20230523Comments.pdf

MICHAEL DUVAL
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone]
IDAHO BARNO.11714
Street Address for Express Mail:
11331 W CHINDEN BLVD,BLDG 8,SUITE 201-A
BOISE,ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )COMPANY'S APPLICATION FOR A )CASE NO.IPC-E-23-01
CERTIFICATE OF PUBLIC )CONVENIENCE AND NECESSITY FOR )THE BOARDMAN TO HEMINGWAY 500-)COMMENTS OF THE
KV TRANSMISSION LINE )COMMISSION STAFF
STAFF OF the Idaho Public Utilities Commission,by and through its Attorney of
record,Michael Duval,Deputy Attorney General,submit the followingcomments.
BACKGROUND
On January 9,2023,Idaho Power Company ("Company")applied for an order granting a
Certificate of Public Convenience and Necessity for the purpose of constructing "a 300-mile
long,overhead 500-kV high voltage line"("Application").Application at 1.This line would
extend between the proposed Longhorn Substation near Boardman,Oregon,and the Hemingway
Substation in southwest Idaho ("B2H").The Company asserted the transmission line is crucial
to meeting a 2026 capacity deficit and therefore construction must begin in the summer of 2023.
It requested a final order be issued by June 30,2023.
STAFF COMMENTS 1 MAY 23,2023
The Company identified B2H as a cost-effective resource in the Company's Integrated
Resource Plans ("IRPs")since 2009.The Company further stated that B2H is "the lowest-cost
alternative to serve Idaho Power's customers in Idaho and Oregon."Id.at 4.
The Company stated that the existing Boise to McNary line was insufficient to
accommodate the expanded transmission that the Company expects.The Company stated that
the B2H line would add neededcapacity to the Idaho/Northwestpath.Specifically,the
Company stated that the line would add "1,050 megawatts ("MW")of capacity in the west-to-
east direction"and "1,000 MW of capacity in the east-to-west"direction.Id.at 7.The
Company stated that B2H would thus facilitate synergy between Bonneville Power
Administration's ("BPA")winter focused capacity needs and Idaho Power's summer focused
capacity needs.Id.at 12.
The Company asserted that it conducted various forms of community outreach to
inform-and seek feedback from-those who will be affected by the Company's proposed
project.The Company asserted that it collectively held dozens of diverse types of meetings,and
that nearly 1,000 people attended them.The Company stated that this outreach helped inform
the proposed B2H route.
The Company asserted that the Bureau of Land Management ("BLM")granted a right-of-
way necessary to construct and maintain B2H on BLM land.
The Company stated that its original ownership share was 21.21%of B2H;BPA's
original ownership share was 24.24%;and PacifiCorp's ("PAC")original ownership share was
54.55%.Idaho Power represents that it and BPA have agreed that "Idaho Power will increase its
B2H project ownership from 21.21[%]to 45.45[%]by acquiring BPA's B2H project capacity."
Id.Idaho Power stated that in January of2023 the parties "conclude[ed]negotiations on final
agreements that memorialize and effectuate the changes in ownership."'Id.Additionally,Idaho
Power has entered into an agreement with PacifiCorp that there will be undivided ownership of
certain assets on B2H.
I Idaho Power and BPA have agreed that the parties will take the next steps in executing these agreements after
BPA's public outreach process is complete in approximately March of 2023.Idaho Power will compensate BPA for
BPA's permitting interest and the costs that BPA expended to get those permits;Idaho Power will also take on
BPA's obligation to fund 24.24%of the B2H line.Idaho Power will pay for the value of BPA's permitting costs
over time.After these agreements have been executed and BPA's ownership interest has been acquired by Idaho
Power,Idaho Power would then use the B2H line to provide transmission service to BPA's customers.Direct
Testimony of Jared L.Ellsworth,8-15;See Application at 12-13.
STAFF COMMENTS 2 MAY 23,2023
The Company estimated that its most cost-effective portfolio without B2H is still
approximately $266 million more expensive than the Company's preferred portfolio (which
includes B2H).
