20171218Vail Rebuttal.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )CASE NO.PAC-E-17-07OFROCKYMOUNTAINPOWERFORA)CERTIFICATEOF PUBLIC )REBUTTAL TESTIMONY OFCONVENIENCEANDNECESSITYAND)RICK A.VAILBINDINGRATEMAKINGTREATMENT)FOR NEW WIND AND TRANSMISSION )FACILITIES )
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ROCKY MOUNTAIN POWER
CASE NO.PAC-E-17-07
December 2017
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l Q.Are you the same Rick A.Vail who previously provided direct testimony in this
2 case on behalf of Rocky Mountain Power ("Company"),a division of PacifiCorp?
3 A.Yes.
4 PURPOSE AND SUMMARY OF REBUTTAL TESTIMONY
5 Q.What is the purpose of your rebuttal testimony?
6 A.I support of the Company's application for certificates of public convenience and
7 necessity ("CPCNs")and for binding ratemaking treatment,I update the status of
8 several aspects of the Aeolus-to-Bridger/Anticline Line and 230 kV Network Upgrades
9 ("Transmission Projects"),and show the important progress the Company has made on
10 the Transmission Projects,as well as their decreasing risk.I also respond to the direct
ll testimony of Monsanto Company ("Monsanto"),PacifiCorp Idaho Industrial
12 Customers ("PIIC"),and the Staff of the Public Utilities Commission of Idaho
13 ("Staff").
14 Q.Please summarize your rebuttal testimony.
15 A.I address the followingkey issues for the Transmission Projects:
16 An update of the status of:
17 Expected design and cost;
18 Engineering,Procurement,and Construction ("EPC")contracts;
19 Required permits at the federal,state,and local level;and
20 The required power system analyses and easements.
21 The necessity of these projects to reduce line losses and derates along with
22 dispatching of Company-owned resources.
23 Mitigation of risks to minimize costs and project delays due to:
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l The permitting process and the Company's plan for obtaining required
2 permits prior to construction;
3 Obtaining the required easements;and
4 Construction delays (EPC contracts and mitigation for meeting
5 constructiondeadlines).
6 Relevant Open Access Transmission Tariff ("OATT")and Federal Energy
7 Regulatory Commission ("FERC")precedent confirming the reasonablenessof
8 the Company's assumptions regarding revenues from third-party customers.
9 The Company's need for timely CPCNs to maintain project timelines.
10 TRANSMISSION PROJECTS UPDATE
11 Q.Since the initial CPCN filing,has the Company maintained the project schedule
12 and cost estimates for the Transmission Projects?
O 13 A.Yes.The Company has made significant progress in the development of the
14 Transmission Projects since its initial filing.The Company is on track to meet its
15 development schedule at or below the costs estimated in its filing.
16 Q.Please provide a status update on the design of the Transmission Projects.
17 A.Currently,both the 500 kV transmission facilities and 230 kV network upgrades are in
18 the detail design phase.For the 500 kV facilities,the major effort is focused on two key
19 elements:(1)micro-siting structures;and (2)structure design.
20 Micro-siting structures involves confirming the precise structure locations and
21 associated access roads to accommodate features such as pipelines,fiber optic cables,
22 and other utilities,along with micro-siting to avoid sensitive biological or cultural
23 features.
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l The structure design process focuses on selecting the tower and foundation
2 design that will be used.Before filing the CPCN application,the Company decided it
3 could use a new tower design that would significantly reduce the structures weight and,
4 therefore,cost as compared to the tower design used in other segments of the Energy
5 Gateway project.The Company is in the process of developingand testing the revised
6 structures and expects to complete this by summer 2018,in line with the overall EPC
7 schedule.The Company is currently completing the initial design phase,the first
8 prototype has begun the fabrication process,and tower testing is scheduled to begin
9 mid-first-quarter 2018.Development efforts to date have confirmed the baseline
10 assumptions included in the design and cost basis of the CPCN filing.
11 In addition,the Company completed a geotechnical program during the summer
12 of 2017 to further aid the EPC contractors in bid preparation and reduce the risk
13 assumptions associated with the foundationdesign.The overall 500 kV transmission
14 design package is on track to be complete by April 2018.
15 Q.What is the status of the 500 kV substation design work?
16 A.The 500 kV substation design work is on schedule.The Company has focused recent
17 efforts on thoroughly analyzing the precise location and space requirements for each
18 new substation.This has led to a reduction in the initial space requirements and allowed
19 for a balanced cut and fill design to reduce the cost of importing high cost fill materials.
20 At the Jim Bridger substation,design optimizationefforts will facilitate construction of
21 the new line terminationbay while minimizing disruptions to the existing facility.The
22 substation design necessary for competitive market EPC bidding is anticipated to be
23 completed by April 2018.
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1 Q.What is the status of the 230 kV facilities?
2 A.Design work for the 230 kV transmission facilities is also ongoing.The Company has
3 selected the proposed line route,after considering field surveys for biological and
4 cultural constraints,as well as incorporating landowner comments.Structure design
5 will be based upon the Company's standard design steel H frames.The Company will
6 begin design work for the 230 kV substations in early 2018.All design work for the
7 230 kV facilities will be completed by the fall of 2018,to allow for the competitive
8 market procurement process to support a 2019 construction period.
