20230525Comments.pdf

CHRIS BURDIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone]
IDAHOBARNO.9810
Street Address for Express Mail:
11331 W CHINDEN BLVD,BLDG 8,SUITE 201-A
BOISE,ID 83714
Attorneyfor the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )OF ROCKY MOUNTAIN POWER FOR A )CASE NO.PAC-E-23-01CERTIFICATEOFPUBLICCONVENIENCE)AND NECESSITY AUTHORIZING )COMMENTS OF THECONSTRUCTIONOFTHEBOARDMAN-TO-)COMMISSION STAFFHEMINGWAY500-KV TRANSMISSION )LINE PROJECT )
STAFF OF the Idaho Public Utilities Commission,by and through its Attorneyof
record,Chris Burdin,Deputy Attorney General,submits the followingcomments.
BACKGROUND
On January 27,2023,Rocky Mountain Power,a division of PacifiCorp ("Company"or
"PAC")filed an application ("Application")requesting an order granting a Certificate of Public
Convenienceand Necessity ("CPCN")for Energy Gateway Segment H,the Boardman-to-
Hemingway 500-kilovolt ("kV")transmission line ("B2H"or "Project").The Company will co-
own B2H with Idaho Power Company ("IPC"),which recently filed its own CPCN application
for the Project in Case No.IPC-E-23-01.
On February 8,2023,the Commission issued a Notice of Application and Notice of
Intervention Deadline.Order No.35678.Subsequently,the Idaho Irrigation Pumpers
Association,Inc.and Bayer Corporation petitioned to intervene.On February 24,2023,the
STAFF COMMENTS 1 MAY 25,2023
Commission granted intervention to both parties.Order No.35686.On March 8,2023,the
Commission Secretary issued a Notice of Parties.
The Company represents that B2H is an approximately 300-mile-long,500-kV electric
transmission line that will extend from a switching station constructed near Boardman,Oregon to
the existing Hemingway Substation located in Owyhee County,Idaho.The Company stated that
approximately two hundred and seventy-four (274)miles of the transmission line will be in five
Oregon counties:Malheur,Baker,Union,Umatilla,and Morrow Counties,and a 24-mile
segment of the Project will be in Owyhee County in Idaho.The Company represents that B2H
will also include ten communication stations along the route that are constructed within the right-
of way of the transmission line,and B2H will also include the installation of the B2H Midline
Series Capacitor Project and development of a remedial action scheme.
The Company represents that B2H enables lower-cost and more reliable transmission
service to serve customer load and increases transmission connectivitybetween PacifiCorp East
("PACE")and PaciflCorp West ("PACW")balancing authority areas ("BAA")and will enable
the Company to cost-effectively and reliably serve growing customer load.The Company stated
that these benefits primarily result from cost savings in serving load in central Oregon and near
the proposed Longhorn substation.Application at 9.
The Company represents that B2H is the most cost-effective means of serving the
Company's load,and that without B2H,the Company would be required to acquire higher-cost
generationresources and third-partytransmission service,which together would increase
customer costs by approximately $1.713 billion through 2042.Id
The Company represents that the cost savings are based on an anticipated 2026 in-service
date for B2H.The Company states that to ensure that the Project can be energized in time for a
2026 in-service date,construction must begin in the summer of 2023.The Company requested
that the Commission issue an order on its Application no later than June 30,2023.Id at 9-10.
STAFF ANALYSIS
Staff reviewed the Company's Application and its responses to discovery requests.Based
on the information,Staff believes that the Company needs to increase the capacity of its
transmission system to enable it to meet loads across its east and west balancing areas and the
STAFF COMMENTS 2 MAY 25,2023
proposed B2H project is the least-cost least-risk solution.Therefore,Staff recommends the
following:
1.The Commission should grant a CPCN for the Company to construct the B2H
transmission line but make recovery contingent on approval of all agreements
requiring Commission approval and the Commission's determination of prudence
of actual costs;
2.When the Company files for recovery,it should include evidence of its pursuit of
alternative funding sources for the project;
3.The Commission establish a soft cap for the recoverable value of the project.The
soft cap should be compared to the all-in total B2H costs including non-B2H
expenses that may be incurred if B2H fails to stay on schedule and needs to
mitigate any capacity shortfalls;and
4.The Company should provide a detailed breakdown of the soft cap cost
components in a subsequent compliance filing with input from Commission Staff
on which components to include.