The Company asserted that it would pay for its share of B2H through a "combination of
available cash and operating cash flow,available facilities and borrowing and debt issuances,
and potential future equity issuances."Id.at 16.
The Company requested that the Commission find that Idaho Power has met the
requirements of Idaho Code §61-526 and issue an order granting a CPCN to construct the B2H
line to meet the identified capacity deficiency in 2026.The Company asserted that it will make a
future filing to address the cost recovery associated with B2H.
On February 1,2023,the Commission issued a Notice of Application and Notice of
InterventionDeadline.Order No.35674.The Idaho Irrigation Pumpers Association,Inc.,Idaho
Industrial Customers of Idaho Power,City of Boise City,Micron Technology,Inc.,and Idaho
Conservation League intervened.Order Nos.35685 and 35695.
STAFF ANALYSIS
Staff reviewed the Company's Application and its responses to discovery requests.Based
on the information,Staff believes that a significant capacity deficit exists and that unless action
is taken,the deficit could affect reliability in 2026.Staff believes that the Company's proposed
B2H project is a least-cost least risk solution that will resolve the 2026 capacity deficit.
Therefore,Staff recommends that:
1.The Commission 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 cost when the project is complete;
2.When the Company files for recovery,it should include evidence of its pursuit of
alternative funding sources for the project;and
3.The Commission establish a soft cap for the recoverable value of the project,and
that the soft cap should include non-B2H expenses that may be incurred if B2H
fails to stay on schedule and needs to mitigate any capacity shortfalls.
STAFF COMMENTS 3 MAY 23,2023
Project Description
The Application describes not only the B2H project,but also several other infrastructure
project agreements that are necessaryto 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 B2H Transmission Line Project
The primary project seeks to acquire rights of way ("ROW"),and construct
approximately300 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;
Construct the Longhorn substation;
Upgrade the Hemingway substation;and
Construct the Midline Series Capacitor substation.
The B2H project will be constructed by a partnership between the Company and PAC,in
which the Company will eventuallyfund and own 45.45%,and PAC will fund and own 55.55%.
The Company will be responsible for managing the construction.
Buyout of BPA
The Company will assume BPA's 24%ownership share of B2H and fund the additional
24%of the construction and operating expenses ("Ownership Buyout").
The Company will reimburse BPA for its share of the permitting expenses incurred over
the last decade.This involves a complicated agreement designed to minimize financial risk to
the Company's ratepayers ("Permit Buyout").
STAFF COMMENTS 4 MAY 23,2023
In return for the Company's Ownership Buyout and Permit Buyout,BPA will commit to
purchasing long term Transmission Service Agreements ("TSA")from the Company to deliver
power to BPA's customers in southeastern Idaho.
Asset Exchanges
The Company and PAC have agreed to a collection of future asset exchanges and
construction projects ("Asset Exchanges")between them,designed to be implemented if B2H is
energized.The proposed Asset Exchanges are:
The Company will transfer to PAC transmission assets between Midpoint and
Borah for 300 MW west-to-east capacity;
The Company will transfer to PAC transmission assets between Borah and
Hemingway for 600 MW east-to-west capacity;
PAC will transfer to the Company transmission assets between Populus and Four
Corners for 200 MW of bi-directional capacity;
PAC will transfer to the Company transmission assets in the Goshen area;
The Company will construct the Midpoint 500/345-kV transformer project;and
The Company will construct the Kinport-Midpoint 345-kV series capacitor
project.
Miscellaneous Agreements
Miscellaneous other agreements between the three entities will go into effect in
conjunction with energizing B2H as listed below.
The Company and BPA will establish a 500 MW point-to-point ("PTP")TSA
from the Mid-Columbia ("Mid-C")market hub to the proposed Longhorn
substation.This will complete the Company's transmission corridor to the Mid-C
market hub;
BPA will transfer to PAC two 100 MW PTP TSAs it has with the Company;and
BPA and PAC will revise multiple transmission agreements and upgrade
infrastructure in the Central Oregon region to establish more efficient delivery
corridors for PAC ("Central Oregon Agreements").