9 Q.Is there any change in the projected costs of the Transmission Projects?
10 A.No.The cost estimates included in the original filing are the same.As discussed below,
11 the construction costs will be updated as a part of the January 16,2018 supplemental
12 filing.O 13 Q.What is the current status of the EPC contract for the 500 kV line?
14 A.The Company is currently in a competitive selection process for an EPC contractor for
15 the 500 kV line.Because the 500 kV line is approximately 85 percent of the total costs
16 of the Transmission Projects,the selection of the EPC contractor will be a significant
17 milestone in confirming final project costs.The Company will have the preliminary
18 results of this process by its supplemental testimony January 16,2018,and will include
19 resulting cost updates at that time.
20 Q.Please provide more detail on the status of the EPC contracts for the Transmission
21 Projects.
22 A.The Company has engaged with eight transmission line contractors to secure Master
23 Service Agreement Terms and Conditions that will apply to the Transmission Projects.
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l The contractors represent some of the leading engineering and construction companies
2 in the country.Negotiationsare currently ongoing to finalize these terms and conditions
3 by January 2018.
4 Concurrent with these activities,the Company issued a request for detailed
5 technical information to the same contractors.This request requires contractors to
6 provide detailed project plans,resource profiles,schedules and cost data.The responses
7 will be analyzed to develop a shortlist of contractors,based on a combination of cost
8 and viability of the overall project approach,for a final pricing event in the summer
9 2018.Contractor responses were received December 11,2017.The data within the
10 responses will also be used to inform the analysis being performed for the Wyoming
11 Industrial Siting Permit application.The 500 kV transmission line EPC contracts
12 remain on track to be in place by October 2018.O 13 For the 500/345 kV substation scope of work,the Company is currently
14 preparing a Terms and Conditions RFP that will be issued by early February 2018 to
15 up to six qualified contractors who will be responsible for full EPC services for the
16 500/345kV substations.This RFP will also request budgetary price information.The
17 Company intends to negotiate EPC contract terms and conditions before final pricing
18 to expedite final contract negotiations in the fall of2018.A final price bid event will be
19 issued to all six companies in the summer of 2018.
20 For the 230 kV network upgrades,the Company intends to competitively source
21 both the transmission line and substation construction via existing term "Line Service
22 Agreements"the Company holds with over one dozen qualified contractors capable of
23 working in Wyoming.The Company may acquire major substation equipment as a
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l direct purchase via a competitive RFP to qualified vendors.The 230 kV work is on
2 schedule to be procured in late 2018 with main construction anticipated during 2019.
3 Q.What is the status of the permits required for construction of the Transmission
4 Projects?
5 A.The Company has been working with various agencies and stakeholders to obtain the
6 final permits necessary to construct the facilities and the Company's permitting
7 activities remain on schedule.A summary of key items is presented below:
8 Section 106 Consultation,National Historic Preservation Act:Field surveys
9 were completed during the summer of 2017.The fmal class III cultural report was
10 submitted to the BLM on December 15,2017.Amendments to the Programmatic
ll Agreement have been issued to stakeholders,agreement is anticipated by
12 December 31,2017.Draft outlines for the Historic Properties Treatment Plan have beenO13issuedtostakeholdersforcomments,which are due December 15,2017.Final approval
14 by the Wyoming State Historic Preservation Office of the Class III report and the
15 Historic Properties Treatment Plan is expected by mid-August 2018.
16 Plan of Development:Work continues in close cooperation with the BLM.
17 Initial updated draft sections have been providedto the BLM,with comments received.
18 The Plan of Development is on schedule to be completed by May 2018 to support the
19 EPC procurement schedule.Final Plan of Development mapping will be completed by
20 the end of 2018 after inclusion of updated data from the 2018 field survey season.
21 Clean Water Act Sections 401:Wyoming Department of Environmental
22 Quality ("WYDEQ")Water Quality Division ("WQD")has categorically-certifiedthe
23 majority of the 2017 USACE Nationwide Permits on non-Class l waters in Wyoming
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1 with the expectation that applicants must comply with the permit's terms and
2 conditions,including permit specific 401 Certification conditions for the certification
3 to be valid.These categorically-certified permits do not require an individual 401
4 Certification by the WDEQ/WQD.The Project requires that a section 404,nationwide
5 permit 12 be obtained.This will meet the requirements under the State of Wyoming for
6 Section 401 certification.
7 Section 404/NWP 12:The Project has completed all wetland delineations to
8 determine impacts.These potential impacts are being reviewed for avoidance via detail
9 design reviews.The Company will submit its pre-construction notification to certify
10 the project does not exceed greater than 0.1 acre of permanent impact at any one
11 delineated wetland area.This is on schedule for approval in May 2018.
12 Wyoming Industrial Siting Permit:The Company held an initial meeting withO13theWYDEQwithrespecttotheIndustrialSitingPermitandtheWYDEQdetermined
14 the jurisdictional determination first recorded in 2012 is still valid.The Company is
15 preparing an applicationfor submission by the end of June 2018.The 135 day review
16 period as described in the Wyoming Administrative Rules,Chapter 35,will therefore
17 conclude with a decision due by mid-November 2018.