Project Description
The Application describes the B2H project and several other infrastructure project
agreements that are necessary to ensure the full benefits of B2H are realized for each party.
Below is an inclusive list of the various infrastructure projects categorized by agreement type.
The Boardman to Hemingway Transmission Line Project ("B2H")
The primary project seeks to acquire rights of way ("ROW"),and construct
approximately 300 miles of 500-kV transmission lines between Boardman,Oregon and
Hemingway,Idaho.It will also:
Construct or improve access roads for the transmission line;
Construct communication regeneration sites along the transmission line;
Rebuild or remove certain other transmission line segments;
o Remove 12 miles of 69-kV transmission line;
o Rebuild 1.1 miles of 138-kV transmission line;
o Rebuild 0.9 miles of 230-kV transmission line;
STAFF COMMENTS 3 MAY 25,2023
Construct the Longhorn substation;
Upgrade the Hemingway substation;and
Construct the Midline Series Capacitor substation.
The B2H project will be constructed through a partnership between the Company and IPC,in
which the Company will fund and own 55.55 percent,and IPC will fund and own 45.45 percent.
IPC will be responsible for managing the construction.
Central Oregon Agreements
The Company and BPA have negotiateda set of agreements ("Central Oregon
Agreements")that will more effectivelysupport transmission in central Oregon.The major
elements are:
PAC-BPA agreement to revise or establish 15 point-to-point("PTP")
transmission service tables that will,upon B2H energization,provide PAC with
340MW of transmission rights from the north,and 340MW of transmission from
Summerlake,to the central Oregon load;
PAC-BPA agreement for PAC to upgrade the existing Meridian Series Capacitor
at the Meridian substation (or an equivalent series capacitor in the Dixonville-
Meridian-Klamath Falls-Captain Jack lines);and
PAC-BPA agreement to provide BPA 1000 MW of bi-directional capacity in the
Summerlake -Malin Line.
Asset Exchanges
The Company and IPC have agreed to a collection of futureasset exchanges and
construction projects ("Asset Exchanges"),designed to be implemented if B2H is energized.
The proposed Asset Exchanges are:
IPC will transfer to the Company transmission assets between Midpoint and
Borah for 300 MW west-to-east capacity;
IPC will transfer to the Company transmission assets between Borah and
Hemingway for 600 MW east-to-west capacity;
The Company will transfer to IPC transmission assets between Populus and Four
Corners for 200 MW of bi-directional capacity;
STAFF COMMENTS 4 MAY 25,2023
The Company will transfer to IPC transmission assets in the Goshen area;
IPC will construct the Midpoint500/345-kV transformer project;and
IPC will construct the Kinport-Midpoint 345-kV series capacitor project.
Miscellaneous Agreements
Miscellaneous other agreements between the three entities will go into effect at various
times:
BPA will transfer to the Company two 100 MW PTP Transmission Service
Agreements ("TSA(s)")it has with IPC;
IPC will buy out BPA's 24 percent ownership share of B2H,increasing IPC's
ownership and funding responsibility to 45 percent.IPC will also reimburse BPA
for its share of the permitting expenses incurred over the last decade.
In return for IPC's buyout,BPA will commit to purchasing long term TSAs from
IPC to deliver power to BPA's customers in southeastern Idaho;and
IPC and BPA will establish a 500 MW PTP TSA from the Mid-Columbia ("Mid-
C")market hub to the proposed Longhorn substation.
CPCN
Summary of Staff's CPCN Recommendations
The Company must increase the capacity of its transmission system to enable it to meet
its increasing loads across its east and west balancing areas,and B2H is the least-cost solution to
resolve it.Therefore,Staff recommends that the Commission grant a CPCN for the Company to
construct the B2H transmission line.Staff also recommends that the Commission clarify that the
CPCN does not include the other agreements described in the Application,and those other
agreements should be submitted for separate approval if and when appropriate.Finally,Staff
recommends that when the Company does file for recovery of actual cost,it should include
evidence of its pursuit of government fundingsources for the project.