STAFF COMMENTS 5 MAY 23,2023
CPCN
Summary of Staff's CPCN Recommendations
The Company has shown,and Staff agrees,that there is an expected capacity dencit in
2026 and that 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 when appropriate.Finally,Staff recommends that when the Company does file for
recovery of actual cost,it include evidence of its pursuit of government funding sources for the
project.
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...and necessity of additional service in the community."Idaho Code §61-528 -
Certificate of Convenience and Necessity -Conditions.
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 fmancial
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 Idaho
customers since 1915.
Assessment ofSystem Need
In evaluating the need for additional resources,Staff reviewed the Company's Load and
Resource Balance ("L&RB")and the Company's forecasted capacity deficiencies.The
Company developed the L&RB as part of the 2021 IRP (Case No.IPC-E-21-43).The L&RB
shows that the Company has been resource capacity deficient during the peak summer months
since 2021,and those deficits are projected to fluctuate through 2025.In 2026,the Company
STAFF COMMENTS 6 MAY 23,2023
forecasts a larger capacity deficit of 560 MW,2 RD ÎDCTORSeof249 MW from the deficit in 2025.
Factors driving the deficit spike are customer load growth and planned exits from coal
generation.
The Company's Witness,Jared Ellsworth,("Ellsworth")detailed how the Company's
existing transmission lines connecting the Company to the Pacific Northwest are being fully
utilized;therefore,they cannot be used to import additional power to satisfy the deficit.
Ellsworth Direct at 31.
Staffattempted to update the L&RB to reflect conditions in 2023,but doing so required a
full-scale forecast and modeling effort equivalent to the 2023 IRP.Staffrequested the Company
provide this information,and the Company asserted that the "...preliminaryresults maintain the
need for B2H in 2026...."See Response to Staff Production Request No.47.However,the
Company also filed a petition,Case No.IPC-E-23-17,to delay filing the 2023 IRP until the last
business day of September to allow for more opportunity for IRP modeling and stakeholder
feedback.
Instead,Staff relied primarily on its review of the 2021 L&RB and a partial projection of
2023 changes.As a result,Staff concludes that a capacity deficit exists,and it will grow by
approximately250 MW in 2026.Staff afBrmed the need for additional summer capacity
resources.
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.6.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 BPA Buyout,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.Instead,the Company should file
applications for Commission approval of the other agreements,as appropriate.
2 See Case No.IPC-E-21-43.Appendix C:Technical Report at 23.
STAFF COMMENTS 7 MAY 23,2023
B2H as a Solution
B2HMeets the System Need
As asserted in the Company's 2021 IRP,the Company will have a larger capacity deficit
starting in 2026.By adding 500 MW of west-to-east transmission capacity from the Mid-C
market -along with a few smaller projects in 2024 and 2025 -the IRP modeling shows the
capacity deficit will be resolved.Of the total B2H capacity,the Company expects B2H to
provide 750 MW of west-to-east capacity and 182 MW of east-to-west capacity while PAC
expects to receive 300 MW west-to-east capacity and 818 MW east-to-west capacity.
Staff's analysis revealed that the effectiveness of B2H will depend on the Longhorn
substation being constructed,and the establishment of a TSA with BPA to the Mid-C market hub.
Staff also noted the importance of sufEcient energy being available for sale in the Mid-C market.
Staffhas discussed the risks associated with these issues in the Project Risk and Other
Risk sections below,but believes the risks are reasonable.Therefore,Staff concludes that B2H
will sufEciently resolve the 2026 capacity deficit enabling the Company to continue providing
reliable and cost-effective service to its customers.However,given that the Asset Exchanges
require Commission approval and are critical for overall project implementation,Staff
recommends granting approval of the CPCN but make recovery contingent on the Commission's
approval of these agreements and its determination of prudence of actual cost when the project is
complete.
B2H is Cost Reasonable
Staffreviewed the cost of B2H against the next least-cost alternative to assess the
decisional prudence of the project.From this review,Staff believes that the B2H project is a
prudent decision.For operational prudence,Staff will review the actual project costs once the
Company files a subsequent case seeking recovery.3
The Company extensivelymodeled and analyzed costs using AURORA during the 2021
IRP process,establishing that B2H was part of the least-cost portfolio at that point in time.