18 Carbon County Conditional Use Permit ("CUP"):The Company held a
19 preliminary meeting with Carbon County to discuss the requirements of the CUP
20 application.The Company is preparing the application for a May 2018 submission with
21 an August 2018 decision.
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l Q.What is the status of the technical studies that are necessary to support the
2 Transmission Projects?
3 A.The Company performed numerous technical studies that show the benefits and
4 reliability improvements resulting from the Transmission Projects.As with any large-
5 scale transmission project,the Company continues to perform additional technical
6 studies.Exhibit No.30 to my rebuttal testimony provides a detailed outline of the
7 studies performed so far and a description of the additional studies that will be
8 performed,along with the timing of the additional studies.
9 In May 2017,the Company completed detailed studies,including power flow
10 and stability analysis,evaluating a wide range of operating conditions.This report,the
11 Preliminary Aeolus West Transmission Path Transfer Capability Assessment,is an
12 exhibit to Monsanto's testimony.O 13 PreliminaryNERC FAC-013-2 Transmission Assessment studies are currently
14 underway for the Aeolus-to-Bridger/Anticline line and are expected to be finalized in
15 2020.The first set of studies to be included in this process has already been completed
16 and showed an increase of transfer capability of 750 MW from east to west across
17 Wyoming.Additional studies cannot be formally initiated until specific new southeast
18 Wyoming wind resources have been identified.Technical analysis shows the Aeolus-
19 to-Bridger/Anticline line increases the system's stiffness factor sufficiently to
20 interconnect up to l,270 MW of new resources.All of the technical study work
21 completed to date continues to support the initial assumptions for the Transmission
22 Projects,the facilities identified,and the benefits that the Transmission Projects will
23 provide.
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l Q.Monsanto witness Mr.James R.Dauphinais is critical of the fact the Company
2 has yet to complete many of the studies that are necessary for the Transmission
3 Projects.(Dauphinais Direct,page 7,lines 4-5.)How do you respond to this
4 criticism?
5 A.Mr.Dauphinais'testimony specifically focused on the lack of power flow,dynamic
6 stability,stiffness factor analysis,Sub-Synchronous Resonance,and voltage stability
7 studies for the Transmission Projects.All necessary transmission planning studies
8 required by WECC,with the exclusion of Sub-Synchronous Resonance studies and
9 stiffness factor analysis,were completed as part of the Aeolus West path ratingprocess,
10 which was granted Phase 3 status on January 5,2011.Sub-Synchronous Resonance
11 studies were completed in November 2017.Stiffness factor analysis is on-going with
12 PacifiCorp utilizingan external consultant to perform Power System Computer AidedOl3Design("PSCAD")analysis.
14 Q.Mr.Dauphinais is also critical of the Company's reliance on a 2010 Western
15 Electricity Coordinating Council ("WECC")study he claims has not been
16 updated.(Dauphinais Direct,page 8,lines 8-10.)How do you respond?
17 A.At the March 30,2010,Gateway West and Gateway South combined project review
18 meeting participants approved the Gateway Phase 2 Study Plan and agreed that
19 incremental limitations for transmission segments added between states,will be
20 addressed via SOL (System Operating Limit)studies.This same process was
21 previously followed and successfully demonstrated by BPA and Avista for the West of
22 Hatwai Expansion project.In additionto SOL studies,which will be completed before
23 the project goes into service,PacifiCorp will be performing FAC-013-2 Transfer
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l Capability Assessment studies,which it will share with other utilities and WECC.
2 These studies are scheduled for completion by October 2019,more than one year in
3 advance of the project in-service date.
4 Q.Mr.Dauphinais claims the Company's October 2017 Aeolus West Transmission
5 Path Transfer Capability Assessment Preliminary Study Report indicates that the
6 Company requires additional facilities that have not been studied yet.(Dauphinais
7 Direct,page 9,lines 5-13.)Is this correct?
8 A.No.The need for dynamic voltage support at Latham Substation and three different
9 Remedial Action Schemes ("RAS")have been studied based on anticipated generation
10 projects in the PacifiCorp Large Generation Interconnection ("LGI")queue;however,
11 the final design of these facilities will not be formalized until the Company obtains the
12 2017R results in early 2018.At that time,the technical studies will be finalized andOl3specifictechnicalrequirementsoftheproposedfacilitiesdefined.The technical study
14 timelines support the proposed in-service date of the project.
15 NECESSITY OF THE TRANSMISSION PROJECTS
16 Q.Mr.Dauphinais claims the proposed Transmission Projects are not needed to serve
17 customer load.(Dauphinais Direct,page 5,line 3 -page 6,line 1).Do you agree?
18 A.No.The Transmission Projects will improve system performance and reliability and
19 directly serve customers.Mr.Dauphinais focuses on the fact that the Transmission
20 Projects will be built only if the Wind Projects are also built.But that is because the
21 Transmission Projects are economic to construct only if the Wind Projects are also built.
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l Q.What is the current status of the Company's eastern Wyoming transmission
2 system?
