20230808Comments of the Commission Staff.pdf

CHRIS BURDIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone]
IDAHO BAR NO.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 IDAHO POWER )COMPANY'S APPLICATION FOR A )CASE NO.IPC-E-23-05
CERTIFICATE OF PUBLIC CONVENIENCE )AND NECESSITY TO ACQUIRE )RESOURCES TO BE ONLINE BY 2024 AND )COMMENTS OF THE
FOR APPROVAL OF A POWER )COMMISSION STAFF
PURCHASED AGREEMENT WITH )FRANKLIN SOLAR LLC
COMMISSION STAFF ("STAFF")OF the Idaho Public Utilities Commission,by and
through its Attorneyof record,Chris Burdin,Deputy AttorneyGeneral,submits the following
comments.
BACKGROUND
On February 17,2023,Idaho Power Company ("Company")filed an application
("Application")with the Idaho Public Utilities Commission ("Commission")requesting an order:
(1)granting the Company a Certificate of Public Convenience and Necessity ("CPCN")to
acquire 72 megawatts ("MW")of dispatchable energy storage to meet an identified capacity
deficiency in 2024;and (2)approving the 25-year Power Purchase Agreement ("PPA")between
Idaho Power and Franklin Solar LLC ("Franklin Solar").
STAFF COMMENTS 1 AUGUST 8,2023
The Company represents that to fill its 2024 capacity deficiency,the Company conducted
solicitation through a Request for Proposals ("RFP")process seeking to acquire energy and
capacity to help meet the Company's previously identified capacity needs of 85 MW to be online
by June of2024,and an incremental 115 MW in 2025.Application at 5.
The Company represents that the RFP process resulted in the selection of a 100 MW
solar photovoltaic ("PV")facility,an Idaho Power-owned 60 MW energy storage project,and an
Idaho Power-owned 12 MW energy storage project.Id.
The Company represents that on January 20,2023,Idaho Power and Franklin Solar
entered into a PPA to construct,own,operate and maintain a 100 MW solar PV facility located
in Twin Falls County,Idaho,supplying the output to the Company's system for the period of 25
years from a commercial operation date of June 1,2024.Id.
The Company represents that concurrent with execution of the PPA,on January 20,2023,
the Company executed a Build Transfer Agreement ("BTA")with Duke Energy Renewables
Solar,LLC ("Duke Energy Solar"),a subsidiary of Duke Energy Renewables,LLC,for the
purchase of a Battery Energy Storage System ("BESS"),co-located with the Franklin Solar 100
MW solar PV facility in Twin Falls County,Idaho,providingfor a minimum capacity of 60
MW.Id.at 9.
The Company represents that it can economically and efficiently add 12 MW of battery
storage at the Hemingway substation,the site for which 80 MW of battery storage is being
installed to meet the 2023 capacity deficiency,without requiring infrastructure upgrades and
ensuring maximum Investment Tax Credits ("ITC")benefits.The Company states that it intends
on adding the 12 MW BESS to the contract executed with Powin Energy Corporation on
February 28,2022,the contract in place for the 2023 energy storage resources,through a change
order.Or,in the alternative,use a different supplier the Company has available.Id.at 10.
The Company is not requesting binding ratemaking treatment in this case.The Company
requests that the Commission find it has met the requirements of Idaho Code §61-526,and for
the Commission to issue an order granting a CPCN to acquire 72 MW of energy storage
necessary to meet the identified capacity deficiency in 2024.Id.at 11-12.
The Company represents that it intends to finance the 72 MW of energy storage with a
combination of available cash and operating cash flow,available facilities and borrowing and
debt issuances,and potential future equity issuances by its parent entity,IDACORP.Id.at 14.
STAFF COMMENTS 2 AUGUST 8,2023
STAFF ANALYSIS
Staff's review focused on the capacity deficiency in 2024,the RFP process,the turn-key
costs of the 72 MW of BESS capacity,and the 25-year PPA.After its review,Staff
recommends:
1.Approval of the CPCN to acquire 72 MW of BESS capacity.