STAFF COMMENTS 5 MAY 25,2023
Company's CPCN Request
Review ofIdaho Codes §61-526 and §61-528
For authorityto construct or extend a transmission line,Idaho Code §61-526 requires the
Company to obtain "from the Commission a certificate that the present or future public
convenience and necessity require."Additionally,the Company must show "the fmancial ability
and good faith...andnecessity of additional service in the community."Idaho Code §61-528.
Staff believes the Company has repeatedly demonstrated its financial ability to obtain capital for
a project of this scale.Staff also accepts the Company's assertion that the financial investment
for the B2H project will not impair its ability to provide safe and reliable electricity service at
reasonable rates.The Company has provided safe and reliable service to its approximately
88,000 Idaho customers,along with its customers in five other states.
Assessment ofSystem Need
The Company anticipates up to 340 MW of incremental load growth in central Oregon,
and additional load growth in the Longhorn area,both being within its western BAA.The
Company has surplus generation capacity in its eastern BAA but insufficient transmission
capacity to reliably deliver the power to western loads.Staff was unable to independently
confirm the specific load growth in the Company's 2021 IRP because the IRP considers the
larger PACW BAA and doesn't provide granularityfor specific regional loads.Response
Production Request No.8.However,the 2021 IRP shows an overall PACW resource capacity
deficit in 2026,with shortfalls of 1,105 MW in the summer and 1,301 MW in the winter.2021
IRP Volume 1 at 154 and 156,Case No.PAC-E-21-19.
Additionally,the Company explained the nature of the incremental growth in its
testimony and in its responses to Staff production requests.The Company also provided a
confidential joint planning study ("Study"),in which it addressed the incremental central Oregon
load.Both the testimony and the 2021 IRP affirm that the existing transmission infrastructure is
inadequate to serve the additional load in PACW.Based on these documents,Staff believes that
the Company's assertion of need is reasonable.
STAFF COMMENTS 6 MAY 25,2023
Scope of CPCN
The Application describes several agreements,but not all of them are part of the
Company's request for a CPCN.The Company clarified the specific actions for which it seeks
the CPCN.See Response to Staff's Production Request No.1.The actions specific to the
Company's CPCN request in this filing are identified in the Project Description section above,
under the Boardman to Hemingway Transmission Line Project heading.The Company is not
seeking a CPCN for the Central Oregon Agreements,the Asset Exchanges,or the other
miscellaneous agreements.
Staff recommends that the Commission state that CPCN approval does not implicitly
approve the other agreements,such as the Asset Exchanges,and the Company should file
applications for Commission approval when appropriate.
B2H as a Solution
B2H Meets the System Needs
The Company expects to obtain from B2H 300 MW of west-to-east transmission capacity
and 818 MW of east-to-west transmission capacity,which will help the Company serve its
customer load across both BAAs.
Staff's analysis identified that the effectiveness of B2H will depend on the successful
construction of the B2H transmission line,and on other agreements that are external to the
transmission line.For the Company,the Asset Exchanges and the Central Oregon Agreements
are also essential to meet the system need.
The Asset Exchanges are necessary to provide additional transmission capacity to the
Company from its PACE BAA to the Hemingway terminus of B2H.The Central Oregon
Agreements are necessary to provide additional transmission capacity from the Boardman
terminus of B2H to the central Oregon load.
Staff discusses the risks associated with these issues in the Project Risks and Other Risks
sections below.
Assuming the project and the related actions are completed,Staff concludes that B2H
will resolve the system need.However,given that additional agreements will require separate
Commission approval,Staff recommends granting approval of the CPCN but make recovery
contingent on the Commission's approval of those additional agreements.
STAFF COMMENTS 7 MAY 25,2023
B2H is Cost Reasonable
Staff reviewed the cost of B2H against the next least-cost alternative to assess the
decisional prudence of the project.From this review,Staff believes that selecting the B2H
project was a prudent decision.For operational prudence,Staff will review the actual project
costs once the Company files a subsequent case seeking recovery.