3 A.The Company's eastern Wyoming transmission system is severely restrained and
4 experiences voltage support issues.While the Company is in compliance with all
5 NERC/WECC reliability standards,the stiffness factor (measurement of a transmission
6 system's ability to control voltage within acceptable limits)in eastern Wyoming is such
7 that new resources cannot be connected to the system,increasing the risk of voltage
8 swings outside acceptable limits in an outage condition.This system condition also
9 limits the ability to schedule outages for segments of the transmission system to
10 perform routine maintenance.
11 Q.Do these general conditions apply specifically to the area where the Transmission
12 Projects will be constructed?O 13 A.Yes.The same constraints and stiffness factor limits present in eastern Wyoming
14 generally are present along the TOT 4A transmission path where the Transmission
15 Projects will be constructed.Because of the constraints and the stiffness factor limit,
16 new resources cannot be connected behind the path (i.e.,east of the path).Further,an
17 outage of a TOT 4A transmission element results in a path derate to prevent a thermal
18 or voltage system violation and maintain system reliability.Existing generation must
19 often be curtailed to operate within derated path limits,which is a curtailment in firm
20 transmission rights used to serve customer load.
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1 Q.PIIC witness Mr.Bradley G.Mullins claims the Aeolus-to-Bridger/Anticlineline
2 may not be the best solution for addressing transmission needs in the West.
3 (MullinsDirect,page 15,lines 13-14).How do you respond?
4 A.Mr.Mullins'claim is without merit,as he provides no substantive analytic support for
5 his contention.Instead,Mr.Mullins implies the Aeolus-to-Bridger/Anticline line was
6 developed outside of the inter-regional transmission planning process required by
7 FERC's Order No.1000.Contrary to Mr.Mullins'implication,the Aeolus-to-
8 Bridger/Anticline line is an integral component of the inter-regional transmission plan
9 developed by the NorthernTier Transmission Group in accordance with FERC's Order
10 No.1000.In fact,the current transmission system master plan for Wyoming calls for
11 the construction of facilities associated with Energy Gateway,specifically Energy
12 Gateway West and Energy Gateway South.The Aeolus-to-Bridger/Anticline line is aO13subsetoftheEnergyGatewayWestproject.
14 The Company has identified these projects in long-term transmission plans to:
15 (1)relieve congestion and increase transmission capacity across Wyoming,allowing
16 interconnection and integration of new generation resources and enabling more
17 efficient dispatch of and greater flexibilityin managing existing resources;(2)provide
18 critical voltage support to the transmission system;(3)improve system reliability;and
19 (4)reduce energy and capacity losses.Up until now,these important benefits of the
20 Transmission Projects have been cost prohibitive.As a part of the Combined Projects,
21 however,customers can economically obtain the much needed support and benefits the
22 Transmission Projects will bring to the Company's existing transmission network.
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l Q.Mr.Mullins also claims the Company should invest in transmission projects that
2 improve reliability,rather than projects that are driven by economics.(Mullins
3 Direct,page 15,lines 15-17).How do you respond to this claim?
4 A.Mr.Mullins does not dispute the Company's extensive evidence that the Aeolus-to-
5 Bridger/Anticline line will,in fact,improve reliability and relieve existing congestion
6 on the eastern Wyoming transmission system.Thus,by his own standards,the Aeolus-
7 to-Bridger/Anticline line is the type of transmission investment that should be pursued.
8 Q.Will the Transmission Projects also increase system efficiency?
9 A.Yes.The addition of a transmission line together with an existing line(s)or path will
10 reduce the impedance of the path,resulting in overall reduced energy line losses.Line
ll losses before and after construction of the Transmission Projects were compared,with
12 the difference being the line savings attributed to the Transmission Projects.ReducedO13linelossesmeanmoreefficientdeliveryofenergyandcapacityatreducedcostswith
14 or without the addition of new generation resources providing additional operational
15 flexibilityof existing resources.
16 Q.Have there been previous investments in transmission facilities along the TOT 4A
17 path?
18 A.Yes.Since the time that the TOT 4A transmission path was initially defined,a
19 significant number of transmission additions and modifications have been made to the
20 Wyoming transmission system to increase the capacity on this path,including the
21 addition of new transmission lines (Spence -Mustang,1991;Dave Johnston -Casper
22 Rebuild,2010;and Sheridan-Dry Fork -Hughes /Carr Draw,2010-11),adding shunt
23 capacitors for voltage support,implementation of dynamic line ratings (Platte-Miners
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l 230 kV line,2013)and addition of a synchronous condenser (Standpipe,2016).
2 As significant new facilities were added,WECC path rating studies have been
3 performed to increase the rating of the path.The last set of path rating studies were
4 completed April 17,2013,with the granting of Phase 3 status by the WECC planning
5 coordinationcommittee ("PCC").These additions and subsequentpath ratings support
6 the adding resources behind the path to the point today where the stiffness factor and
7 the path rating cannot support additional resources without infrastructure additions.
8 Generation interconnection studies have shown that new resources cannot be reliably
9 interconnected without the addition of transmission infrastructure.