2.Capping the turn-keycosts of the 12 MW BESS and the 60 MW BESS at the
amounts specified in Paragraph 1 of Confidential Attachment A,unless the
Company presents convincing evidence that the current least-cost price is higher,
when the Company seeks cost recovery.
3.Approval of the PPA conditioned on the Parties updating the PPA to reflect the
followingitems:
a.inclusion of transmission costs in the calculation of liquidated damages for
Output Shortfall in Section 7.12.2.3;
b.correction of the mistake in Section 12.2.2;and
c.modification of Section 23.1 to reflect the significance of Commission
approval.
Staff also recommends that the Company address the issues Staff identified in the RFP
process in future RFPs,regardless of whether the Company files an exception with the Oregon
Public Utilities Commission ("OPUC").
I.Procurement Guidelines and Requirements
The Commission directed the Company to follow Oregon's procurement guidelines,
which Staff used as a basis to evaluate the Company's RFP process.Order No.32745 at 2.
Althoughthe Company filed a Notice of Exception to the Competitive Bidding Rules with the
Oregon Public Utilities Commission on February 17,2023 (Response to Staff Production
Request No.17),Staff believes the procurement guidelines exist for a reason and should be
followed to the greatest extent possible,only relaxing requirements with justification directly
tied to the specific reasons for filing an exception.
STAFF COMMENTS 3 AUGUST 8,2023
II.Capacity Needs in 2024
Staff believes that the capacity needs that drove the proposed resources are justified.The
Company represents that the 2022 All-Source RFP was issued on December 30,2021.The
Company stated that it was issued to address capacity needs of 85 MW in 2024 and incremental
115 MW in 2025 as identified in the 2021 Integrated Resource Plan ("IRP").The 2021 IRP was
acknowledged by the Commission on November 18,2022.Order No.35603.The Company
represents that the capacity deficiency identified in the IRP serves as the basis for issuance of the
2022 RFP.Response to Staff Production Request No.35 (a).
The Company states that in January of 2023,when bids were selected and contract
negotiations were starting,the 2024 capacity deficiency increased from 85 MW to 103 MW.
Response to Staff Production Request No.35 (c).The Company explains that the main factors
that caused the increase included an updated load forecast,updated transmission assumptions,
and enhancements to the Reliability and Capacity Assessment Tool ("R-CAT")used to
determine the capacity position for a given year.Response to Staff Production Request No.12.
The updated Load and Resource Balance ("L&R")is shown in Table No.1 below.Response to
Staff Production Request No.36.
Staff performed a thorough review of the loads and resources included in the L&R and
the assumptions used in their determination and believes the amount of the deficit is reasonable.
Table No.1:Load and Resource Balance
L&R Contribution
4,273.9
Hydro with Storage (Hells Canyon Complex)1,050.0
Coal (Bridger &Valmy)442.6
Gas (Langley,Bennett Mountain,Danskin &Bridger)976.7
Variable &Energy Limited Resources 1,060.3
Firm Transmission 453.0
Emergency Transmission 188.4
4,170.9
Annual Position (Positive is tength,Negative is Shortfo1II (103)
o.1 event-days/year
STAFF COMMENTS 4 AUGUST 8,2023
III.The RFP Process
Staff believes the Company generally conducted a fair and transparent RFP process.
However,there are several key issues that have caused Staff to question whether the Company's
RFP process resulted in projects that are least-cost,least-risk resources for Idaho ratepayers.
These issues include the following:
1.The Company restricted ownership types and resource types that could be
submitted for bid when it issued its RFP,limitingthe size of the bid pool;and
2.There were anomalies created by decisions the Company made to accommodate
changing circumstances during the final selection process.
In addition,Staff recommends the Company include the weighting of factors used to develop its
score for each of the bids when it issues future RFPs to improve transparency of its bid-scoring.