The Company provided extensivemodeling and cost analysis using its PLEXOS model
through its 2021 IRP process.See Case No.PAC-E-21-19.The PLEXOS model is used to
optimize resources and transmission lines that the Company will use to serve its customers.The
PLEXOS model,under several alternative futures,showed the portfolio with B2H transmission
line as the least-cost and least-risk preferred portfolio."In the 2021 IRP,B2H was projected to
result in $453 million in risk-adjusted net benefits....Similarly,the 2021 IRP Update projected
risk-adjusted net benefits of $439 million...."Link Direct at 3.After the 2021 IRP Update,
several key changes occurred,and the Company now projects risk-adjusted net benefits of
$1.713 billion.The bulk of the benefit is derived by avoiding the cost of constructing a new
solar and eight-hour storage2 facility to serve the central Oregon load.
The Company also believes,and Staff agrees,that B2H will provide "lower-cost and
more reliable transmission service"to its customers.Application at 2.Company Witness Link
described that with B2H in-service,the Company would reduce its third-partywheeling expenses
and those cost savings would be attributed to the Company's retail customers.Link Direct at 25.
Staff reviewed the Company's cost estimate and verified that the Company provided sufficient
justification for the B2H transmission line as the least-cost least-risk option.
Separately,Staff is concerned that the Company has not pursued alternative funding,such
as grants that could potentiallyreduce the impact to ratepayers.Staff recommends that when the
Company seeks recovery of costs for the B2H project,that it provides evidence of conducting
investigations,analyses,and/or applications for grants or alternative funding from federal,state,
or local agencies.
I Decisional prudence is a determination that the "decision"to move forwardwith an investment is based on needandinthiscaseistheleastcostalternative.Operational Prudence is a determination that the Company implementedtheinvestmentinaleast-cost manner.
2 The 2021 IRP and 2021 IRP Update both identified4-hour battery storage duration;however,the Companyupgradeditto8-hour battery storage duration in this filing.Link Direct at 26.
STAFF COMMENTS 8 MAY 25,2023
Project Risks
Staff recommends that the Commission establish a soft cap as reflected in response to
Production Request No.3(b)and as shown in Confidential Staff Attachment A for the
recoverable cost of constructing the project.The total cost of the project plus any additional cost
necessary to meet load if the project fails to stay on schedule should be part of the all-in total
B2H costs that will be compared to the established soft cap.The soft cap should be the threshold
that will require the Company to provide robust justification for construction costs over the cap
to receive recovery.
Because of the complexityand amount of uncertainty associated with the B2H
transmission project,the Company faces significant risks throughoutthe entire project life cycle
that may ultimatelyimpact customers.Staff categorized the risks into three types:project
capability risk,project schedule risk,and project cost risk.In the followingsections,Staff
discusses the three types of risk,recommends mitigations for each type,explains each risk issue,
and provides the latest status for each.Table No.1 summarizes the three types of project risk
and the key issues contributing to them.
Table No.1:Project Risks
Capability Risks Schedule Risks Cost Risks
Longhorn Substation:Longhorn Substation:Longhorn¯Substation:
B2H will be unusable without The permitting process is in The cost of an alternative is
this interconnection.progress and the construction unknown.
timeline is unknown.
ROW Acquisitions:ROW Acquisitions:ROW Acquisitions:B2H cannot be built without ROW delays might delay ROW negotiations have thetheROW(s).construction,especially if legal potential to increase costs.
action becomes necessary.
Boardman-Ione ("B-I")B-I Alternate Transmission Path:B-I Alternate TransmissionAlternateTransmissionPath:An alternate line is in the early Path:B2H cannot be completed stages of permitting,followed by The alternatepath and cost arewithoutrelocatingthisline.construction of the line,then not certain,and environmentaldemolitionoftheoldline.mitigation may be required.
Supply Chain:Inflation:Substantial delays exist for key High inflation persists,project materials.especially for key project
materials.
Outstanding Permits:
Various project permits are
outstanding,and delays are typical.
STAFF COMMENTS 9 MAY 25,2023
Project Capability Risk
Project capability risk is the risk that an essential part of the project cannot be completed,
thereby preventing completion of the overall project.For example,the B2H line terminates in
Boardman,but a third party (BPA)must construct the Longhorn substation to interconnect it to
the existing transmission grid.Without proper interconnection,B2H will not be usable.