3 Decisional prudence is a determination that the "decision"to move forward with an investment is based on need
and in this case is the least coat alternative.Operational Prudence is a determination that the Company implemented
the investment in a least-cost manner.
STAFF COMMENTS 8 MAY 23,2023
Ellsworth explained how increased inflation,supply chain issues,and inclusion of contingency
costs increased the B2H cost estimate between the 202l IRP and filing the Application.
Ellsworth Direct at 55.The Company updated its cost analysis by updating its estimate for B2H,
and then recalculating the Net Present Value ("NPV")of the 2021 preferred portfolio.Even with
the significantly higher estimate for B2H,the portfolio with B2H is approximately$228 million
less than the least-cost non-B2H portfolio.Staff reviewed the Company's analysis and agrees
that B2H is a significant part of the least-cost resource portfolio.In other words,Staffbelieves
that B2H is cost reasonable.
Given the high electric market prices over recent years,Staff explored how high market
prices might change the cost of the B2H portfolio.This issue is further discussed in the Other
Risks section below.
Separately,Staff is concerned that the Company has not pursued alternative funding,such
as grants,which could potentially reduce the cost 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.
Project Risks
Staff recommends that the Commission establish a soft cap as shown in 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 complexity and amount of uncertainty associated with the B2H
transmission project,the Company faces significant risks throughout the entire project life cycle
that may ultimately impact 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 the issues for
each risk,and provides the latest status for each.Table No.1 summarizes the three types of
project risk and the key issues contributing to them.
STAFF COMMENTS 9 MAY 23,2023
STAFF COMMENTS 10 MAY 23,2023
Table No.1:Project Risks
Capability Risks Schedule Risks Cost Risks
Longhorn Substation:Longhorn Substation:Longhorn Substation:
B2H will be unusable The permitting process is in Cost of an alternative is
without this progress and the construction unknown
interconnection.timeline is unknown.
ROW Acquisitions:ROW Acquisitions:ROW Acquisitions:
B2H cannot be built ROW delays might delay ROW negotiations have
without the ROWs.construction,especially if legal potential to increase costs.
action becomes necessary.
Boardman-Ione ("B-I")B-I Alternate Transmission B-I Alternate Transmission
Alternate Transmission Path:Path:
Path:An alternate line is in the early The alternate path and cost
B2H cannot be completed stages of permitting,followed are not certain.Also,
without relocating this line.by construction of the line,then environmental mitigation may
demolition of the old line.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.
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 Iine terminates in
Boardman,but a third party -BPA -must construct the Longhorn substation to interconnect
it to the existingtransmission 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.
Although any of these issues (or other unforeseen ones)could prevent the successful
completion of B2H,Staff assumes that the Company will fmd a workaround to complete the
project and make it useful.Staff concludes that these capacity risks could translate into
STAFF COMMENTS 11 MAY 23,2023
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 manifests as cost risk to ratepayers.The Company's current planned in-
service date for B2H is June 1,2026,which is necessary to meet the 2026 capacity deficit
established in its 2021 IRP.If B2H is not online,the Company may opt to incur additional
expenses to implement a workaround for the capacity deficit.Staff recommends that if
circumstances delay the project beyond June l,2026,the Commission should require the
Company to track and report any expenses incurred outside of B2H to cover the capacity deficit
until B2H is online.These expenses should be subject to the same 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
cost.The Company has retained experienced engineering firms to refine the project estimate and
STAFF COMMENTS 12 MAY 23,2023
has shown due diligence in responsibly estimating the project cost.However,to protect
customers,Staff recommends that the Commission place a soft cap on the project in accordance
with the Application's estimate.If the project costs more than the soft cap,the Company should
provide convincing evidence of its efforts to remain within the cap and the reasons for exceeding
it.
Staff examined multiple responses to discovery including the date of estimates,major
construction features,contingency markups,shared and unshared costs between partners,
financing costs,and taxes to obtain a cohesive summary of the B2H cost estimate included as
Attachment A to these comments.Staff recommends that the Commission use the final total
included in the attachment as the soft cap for any future recovery.Staff and the Company can
use the subtotals as markers to identify which costs deviated from the estimate,and by how
much.