Limiting the Size of the Bid Pool
When the Company issued the RFP,the Company limited the size of the bid pool by
restricting ownership and resource types,preventing the Company from receiving potential
additional bids.Instead,the Company should have allowed all potential sources to bid into the
All-Source RFP and should have used scoring metrics and criteria to narrow the bid pool.By
limitingthe bid pool when the Company first issued its RFP,the Company may have excluded
resources that could be obtained at a bargain price to Idaho's ratepayers.
Althoughthe Company revised the RFP on April 13,2022,through an addendum to
allow respondent ownership of standalone BESS,respondent ownership of BESS was still not
allowed in "Solar +BESS"and "Wind +BESS"projects.Response to Staff Production Request
No.19 and Exhibit No.3 of Hackett's Direct Testimony.Althoughthe Company stated that
some respondents still provided bids with PPA-based storage components (Response to Staff
Production Request No.19),additional bids might have been submitted that were lower in
overall cost,if ownership was not restricted.
Althoughthe RFP was called "2022 All-Source RFP,"certain resource types were not
allowed in the RFP.For example,even though gas-fired plants convertible to hydrogen plants
were allowed,non-convertible gas-fired plants were not allowed in the RFP.The Company
explained that ensuring gas-fired plants could convert to hydrogen would provide greater long-
term operational viabilityof the resources given the uncertainty of future clean energy policies
STAFF COMMENTS 5 AUGUST 8,2023
and was consistent with the resource assumptions used in the 2021 IRP.Response to Staff
Production Request No.21.However,Staff believes that by only allowingconvertible gas-fired
projects to submit bids,it might have discouraged bids from potential non-convertible gas-fired
plants that might be available and could be a potential bargain for Idaho ratepayers.
Staff also believes the Company should not bias the types of resources based on resources
included for selection in the IRP,since they are proxy resources with assumed costs.The
purpose of an RFP is to determine potential resources that are available in the market.Until
actual bids are received,the availability of certain resources and their costs are unknown.
Anomalies in Final Selection Process
During the process of conducting the RFP,and after the Company developed its initial
shortlist,two circumstances occurred requiring the Company to deviate from the process it
originally envisioned in selecting its final proposed projects.One was the passing of the
Inflation Reduction Act ("2022 IRA")and the second was an increase in the 2024 capacity
deficit.The Company's decisions to accommodate these changes has caused Staff to question
whether the final selected resources are least-cost,least-risk.
After the qualitative and quantitative evaluation processes were conducted,five projects
were selected for the Final Short List in June and July of 2022,which included Project Nos.2,7,
8,9,and 10.Hackett Direct at 16.Project Nos.7 and 8 were selected because they were
consistently selected in the initial long-term capacity expansion ("LTCE")analysis.Id at 19.
Project Nos.2,9,and 10 were selected because they were the next most cost-effective projects.
Id.The Company notified those projects that were not selected in June and July of 2022.Id at
16.On August 16,2022,the 2022 IRA was signed into law.Because 2022 IRA could
potentiallyimpact!the pricing of proposals,the RFP evaluation team gave these five projects on
the Final Short List an opportunityto update pricing.Id at 21.All five shortlist projects
provided updated pricing,except for Project No.7,because the project was withdrawn due to site
control concerns.Id.
'Page 21 of Eric Hackett's Direct Testimony states that "[t]he 2022 IRA provides for,among other things,
numerous renewable energy tax credits,for example extension of the current investment tax credits ("ITC")andproductiontaxcredits("PTC"),a new ITC for standalone energy storage,application of the PTC to solar,transition
to a technology-neutral ITC and PTC after 2024,and creates a transferability option that allows credits to be sold to
an unrelated taxpayer."
STAFF COMMENTS 6 AUGUST 8,2023
Subsequently,a second LTCE analysis was performed for Project Nos 2,8,9,and 10.Id
at 22.Project No.8 was consistently selected as the most cost-effective resource.Id.
According to the levelized costs of capacity ("LCOC")of the shortlist projects,the next most
cost-effective project was Project No.10.Exhibit No.4 of Hackett Direct.