10 RISK MITIGATION OF TRANSMISSION PROJECTS
11 Q.Mr.Dauphinais identifies many risks associated with development of the
12 Transmission Projects,such as cost over-runs,or construction delays,that mayO13adverselyimpacttheireconomics.(Dauphinais Direct,page 2,line 20 -page 3,line
14 7).Mr.Mullins and Staff witness Mr.Richard Keller also express a concern over
15 the risk of cost overruns.(MullinsDirect,page 31,lines 2-14;Keller Direct,page
16 13,lines 16-21).Please describe the Company's experience mitigating these types
17 of transmission project risks.
18 A.In the past five years,the Company has completed two significant and similar Energy
19 Gateway transmission projects:(1)the 100-mile 500/345 kV Mona-to-Oquirrh
20 transmission line;and (2)the 170-mile 345 kV Sigurd-to-Red Butte transmission line.
21 Similar to the Aeolus-to-Bridger/Anticline line,both projects required a NEPA-
22 compliant Environmental Impact Statement,including a Record of Decision,Plan of
23 Development,and Right of Acquisition process.Using its expertise in utility resource
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l development and project management,the Company delivered both the Mona-to-
2 Oquirrh and Sigurd-to-Red Butte transmission lines within the cost estimates used in
3 the CPCN processes and on time.Table 1 below summarizes the actual project
4 performance relative to the CPCN filing information:
TABLE 1
Original CPCN FiHng Informaden
cost
PROJECT REF Data of Applicadon (4 nnn m)In-Serluce COST in-Selvice
MonaOquirrh lITDocket (8·035-54 November 21,2009 $450.00 5/31/2013 $36400 5/31/2013
Sigurd Red Butte UT Docket 12-035-97 September 17,2012 $380.00 6/3Qf2015 $357.80 6/30/2015
5 The Transmission Projects have the same project management team,and the Company
6 developed the budget and schedule in the same manner as these earlier projects.The
7 Company's past experience substantially mitigates construction cost and schedule risk.
8 Q.How confident are you in the cost estimates for the Transmission Projects?
9 A.The Company is confident that it will deliver the Transmission Projects at or below the
10 cost estimates included in this filing,as updated in the supplemental testimony.Since
11 starting the Energy Gateway Program,which includes the Aeolus-to-Bridger/Anticline
12 line,the Company has used a Facilities Definition Document to clearly define and
13 describe the required scope of the project to all parties.The Facilities Definition
14 Document is one of the foundations for the project success described earlier in my
15 testimony.This document was updated prior to developingthe schedule and budgets
16 that were included in the CPCN application.A clear definition of the project scope from
17 the beginning of the project life-cycle brings an increased confidence in the accuracy
18 of forecasts.
19 In addition,as an overall strategy of controlling contract cost and performance,
20 the Company will secure fixed-price,fixed-performance date contracts that will
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l provide liquidated damages for late performance.The Company also uses project
2 management techniques to trend and forecast performance,including earned value
3 analysis,which provides an early notification of potential productivity concerns that
4 can then be addressedbefore becoming a major issue.In fact,the Company anticipates
5 executing contracts for the Aeolus-to-Bridger/Anticline line (which is a substantial
6 portion of the overall Transmission Projects'cost)in early 2018 that will effectively
7 lock-in the cost for that line.Mr.Mullins also claims that the Company's estimated
8 incremental O&M costs for the Transmission Projects is unsupported and the actual
9 O&M may be much higher.The Company has a well-defined maintenance program
10 that includes line and substation inspections,preventative maintenance and corrective
11 maintenance.The Company has extensive experience operating and maintainingboth
12 transmission and distribution assets.Based on the defined maintenance programs andO13theCompany's experience with similar assets,the O&M costs assumed for this project
14 are accurate.
15 Q.Mr.Mullins further claims the Company has a history of under-estimating
16 transmission resource costs and cites the Populus-to-Terminaltransmission line
17 as an example.(Mullins Direct,page 4,lines 10-15).Is Mr.Mullins'
18 characterization of the cost estimates for the Populus-to-Terminalline correct?
19 A.No,Mr.Mullins'testimony on this point is very misleading.Mr.Mullins testifies that
20 the Populus-to-Terminal line was originally estimated to cost $78 million,but was
21 actually constructed for $801 million,implying the Company's estimate was
22 understated by more than $700 million.In fact,when the Company requested a CPCN
23 from the Commission for the Populus-to-Terminal line,its cost estimate was $750
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l million,which was within seven percent of the fmal costs.See In the Matter of the
2 Application ofRocky Mountain Power For a Certificate of Public Convenience and
3 Necessity Authorizing Construction of the Populus-to-Terminal 345 kV Transmission
4 Line Project,Case No.PAC-E-08-03,Order No.30657 at 2 (Oct.10,2008).
5 Q.What is the basis for Mr.Mullins'claim that the Populus-to-Terminalline was
6 originally estimated to cost $78 million?
7 A.Mr.Mullins appears to have relied on a 2006 estimate provided by the Company in one
8 of its commitments stemming from the merger with MidAmerican Energy Holding
9 Company.In the Matter of the Joint Application of MidAmerican Energy Holdings
10 Company (MEHC)and PacifiCorp dba Utah Power &Light Company for an Order
11 Authorizing MEHC to Acquire PacifiCorp,Case No.PAC-E-05-08,Order No.29998
12 at 6 (Mar.14,2006).Mr.Mullins'testimony fails to note,however,that between theO13estimateincludedinthemergercommitmentandtheactualconstructionofthePopulus-
14 to-Terminal line,conditions changed.Most notably,the 2006 merger commitment was
15 a high-level estimate of the cost to construct a 300 MW transmission line,while
16 subsequentdevelopments indicated that a much larger resource was required.Thus,the
17 Populus-to-Terminal line provided700 MW of immediate additionalcapacity and 1400
18 MW of additional future capacity.Mr.Mullins'comparison of the $78 million estimate
19 in the merger commitment to the actual costs of the Populus-to-Terminal line is
20 disingenuous and inapt.
