to comply with mandated reliability and performance standards;
8 (5)reduce line losses;and (6),create an opportunity for further increases to the transfer
9 capability across the Aeolus-to-Bridger/Anticline Line with the construction of
10 additional segments of the Energy Gateway project.
11 The economic analysis of the Combined Projects demonstrates that net benefits
12 more than outweigh net project costs.
13 Q.What do you recommend?
14 A.As supported by PacifiCorp's economic analysis,I recommend that the Commission
15 determine that PacifiCorp's decision to invest in the Wind Projects and the
16 Transmission Projects is in the public interest and approve the Application as filed,
17 including the proposed ratemaking treatment for the new costs and benefits of the
18 Combined Projects.
19 Q.Does this conclude your direct testimony?
20 A.Yes.
O
REDACTED Link,Di -46
Rocky Mountain Power
O
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 )DIRECT TESTIMONY OF
CONVENIENCE AND NECESSITY AND )RICK T.LINK
BINDING RATEMAKING TREATMENT )REDACTED
FOR NEW WIND AND TRANSMISSION )FACILITIES )
O
ROCKY MOUNTAIN POWER
CASE NO.PAC-E-17-07
June 2017
O