Staff identified three capability risk issues for B2H:
1.The Longhorn substation;
2.Acquisition of the ROWs to construct B2H;and
3.Establishment of an alternate transmission path for BPA's B-I line.
The Project Risk Issue section explains each of these in more detail.
Althoughany of these issues (or other unforeseen ones)could prevent the successful
completion of B2H,Staff assumes that the Company will find a workaround to complete the
project and make it useful.Staff concludes that these capability risks may translate into
increased project costs and/or schedule growth.Therefore,Staff makes no recommendation for
capability risk,but will provide recommendations to mitigate schedule and cost risk,which Staff
discusses in the followingsections.
Project Schedule Risk
Staff identified five risk issues that have potential to delay the overall project schedule:
1.The Longhorn substation;
2.ROW acquisitions for B2H;
3.The B-I alternate transmission path;
4.Supply chain delays;and
5.Outstanding permits.
The Project Risk Issue section explains each of these in more detail.
Schedule delays manifest as cost risk to ratepayers.The current planned in-service date
for B2H is June 1,2026.If B2H is not online at that time,the Company may need to incur
additional expenses outside of B2H to provide additional capacity for the central Oregon load
growth.Staff recommends that if circumstances delay the project beyond the planned in-service
date,the Commission should require the Company to track and report any expenses incurred
outside of B2H to cover central Oregon capacity deficits until B2H is online.These expenses
STAFF COMMENTS 10 MAY 25,2023
should be part of the all-in total B2H costs compared to the soft cap limit recommended in the
Project Cost Risk section.
Project Cost Risk
Staff identified four cost risk issues that have potential to drive the project cost beyond
the current estimate:
1.The Longhorn substation;
2.ROW acquisitions;
3.The B-I alternate transmission path;and
4.Inflation.
The Project Risk Issue section explains each of these in more detail.
Project cost overruns represent a direct risk to ratepayers,who will be asked to recover
the full cost.The Company has retained experienced engineering firms to refine the project
estimate and has shown due diligence in responsibly estimating the project cost.The Company
has also established cost control policies,in cooperation with IPC,to provide reasonable
oversight of the project costs.
However,to further protect customers,Staff recommends that the Commission place a
soft cap on the project in accordance with the Application estimate.If the final project cost
exceeds the soft cap,the Company should provide convincing evidence of its efforts to remain
within the cap,the reasons it had to exceed the cap,and justify any overages at the time recovery
is requested.
Quantifyingthe cost of a complex project like B2H requires careful attention to many
details.Items that must be specified include the date of the estimate,major construction features,
contingency markups,shared and unshared costs between partners,financing costs,and taxes.
Staff requested that the Company provide a detailed breakdown of these costs in Production
Request No.3,but the Company only provided the bottom line total,sub-divided into direct and
overhead costs.Staff recommends that the Commission use the Company's bottom line total
estimate as the soft cap for any future recovery.Staff also recommends that the Commission
require the Company to provide a detailed breakdown of the cost components in a subsequent
compliance filing.This detailed breakdown will provide benchmarks to assist Staff and the
STAFF COMMENTS 11 MAY 25,2023
Company in any future cost recovery filing.The Company should consult with Staff to
determine an appropriate level of cost component breakdown.
Project Risk Issues
Staff performed an analysis of the types of risks described above for specific risk issues
associated with the construction of the B2H project.The results of Staff's analysis are described
below for each specific risk issue.
LonghornSubstation
The northern terminus of B2H must have the Longhorn substation constructed to connect
to the existing transmission network.Without this substation,the transmission path would be
incomplete,and the project would not be useful.In short,the Longhorn substation is a critical
component of B2H.BPA owns the land for the Longhorn Substation and intends to construct,
own,and operate the substation.The substation will have other terminals,one of which is in
progress to provide interconnection services for Umatilla Electric Cooperative ("UEC").3 Based
on Staff s analysis described below,Staff believes that the capability,schedule,and cost risks
associated with the Longhorn substation are all low.
Staff believes the Company has no realistic alternative to the Longhorn substation.Staff
asked the Company to describe its contingency plan if BPA is unable to complete its
responsibilities.The Company stated,"At this time,there are no contingenciesthat would
provide for connecting the line into BPA's 500 kV transmission system."Response to
Production Request No.7.