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l Q.Staff witness Mr.Randy Lobb proposes a cap on the construction costs for the
2 Transmission Projects based on the Company's estimates.(Lobb Direct,page 6,
3 lines 15-16).Would the Company accept this condition?
4 A.Yes,in part.As discussed by Company witness Ms.Joelle R.Steward,consistent with
5 the binding ratemaking treatment law in Idaho,the Company agrees to a soft cap based
6 on the cost estimate included in the Company's supplemental filing.If the actual costs
7 are greater than the fmal estimate,the Company agrees it must demonstrate the
8 prudence of the additionalcosts in a subsequent ratemaking proceeding.
9 Q.Mr.Dauphinais specifically argues that the lack of Wyoming Industrial Siting
10 Permit and the lack of a CUP from Carbon County may delay the Transmission
11 Projects.(Dauphinais Direct,page 10,lines 9-12).How do you respond to this
12 concern?O 13 A.The Company understands that the permitting process for transmission is complex,but
14 it is already well on its way to securing all required permits.In my testimony regarding
15 permit status,I note the Company is currently preparing applications for all of the major
16 remaining permits.The permitting schedule sets forth completing the process by the
17 end of2018.To mitigate the risk of permitting delays,this schedule allows some delay
18 without adversely impacting the overall construction schedule.
19 In addition,to further mitigate the risk of potential delays,the Company is
20 actively engaging with stakeholders to inform them of the Transmission Projects and
21 the applicable permit application process.The Company meets with the BLM on a
22 regular basis to review project status,planned or expected deliverables to the BLM and
23 cooperating agencies in relevant areas such as Section 106 consultation,Plan of
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l Development work,and the like.Similarly,the Company has met with the Wyoming
2 Industrial Siting Commission to review the application process and the Company will
3 soon engage with agencies supporting the Industrial Siting Permit to inform those
4 agencies of the project details.Engaging with stakeholders increases the ability to
5 understand local needs,identify appropriate approaches and potential mitigations to
6 successfully complete the permit and approvals process.
7 Q.What about the risk of delay associated with obtaining rights-of-way for the
8 Transmission Projects?
9 A.Although the Company does not intend to complete acquisition of rights-of-way until
10 early 2019,it is confident this timing will not delay the Transmission Projects.The
ll Company has engaged landowners on the projects since 2007 as part of its outreach for
12 the overall Energy Gateway West project.During that time the Company learned a lotO13abouttheconcernsoflandownersandhas,where practical,addressed many of them.
14 In summer 2017,the Company renewed discussions with all landowners about
15 the Transmission Projects.This effort has identified,and continues to identify,
16 additional concerns and questions the Company is committed to resolve to balance the
17 needs of landowners with the project and its schedule.This renewed discussion will,
18 through previous experience,resolve many issues and lead to successful conclusion of
19 negotiations.Because any project will affect landowners in different ways,the effort
20 and time frame of negotiations are individual and will vary from landowner to
21 landowner.When landowners are willing to actively engage in the process,timely
22 resolution is almost always assured.
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l Q.How has the Company evaluated risks with the construction schedule?
2 A.Project risks related to the construction schedule fall broadly into three classifications:
3 (1)restricted access due to environmental constraints;(2)weather restrictions;and (3)
4 late commencement due to late receipt of all permits.
5 To mitigate the potential impacts due to environmental constraints,the
6 Company considered previous project history constructing in areas with similar levels
7 of constraints and built the overall schedule based on this experience.From previous
8 practical experience and the ongoing agency engagements described in my testimony,
9 the Company understands that mitigation techniques,such as supervised or monitored
10 access into environmentally restricted areas,is possible through negotiation and
11 cooperation between respective parties.Additional mitigation plans,such as re-
12 sequencing of work or schedule compression,have also been successfully employedO13onpreviousprojects,with the contractor assuming the risk of occurrence for such items.
14 To mitigate the risk of constraints caused by weather,the schedule is set to
15 minimize construction during the winter and perform additional work in the summer.
16 In 2009,the Company engaged with several qualified and respected construction
17 contractors to analyze the feasibility of the construction program.This informed the
18 Company on the overall approach neededfor the project and has helped the Company
19 develop the project schedule.In addition,the Company is currently negotiating
20 contracts where the construction contractor will assume the risk for weather delays and
21 allow for such delay within their schedule and the guaranteed completion dates within
22 the contract.
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1 Q.What are the primary risks and mitigation measures underway?