Between the time of the second LTCE analysis and the time of contract negotiations,the
2024 capacity need had increased from 85 MW to 103 MW.Hackett Direct at 23 and
Ellsworth's Direct Testimony at 24.Therefore,the Company and Project No.8 increased the
proposed energy storage system from 20 MW to 60 MW.Hackett Direct at 23.However,a 7
MW deficit still existed even with the 100 MW solar paired with the 60 MW energy storage.Id.
Therefore,the RFP evaluation team contacted Project No.10,the next most cost-effective
project.Id at 32.Ultimately,the Company and Project No.10 decided to propose a 12 MW
BESS project to meet the additional deficit,even though Project No.10 originally submitted a
bid for a 46 MW BESS project.Id.
Staff identified several issues associated with the process described above.First,Staff
believes that some of the eliminated projects (such as Project Nos.3,16,17)in the first round
could have been invited back into the Final Short List and given an opportunityto update pricing
after the 2022 IRA was signed into law.These projects did not have hard constraints such as
transmission availability,and they were eliminated because they were not selected by the first
LTCE analysis.
Second,Staff believes the Company could have updated L&R and identified the higher
deficiency amount earlier than January of 2023,before contract negotiations began,giving all
potential candidates an opportunityto update the capacity amounts in their bids.This might have
led to revised bids with updated capacity amounts and pricing information,before the Company
eliminated any project.Instead,the Company only negotiated with Project No.8 to modify its
capacity to a higher amount and by adding an additional Project No.10 to meet the higher
amount of deficiency.
Transparency of Bid-Scoring
Staff believes the Company adequatelydescribed the evaluation,negotiation,and
approval processes in the RFP and embedded the metrics and criteria used to score each of the
STAFF COMMENTS 7 AUGUST 8,2023
bids directly in the forms each bidder submitted to the Company for evaluation.This allowed
each bidder to understand how their bids would be evaluated against other competing bids.
However,the Company did not provide the weighting factors for the evaluation metrics
and criteria in the bid solicitation materials.Response to Staff Production Request No.40.
AlthoughStaff believes the scoring process was likely conducted in a fair and impartial manner,
Staff believes it could lead to questions of bias toward certain projects since the weighting
factors were not included upfrontwhen the RFP was issued.Staff recommends that the
Company include the weighting of factors used in determining the final scores in the evaluation
and selection of bids in future RFPs.
IV.Turn-keyCosts of 72 MW BESS
Staff recommends approval of the CPCN for the two BESS resources with a soft cap on
each project's turn-keycost because Staff cannot confirm the selected resources are the least-
cost,least-risk resources to meet the Company's 2024 capacity needs due to the issues associated
with the RFP process.However,recovery above the cap can occur if the Company presents
convincing evidence that the least-cost price is currentlyhigher when the Company seeks cost
recovery.
The estimated turn-keycosts of the 12 MW BESS and the 60 MW BESS projects are
specified in Paragraph 2 of Confidential Attachment A.Response to Staff Production Request
No.43(b)and BTA at 25.All these costs are full turn-keyall-in costs to bring a BESS project
from design to commercial operation.Response to Staff Production Request No.43 (a)and (b).
Staff compared the turn-keycosts of all the projects on the Final Short List and the proposed
BESS projects.The results are shown in Table No.2 contained in Paragraph 3 of Confidential
Attachment A.Because of the issues identified in the RFP process,Staff believes it is reasonable
to cap the proposed BESS facilities'turn-keyprices at the lowest unit price identified in
Paragraph 3 of Confidential Attachment A.This results in a soft cap for the 12 MW BESS and a
soft cap for the 60 MW BESS specified in Paragraph 1 of Confidential Attachment A,unless the
Company presents convincing evidence that the current least-cost,least-risk price is higher,in a
subsequent recovery case.Staff believes the soft cap and the method used to set it is reasonable
because it reflects current market conditions includingthe impacts of the 2022 IRA.
STAFF COMMENTS 8 AUGUST 8,2023
V.25-year PPA
Staff identified issues with Section 7.12.2.3,Section 12.2.2,and Section 23.1 in the 25-
year PPA and recommends approval of the PPA conditioned on updating these three sections.