Despite the lack of a contingency plan,Staff believes the risk of BPA not buildingthe
substation is low because the substation is critically important to BPA,the Company,IPC,and
UEC.Furthermore,BPA owns the land,has completed the environmental review process,and
has therefore resolved two major problem areas.Funding for the substation has been built into
the overall B2H cost,includinga 20 percent contingency.
ROW Acquisitions
The Company has already obtained ROWs across federal and state property,which
eliminates much of the risk associated with the project.However,the Company must still
3 The Umatilla Electric Cooperative serves a portion of the Columbia Basin and Blue Mountain county inNortheasternOregon.
STAFF COMMENTS 12 MAY 25,2023
acquire many private easements,so significant risks remain relating to costs and scheduling.The
Company has estimated the fair market value of the remaining ROWs,added a contingency,and
built that into the project budget.Each landowner must be persuaded to grant an easement for a
fair price.For each landowner that cannot be persuaded,the Company will have to balance
between offering more money (cost risk)or pursuing a legal remedy (schedule risk).Staff
believes that both cost and schedule risks are significant for this issue.However,Staff believes
that this case pairs well with the statutory framework of the Company's condemnation rights.
Staff believes that this can serve as a backstop to reduce these risks.See Idaho Code §7-71lA.
Boardman to Ione Alternate Transmission Path
Currently,the 69-kV B-I transmission line crosses U.S Navy property in Umatilla
County,Oregon.The B2H transmission line must be constructed across a portion of the B-I
path.BPA has agreed to remove the interfering segment,but before the B-I segment can be
removed,BPA must construct an alternative transmission path to serve its Columbia Basin load.
This creates significant cost and schedule risk for the Company.
The Company and IPC executed an agreement with BPA on March 18,2020,to pay BPA
for its costs associated with removing the B-I line and building the new path.BPA must
construct and energize the alternate transmission path by Spring of 2025,to allow time to remove
the old line and finish B2H by Spring of 2026.
Currently,BPA is performing environmental studies of the proposed alternate path so
potential environmental issues or mitigation to resolve them are not yet known.The Company
has included an approximate cost estimate for this work in its overall B2H budget,but the final
project scope is yet to be determined.
Supply Chain
Staff believes the current supply chain problems add significant schedule risk to the
project.Staff has received reports from utility companies that the purchase lead time for
transformers has grown from a few months to 24 to 36 months.Likewise,the purchase lead time
for electric meters has grown from 8 weeks to 52 weeks.Similar situations exist for other
components.Althoughnational efforts are being directed to alleviate some of these issues,the
risk of schedule delay due to supply chain problems is significant.
STAFF COMMENTS 13 MAY 25,2023
lnflation
Staff believes that persistent inflation adds significant cost risk to the project.The
Company mitigated inflation risk by hiring experienced transmission engineers to update the cost
estimates reflecting the most current prices as of January 2023,and then adding 20 percent
contingency to account for the uncertainty of inflation.However,Staff has received recent
reports from utility companies with evidence that certain electrical components such as
transformers,switch gear,and electric cabling have increased in price by as much as 80 percent
over the last year.Even with the 20 percent contingency,the Company's fmal project cost may
be underestimated.
The Company has additional cost risk because it does not have direct control of
construction oversight,having delegated the construction management to IPC.However,The
Construction Funding Agreement defines the Company's and IPC's roles and responsibilities in
construction of the B2H project.Application,Exhibit No.1 at 24-29.This agreement,in
conjunction with the Construction Funding Committee,should provide sufficient oversight
capability to manage the project cost.
Outstanding Permits
The primary risk from an outstandingpermit is schedule delay.The Company has spent
years obtaining the most difficult project permits,but several routine permits and permits out of
the Company's control are still outstanding.
The environmental review is not complete for the new B-I substation,and the engineering
studies are incomplete for the Longhorn substation.These requirements are the responsibility of
BPA and are outside of the Company's control.In addition,environmental reviews are
frequentlyused by opponents to block federal actions.These reasons lead Staff to believe that
schedule risk for all outstanding permits is at a moderate level.