2 A.The primary risk in maintaining the critical-path construction schedule for the
3 Transmission Projects is the on-going regulatory review and approval processes
4 currently underway.In particular,it is critical that the Company obtain CPCNs from
5 the WPSC for the Transmission Projects,which are conditioned upon acquisition of all
6 necessaryrights-of-way,with sufficient time to meet this condition.The Company must
7 also obtain the outstanding siting permits by the end of2018.If the Company does not
8 receive conditional CPCNs in early 2018,or siting permits by the end of 2018,it must
9 assess the viability of achieving a year-end 2020 online date before moving forward.
10 To managethe risk of obtainingtimely regulatory reviews and approvals,the Company
11 will secure off-ramps in its EPC contracts,allowing assurance of regulatory approvals
l2 before significant capital commitments or outlays are made.O 13 Q.Is the Company confident that it can manage the construction schedule risk and
14 deliver the Transmission Projects by 2020?
15 A.Yes.To manage construction schedule risk,the Company will structure and manage the
16 Transmission Projects on a firm,date-certain,fixed-price,turnkey contract basis.
17 Construction contractors and equipment suppliers will be held to key construction and
18 delivery milestones and development of compressed schedule mitigation plans,if
19 required.The Company will establish construction contract completion dates and
20 backstop them with guarantees.
21 Q.Does the Company have experience building similar types of projects that require
22 completion by a date certain?
23 A.Yes.The Company has managed multiple major projects that required the work be
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1 completed by a date certain,or similar circumstances where project completion was
2 required to allow a project to tie into an existing system within a short planned-outage
3 window or closely coordinated with delivery of transmission system networkupgrades.
4 Examples of these projects include:(a)Dunlap wind facility;(b)High Plains wind
5 facility;(c)McFadden Ridge I wind facility;(d)Populus-to-Terminal 345 kV
6 transmission line;(e)Sigurd-to-Red Butte transmission line;(f)Mona-to-Oquirrh
7 transmission line;(g)Lake Side 2 combined cycle natural gas facility;(h)Jim Bridger
8 Unit 3 and Jim Bridger Unit 4 selective catalytic reduction systems;(i)Naughton Unit
9 1 and Naughton Unit 2 flue gas desulfurization systems ("FDG");(j)Hunter Unit 1,
10 Hunter Unit 2,Huntington Unit 1,and Huntington Unit 2 pulse jet fabric filters
11 ("PJFF");and (k)Wyodak PJFF,(1)Dave Johnston Unit 3 and Dave Johnston Unit 4
12 PJFF and FGD systems.O 13 Q.If the Transmission Projects aren't fully in-service by December 31,2020,can the
14 new wind projects still qualify for the production tax credit?
15 A.Yes.Assuming the Transmission Projects are not completed by December 31,2020,but
16 otherwise have facilitated synchronization to the transmission grid and commissioning
17 of individual wind turbines in accordance with Internal Revenue Service ("IRS")
18 guidance,the Company would treat a completed and functional wind turbine as being
19 placed in service regardless of any transmission constraints affecting a wind project.In
20 Private Letter Ruling ("PLR")20033403,the IRS ruled that if a wind turbine has all
21 necessary operating permits and licenses,has been synchronized to the power grid,the
22 critical tests for the components of the wind turbine have been completed,the wind
23 turbinehas been placed in the control of the taxpayer by the contractor and the taxpayer
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l has sold electricity that has been produced by the wind turbine,then the wind turbine
2 has been placed in service.This is even if the wind project is not producing
3 transmission-level electricity due to a delay in a transmission project and has not been
4 deemed to be under commercial operation by a regulatory commission.A PLR may not
5 be relied on as precedent by other taxpayers;however,it is indicative of the IRS
6 position on certain matters.
7 ENERGY IMBALANCE MARKET COSTS
8 Q.Mr.Mullins claims the EIM will impose additional costs on the Wind Projects
9 because they will be subject to uninstructed imbalance charges that were not
10 included in the Company's economic analysis.(MullinsDirect,page 28,line 20 -
11 29,line 1).Is this true?
12 A.No.There is no basis to assume that uninstructed imbalance will result in a net costO13and,in fact,the expectation is that over time there will be no net impact associatedwith
14 uninstructed imbalance.
15 Q.What is uninstructed imbalance?
16 A.Uninstructed imbalance in the EIM is assessed when a unit does not follow its
17 scheduled output in the five-minute market.For example,if the dispatch operating
18 target for five minutes was 50 MW and the unit actually produced 55 MW,then there
19 is an uninstructed imbalance of 5 MW.In this example,the 5 MW would be multiplied
20 by the locational marginal price of the unit to determine the uninstructed imbalance
21 assessment.Importantly,however,the assessment can be a charge or a credit because
22 the locational marginal price for a particular unit can be positive or negative.All of the
23 Company's generating units,as well as loads,have uninstructed imbalance.
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l Mr.Mullins is wrong to claim that uninstructed imbalance is somehow a negative
2 outcome that will impose additional costs.
3 Also,as described by Company witness Mr.Chad A.Teply,the wind forecasts
4 that are provided to the Company's economic model are P50 forecasts,which assumed
5 a balanced outcome over periods of times,i.e.,there is a 50 percent probability that
6 wind generation will be more than forecast and a 50 percent probability it will be below
7 forecast.To impute a negative pricing outcome assumes that the times when the unit is
8 under or over performingis somehow biasedtowards periods in which the dollar impact
9 is less favorable,e.g.,always under performs when prices are high or over performs
10 when prices are low (possibly negative).This would imply a bias in the outcome,which
11 is an unreasonable assumption in a forecast for variable energy resources.