Section 7.12.2.3
Staff recommends inclusion of transmission costs in the calculation of liquidated
damages for Output Shortfall.Output Shortfall will occur when the Net Output delivered by the
Facility during any month is less than the Output Guarantee for such month.PPA at 49.
Liquidated Damages associated with Output Shortfall are calculated as the product of the Output
Shortfall multipliedby Idaho Power's Cost to Cover.Id at 50.Idaho Power's Cost to Cover is
defined as the difference between market price plus Green Tags Price and Contract Price.Id at
9.This calculation does not consider transmission costs associated with moving energy to cover
the Output Shortfall.
Idaho Power stated that there may or may not be transmission costs incurred.Response
to Staff's Production Request No.22.Staff believes transmission costs should be included in the
calculation of liquidated damages for the followingreasons.First,when market price is used in
calculating liquidated damages,transmission costs associated with moving energy from market
to Idaho Power should be considered.Otherwise,when the Seller does not meet the Output
Guarantee,ratepayers (instead of the Seller)will have to pay for the transmission to move
replacement energy to Idaho Power.Second,in Section 12.2.1 (Remedy for Seller's Failure to
Deliver),transmission costs associated with movingreplacement energy from market to Idaho
Power are considered in the calculation of the damages for situations in which the Seller has
committed an Event of Default where Seller fails to deliver.Because the impact of an Event of
Default and the impact of an Output Shortfall are essentially similar in nature,Staff believes that
they should be treated in a consistent manner.Third,the Company agreed with Staff s position
on this issue in Case No.IPC-E-22-29,and the Company amended the Pleasant Valley Solar
PPA to include transmission related costs when calculating liquidated damages for Output
Shortfall.
STAFF COMMENTS 9 AUGUST 8,2023
Section 12.2.2
This section discusses the remedy for the Company's failure to purchase and intends to
reference Section 12.6 (Duty/Rightto Mitigate),but it mistakenly references Section 12.7
(Security).Staff recommends that the Parties correct this mistake.
Section 23.1
Section 23.1 of the PPA contains the statement "[n]o modification hereof shall be
effective unless it is in writing and executed by both Parties."PPA at 68.Staff believes that this
statement neglects the significance of Commission approval and recommends that the statement
be updated to reflect the need for Commission approval before any modification becomes valid.
For example,the statement can be updated as follows:No modification hereof shall be effective
unless it is in writing and executed by both Parties and subsequently approved by the
Commission.
STAFF RECOMMENDATION
After its review,Staff recommends:
1.Approval of the CPCN to acquire 72 MW of BESS capacity;
2.Capping the turn-keycosts of the 12 MW BESS and the 60 MW BESS at the
amounts specified in Paragraph 1 of Confidential Attachment A ,unless the
Company presents convincing evidence that the current least-cost price is higher,
when the Company seeks recovery in a subsequent case;and
3.Approval of the PPA conditioned on the Parties updating the PPA to reflect the
followingitems:
a.Inclusion of transmission costs in the calculation of liquidated damages for
Output Shortfall in Section 7.12.2.3;
b.Correction of the mistake in Section 12.2.2;and
c.Modification of Section 23.1 to reflect the significance of Commission
approval.
Staff also recommends the Company address the issues Staff identified for the RFP
process in future RFPs,regardless of whether the Company files an exception with Oregon
Public Utilities Commission ("OPUC").
STAFF COMMENTS 10 AUGUST 8,2023
Respectfully submitted this 8th day of August 2023.
Chris Burdin
Deputy AttorneyGeneral
Technical Staff:Yao Yin
Kevin Keyt
i:umisc/comments/ipce23.5cbyykkmscomments
STAFF COMMENTS 11 AUGUST 8,2023
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 8th DAY OF AUGUST 2023,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,IN CASE
NO.IPC-E-23-05,BY E-MAILING A COPY THEREOF,TO THE FOLLOWING:
DONOVAN E WALKER TIM 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:ttatum idahopower.com
[e-mail]
SECRETARY
CERTIFICATE OF SERVICE