Other Risks
In addition to the risks associated with the construction of the project,Staff identified and
analyzed several other risks that are external to the construction of the project but may result in
unrealized benefits after the project is put into operation.However,Staff believes its analysis of
STAFF COMMENTS 14 MAY 25,2023
these costs and benefits from the project supports the CPCN when comparing it to the costs and
benefits of the next best alternative.
Asset Exchanges
The Company's primary purpose for B2H is to obtain a robust transmission corridor to
better connect the PACW and PACE BAAs.B2H will provide most of the benefits to the
Company's system,but without the Asset Exchanges between the Company and IPC listed in the
Project Description section,the full extent of the project benefits to the Company will be
limited,posing a risk if the exchanges do not occur.
These Asset Exchanges require Commission approval under Idaho Code §61-328.The
Company and IPC have mitigated this risk by signing an agreement to execute these exchanges;
however,these agreements are contingent on obtaining Commission approval.Under the statute,
the remaining risk of obtaining Commission approval is if the value of the assets being
exchanged is not comparable.This issue will need to be resolved when the two companies file
for authorization from the Commission.Given the current signed agreement between the
Company and IPC,Staff believes the risk in completing the Asset Exchanges is low.However,
Staff recommends that recovery for the cost of the project be contingent on both the Company
and IPC obtaining Commission approval of these exchanges.
Central Oregon Agreements
The major components of Central Oregon Agreements are described in the Project
Description section.This set of agreements is necessary for the Company to deliver power via
B2H to central Oregon load.Without modifying the PTP agreements,the transmission path to
central Oregon would still be constrained,and the usefulness of B2H to the Company would be
reduced.This risk rests primarily on the Company since reduced usefulness would reduce its
basis for cost recovery.
Staff believes the risk of this issue is low since the Company and BPA have signed the
agreements.However,there are remaining risks given contingencies contained in the
agreements,especially the need for FERC approval,which is outside of the Company's control.
STAFF COMMENTS 15 MAY 25,2023
Customer Notice and Public Comments
A telephonic Customer Workshop for Rocky Mountain Power's application was held on
Wednesday,April 19,2023.Customer participation was minimal.As of Thursday,May 25,
2023,there has been one (1)Customer Comment received,which was in support of this case.
STAFF RECOMMENDATIONS
Staff recommends that the Commission:
1.Issue an order granting a CPCN for the construction of the B2H project but make
recovery contingent on the Commission's approval of all Asset Exchanges and a
determination of the prudence of actual cost when the project is complete;
2.Direct that when the Company does file for recovery,it should include evidence of its
pursuit of alternative funding sources for the project;
3.Establish a soft cap for the recoverable value of the project as discussed above;and
4.Require the Company to provide a detailed breakdown of the soft cap cost
components in a subsequent compliance filing with input from Commission Staff on
the components to include.
Respectfully submitted this day of May 2023.
Chris Burdin
Deputy AttorneyGeneral
Technical Staff:Matt Suess
Jolene Bossard
Jon Kruck
Kevin Keyt
Kimberly Loskot
i:umisc/comments/pace23.1cbmsjkjbkikkcomments
STAFF COMMENTS 16 MAY 25,2023
ATTACHMENT A
IS CONFIDENTIAL
AND PROTECTED
UNDER THE
PROTE CTIVE
AGREEMENT
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 25th DAY OF MAY 2023,SERVEDTHEFOREGOINGCOMMENTSOFTHECOMMISSIONSTAFFTO,IN CASENO.PAC-E-23-01,BY E-MAILING A COPY THEREOF,TO THE FOLLOWING:
MARK ALDER JOHN HUTCHINGSROCKYMOUNTAINPOWERCARLASCARSELLA1407WESTNORTHTEMPLESTE330ROCKYMOUNTAIN POWERSALTLAKECITYUT841161407WESTNORTHTEMPLE STE 330E-MAIL:[e-mail] SALT LAKE CITY UT 84116E-MAIL:[e-mail]
[e-mail]
DATA REQUEST RESPONSE CENTER KATHERINE McDOWELLE-MAIL ONLY:ADAM [e-mail] McDOWELL RACKNER GIBSON
419 SW 11TH AVE STE 400PORTLANDOR97205
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