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.
Longhorn Substation
The northern terminus of B2H must have the Longhorn substation constructed to connect
to the existing BPA 500-kV transmission network and the Mid-C market hub.Without this
substation,the transmission path would be incomplete,and the project would not be useful.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").4 Based on Staff's analysis
described below,Staff believes that the capability,schedule,and cost risks associated with the
Longhorn substation are all low.
4 The Umatilla Electric Cooperative serves a portion of the Columbia Basin and Blue Mountain county in
Northeastern Oregon.
STAFF COMMENTS 13 MAY 23,2023
The Company has no realistic alternative to the Longhorn substation.Staff questioned
what the Company would do if BPA does not construct the Longhorn Substation.The Company
stated:"In the unlikelyevent that BPA decides not to pursue construction of the Longhorn
substation,the Company will look to find a new 500-kV interconnection point for B2H in the
area."See Response to Production Request No.12
Despite the lack of a contingency plan,Staff believes the risk of BPA not building the
substation is low because the substation is critically important to BPA,the Company,PAC,and
UEC.Furthermore,BPA owns the land,has completed the environmental review process and
has already resolved two chronic problem areas.Funding for the substation has been built into
the overall B2H cost,including a 20%contingency.Finally,the Company states:"According to
BPA,construction of the Longhorn substation is expected to begin in spring 2023 in response to
the UEC interconnection request.BPA is beginning the second phase of the Line and Load
Interconnection Facilities Study for the B2H interconnection at Longhorn."See Response to
Production Request No.44.
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
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 §7-711A.
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
STAFF COMMENTS 14 MAY 23,2023
removed,BPA must construct an alternativetransmission path to serve its Columbia Basin load
that creates a signiñcant cost and schedule risk for the Company.
The Company and PAC 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 Enish B2H by Spring of 2026.
Currently,BPA is performing environmental studies of the proposed alternate path.The
Company has included an approximate cost estimate for this work in its overall B2H budget,but
the fmal project scope is not yet known.Potential environmental mitigations are also not yet
known.
Supply Chain
Staff believes the current supply chain problems add signincant 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.Although national efforts are being
directed to alleviate some of these issues,the risk of schedule delay due to supply chain
problems is signiñcant.
Inflation
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 a 20%
contingency to account of the uncertainty of innation.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%over
the last year.Even with the 20%contingency,the Company's final project cost may be
underestimated.
STAFF COMMENTS 15 MAY 23,2023
Outstanding Permits
The primary risk from an outstanding permit is schedule delay.The Company has spent
years obtaining some of the particularly difficult to obtain project permits,but several routine
permits and permits out of the Company's control are still outstanding.
The Company has identified almost 50 different permits that the project has obtained or is
in the process of obtaining.See Response to Production Request No.19.Overall,the Company
assesses a "high likelihood that the pending permits will be issued in time to complete
construction of B2H in 2026."Id.Staff reviewed the list of pending permits and agree the
schedule risk is low for routine filings within the Company's control.
However,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 frequently used 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
increased operational costs or unrealized benefits after the project is put into operation.
However,Staff believes its analysis of these costs and benefits from the project supports the
granting of the requested CPCN in this case when compared to the costs and benefits of the next
best alternative.
Mid-C Market Sufficiency
The primary purpose of B2H is to provide access to the Mid-C market for the Company
to purchase power when needed,typicallyin July and August.Therefore,it is essential to assess
the likelihood that power will be available when the Company needs it.
The Company evaluated market sufficiency using peak load analysis,BPA's Resource
Adequacy assessment,Northwest peak coincident load,a Renewable Portfolio Standard ("RPS")
review,and Northwest IRP resource plans.The Company's consolidated assessment is that
summer Mid-C capacity will be available for the foreseeable future.In addition,because most
STAFF COMMENTS 16 MAY 23,2023
utility companies in the Northwest have winter peak demands,an abundance of summer surplus
is expected.