12 Finally,because the EIM is such a large,liquid market with renewable resourceO13diversity,it further supports the assumption of a balanced price outcome when a
14 resource or load deviates from a forecast.
15 Q.Mr.Mullins also claims the EIM operates onlyon the ability to transfer power on
16 the firm rights of the Company,and does not allow transfers to occur on another
17 utilities'transmission rights.(MullinsDirect,page 28,lines 13-15).Is this true?
18 A.No.The opposite is true.The ability to use available transmission capability across the
19 Western Interconnect of participating EIM entities and the California Independent
20 System Operator ("CAISO")is the foundationof how benefits are realized in the EIM.
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1 THIRD-PARTY TRANSMISSION REVENUE
2 Q.Mr.Dauphinais also expressed a concern that the Company's forecasted third-
3 party transmission revenue resulting from the Transmission Projects will not
4 materialize because the costs of the Transmission Projects may not be included the
5 Company's OATT rates.(Dauphinais Direct,page 12,lines 17-19).How do you
6 respond to this concern?
7 A.Mr.Dauphinais'concern is unfounded.The Transmission Projects are network
8 transmission assets under the Company's OATT because they will be integrated into
9 the Company's transmission network,available for scheduling by all customers,and
10 provide benefits to the network,such as congestion relief,increased transmission
11 capacity and improved system reliability,among others.Based on these characteristics,
12 I understand that FERC precedent supports rolling the costs of these assets into theO13Company's transmission rates.
14 I also understand that FERC's longstanding open access transmission policies
15 state the cost of network upgrades necessary to accommodate transmission service
16 should be rolled into transmission rates because these types of upgrades are presumed
17 to benefit all network users.The Transmission Projects clearly provide network
18 benefits to all customers that use the transmission system,including third-party
19 transmission system users,while also allowing additional generation to be connected.
20 Q.Does Mr.Dauphinais recognize that FERC precedent generally supports rolling
21 the costs of network transmission facilities into OATT rates?
22 A.Yes.(Dauphinais Direct,page 13,lines 16-17).Mr.Dauphinais cites only one case
23 where a utility was unable to roll a transmission project into its FERC formula rates.
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l Notably,the 1993 case cited by Mr.Dauphinais predates two landmark FERC orders
2 that revamped major federal transmission policies and that still define the federal
3 landscape we operate in today.First,FERC's 1994 transmission pricing policy order
4 essentially marked the beginning of the presumption that any network transmission
5 facility benefits all network users and,thus,the cost of any network facilities should be
6 rolled into transmission rate base and shared among all network users rather than
7 directly allocated to the customer "causing"the need for the new facility.Inquiry
8 Concerning the Commission's Pricing Policyfor Transmission Services Provided by
9 Public Utilities Under the Federal Power Act,59 Fed.Reg.55,031 (Nov.3,1994),
10 FERC Stats.&Regs.¶31,005 46 (1994),order on reconsideration,71 FERC ¶61,195
11 (1995).
12 Second,in 1996,FERC established open access transmission policies,O 13 including the pro forma OATT.Promoting Wholesale Competition Through Open
14 Access Non-discriminatory Transmission Services by Public Utilities;Recovery of
l 5 Stranded Costs by Public Utilities and Transmitting Utilities,Order No.888,61 Fed.
16 Reg.21,540 (May 10,1996),FERC Stats.&Regs.¶31,036 (1996).
17 Q.Has the Company ever had FERC reject a request to roll the costs of a
18 transmission project into its OATT rates?
19 A.No.
20 Q.How will the costs of the Transmission Projects flow into the Company's
21 transmission rates,and who will pay these rates?
22 A.The Company's current transmission formula rate (included in PacifiCorp's OATT)
23 was approved by FERC in Docket No.ER11-3643.PacifiCorp's transmission formula
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l rate is updated annually with the transmission revenue requirement ("ATRR")that
2 representsthe annual total cost of providing firm transmission service over the test year.
3 The ATRR calculation incorporates a return on rate base,income taxes,expenses,and
4 certain revenue credits,among other specific elements and adjustments.Transmission
5 assets,including new transmission capital,are included in the ATRR,weighted by
6 months in service.The ATRR is converted into a rate by dividing ATRR by firm
7 transmission demand.All third-party revenues for transmission service (along with
8 third-party revenues for ancillary services)are included as revenue credits in the
9 calculation of rates in each of PacifiCorp's state retail jurisdictions.
10 Q.Mr.Mullins also claims the Company "simply assumed that 12 percent of the new
11 investment"in the Transmission Projects would be funded by OATT customers.
12 (MullinsDirect,page 30,lines 3-6).Is this true?O 13 A.No.As I explained above,FERC has approved the Company's current formula rate that
14 will include the ATTR of the Transmission Projects once they are in-service,and the
15 Company has gone through the annual update.The 12 percent figure represents the
16 current level of ATRR funded by OATT customers.
17 Q.Does this conclude your rebuttal testimony?
18 A.Yes.
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