Staff reviewed the Company's evidence and concurs that the evidence suggests a summer
surplus will be available in the foreseeable future.Although Staff has concerns that the
electrification mandates in Oregon and Washington may begin to cause summer shortages,this is
not substantiated by data.Therefore,Staff believes the risk of market insufficiency is low.
Mid-C Market Price
Staff believes that sustained high prices in the Mid-C market could present cost risk to
ratepayers,but the preponderance of the modeling evidence suggests that B2H is still the most
cost-effective solution.
The Company intends to use B2H to economically purchase Mid-C market electricity to
meet its energy needs and to resolve future capacity deficits during summer peaks.According to
the Company,as the price of Mid-C market power rises,the less cost-effective B2H becomes,
but can be mitigated through the sale of surplus electricity.See Responseto Staff Production
Request No.46.
However,it is difficult to determine if more expensive market purchases would render
the overall B2H portfolio less cost-effective than the non-B2H portfolio.To assess this,Staff
asked the Company to model it over a 20-year time period.High market prices had to be
indirectly forced by inputting high gas or high carbon prices.The result show that in 18 out of
20 stochastic runs,the B2H portfolio was still the most cost-effective solution.Based on this,
Staff believes that the Mid-C market price risk is low to moderate.
Mid-C to Longhorn TSA
The Company's primary purpose for B2H is to obtain a high-capacity transmission path
to the Mid-C market in south-central Washington.However,B2H provides only a portion of the
full transmission path.The Company must still obtain transmission rights on existing networks
for the segment between the Longhorn substation and the Mid-C market.Without this,B2H
would not be useful to the Company.
On March 24,2023,the Company and BPA signed an agreement for the Company to
acquire 500 MW of PTP transmission service between Mid-C and Longhorn.The agreement
STAFF COMMENTS 17 MAY 23,2023
includes several contingencies including successful energization of B2H,and completion of the
Longhorn substation.Response to Production Request No.42,Attachment 10.The 500 MW
acquisition aligns with the Company's 2021 IRP preferred portfolio capacity requirement.Based
on this agreement,Staff believes that the TSA risk is low.
BPA Buyout
The Company's Ownership Buyout of BPA amounts to hundreds of millions of dollars in
additional expenses to construct and maintain B2H.However,BPA committed to purchasing
long-term transmission services across B2H and other parts of the Company's network.The
Company asserts that the long-term revenue from BPA will adequately cover the increased
project costs and the reimbursement of BPA's earlier expenses.
Staff analyzed the Company's cost and revenue assumptions provided in its Responsesto
Production RequestNos.34 and 35.Staff agrees that the assumptions are realistic because they
are based on recent historic transmission volumes by BPA,and informed forecasts of annual
Open Access Transmission Tariffs ("OATT")rates.Also,the revenue from BPA is expected to
continue indefinitely,with modest annual increases.Over time,this revenue should fully offset
the extra project expenses and become a benefit to ratepayers as the transmission line is
depreciated.
In addition,the Permit Buyout agreement with BPA defers the payback of BPA's early
B2H expenses until 10 years after B2H is energized.This allows the Company to accumulate
sufficient revenue from BPA to cover the payback.Staff believes the cost and revenue
assumptions are realistic,that the revenue should adequately cover the costs,and therefore the
Permit Buyout risk to ratepayers is low.
Asset Exchanges
The Project Description section lists the six components that make up the asset
exchanges between PAC and the Company.These exchanges are not part of B2H but are
essential to unlock its usefulness,posing a risk to the overall deal if the exchanges do not occur.
The Company and PAC have mitigated this risk by signing an agreement to execute these actions
contingent on CPCN Commission approval and after B2H is energized.The Company stated
that,"[b]oth the Company and PacifiCorp will request approval of the agreement pursuant to
STAFF COMMENTS 18 MAY 23,2023
Idaho Code §61-328,...,in a future proceeding at a time that would allow for a Commission
determination prior to energization of B2H."Responseto Production Request No.6.
The main risk of the Asset Exchanges is if the value of the assets 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 PAC,Staff
believes the risk in completingthe asset exchanges is low.However,Staff recommends that
recovery for the cost of the project be contingent on both PAC and the Company obtaining
Commission approval of these exchanges.
Customer Notice and Public Comments
A telephonic Customer Workshop for Idaho Power's application was held on Monday,
April 17,2023.Customer participation was minimal.As of Tuesday,May 23,2023,there has
been one (1)Customer Comment received,which was in support of this case.
STAFF RECOMMENDATIONS
Staff makes the followingrecommendations:
1.Issue an order granting a CPCN for the construction of the B2H project,but make
the project's recovery contingent on the Commission's approval of all Asset
Exchanges and the Commission's determination of prudence of actual cost when
the project is complete;
2.When the Company does file for recovery,it should include evidence of its
pursuit of alternative funding sources for the project;and
3.Establish a soft cap for the recoverable value of the project as discussed above.
Respectfully submitted this day of May 2023.
Deputy Attorney General
Technical Staff:Matt Suess
STAFF COMMENTS 19 MAY 23,2023
Jolene Bossard
Jon Kruck
Kevin Keyt
Kimberly Loskot
i:umisc/comments/ipce23.1mdmsjbjkkkk!comments
STAFF COMMENTS 20 MAY 23,2023
THIS ATTACHMENT
IS CONSIDERED
CONFIDENTIAL AND
PROPRIE TARY IN
CASE NO.IPC-E-23-01
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 23rd DAY OF MAY 2023,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,IN
CASE NO.IPC-E-23-01,BY E-MAILING A COPY THEREOF,TO THE
FOLLOWING:
DONOVAN E WALKER TIMOTHY TATUM
IDAHO POWER COMPANY IDAHO POWER COMPANY
PO BOX 70 PO BOX 70
BOISE ID 83707-0070 BOISE ID 83707-0070
E-MAIL:[e-mail] E-MAIL:[e-mail]
[e-mail] (Confidential Copy)
(Confidential Copy)
ERIC L OLSEN LANCE KAUFMAN PhD
ECHO HAWK &OLSEN PLLC 2623 NW BLUEBELL PLACE
PO BOX 6119 CORVALLIS OR 97330
POCATELLO ID 83205 E-MAIL:lance aegisinsight.com
E-MAIL:[e-mail] (Redacted Copy)
(Confidential Copy)
PETER J RICHARDSON DR DON READING
RICHARDSON ADAMS PLLC 280 S SILVERWOOD WAY
PO BOX 7218 EAGLE ID 83616
BOISE ID 83702 E-MAIL:[e-mail]
E-MAIL:[e-mail] (Redacted Copy)
(Confidential Copy)
ED JEWELL WIL GEHL
DEPUTY CITY ATTORNEY ENERGY PROGRAM MANAGER
BOISE CITY ATTORNEY'S OFFICE BOISE CITY DEPT OF PUBLIC WORKS
PO BOX 500 PO BOX 500
BOISE ID 83701-0500 BOISE ID 82701-0500
E-MAIL:[e-mail] E-MAIL:[e-mail]
[e-mail] (Redacted Copy)
boisecityattornev citvofboise.ore
(Confidential Copy)
CERTIFICATE OF SERVICE
MARIE CALLAWAY KELLNER BRAD HEUSINKVELD
ID CONSERVATION LEAGUE ID CONSERVATION LEAGUE
710 N 6TH ST 710 N 6TH ST
BOISE ID 83702 BOISE ID 83702
E-MAIL:[e-mail] E-MAIL:
(Confidential Copy)[e-mail]
(Redacted Copy)
JIM SWIER AUSTIN RUESCHHOFF
MICRON TECHNOLOGY INC THORVALD A NELSON
8000 S FEDERAL WAY AUSTIN W JENSEN
BOISE ID 83707 HOLLAND &HART LLP
E-MAIL:[e-mail] 555 17TH ST STE 3200
(Redacted Copy)DENVER CO 80202
E-MAIL:[e-mail]
[e-mail]
[e-mail]
aclee hollandhart.com
(Redacted Copy)
SECRETARŸ -
CERTIFICATE OF SERVICE