20251219Reply Comments.pdf

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RECEIVED
DONOVAN WALKER December 19, 2025
Lead Counsel IDAHO PUBLIC
dwalkerCWidahopower.com UTILITIES COMMISSION
December 19, 2025
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714
Re: Case No. IPC-E-25-22
Idaho Power Company's Application for Authority to Update its Operation
and Maintenance Charges Applicable to Schedule 72, Generator
Interconnections to PURPA Qualifying Facility Sellers
Dear Commission Secretary:
Attached for electronic filing please find attached Idaho Power Company's Reply
Comments in the above-entitled matter.
If you have any questions about the attached documents, please do not hesitate
to contact me.
Sincerely,
Donovan E. Walker
DEW:sg
Attachments
1221 W. Idaho St(83702)
P.O. Box 70
Boise, ID 83707

DONOVAN E. WALKER (ISB No. 5921)
LISA C. LANCE (ISB No. 6241)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalker idahopower.com
I lance(a-)idahopower.com
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-25-22
AUTHORITY TO UPDATE ITS OPERATION )
AND MAINTENANCE CHARGES ) IDAHO POWER COMPANY'S
APPLICABLE TO SCHEDULE 72, ) REPLY COMMENTS
GENERATOR INTERCONNECTIONS TO )
PURPA QUALIFYING FACILITY SELLERS. )
COMES Now, Idaho Power Company ("Idaho Power" or "Company"), and,
pursuant to Idaho Public Utilities Commission's ("Commission") Rules of Procedure 201-
204 and pursuant to the Amended Notice of Modified Procedure, Order No. 36833,
entered on November 6, 2025, hereby respectfully submits the following Reply in
response to Supplemental Comments filed by Idaho Hydroelectric Power Producers Trust
("IdaHydro"), on December 10, 2025.
IDAHO POWER COMPANY'S REPLY COMMENTS - 1

On May 8, 2025, Idaho Power filed an Application requesting Commission
approval to update the monthly operations and maintenance ("O&M") charges contained
in Schedule 72, Generator Interconnections to PURPA Qualifying Facility Sellers
("Schedule 72"). The proposed updates were submitted in compliance with the settlement
stipulation approved by Order No. 36042 issued in the Company's 2023 General Rate
Case (Case No. IPC-E-23-11) (the "2023 GRU) and are intended to reflect current
operating metrics and assumptions.
In these Reply Comments, Idaho Power addresses the arguments IdaHydro has
attempted to relitigate throughout this compliance update, which uses the previously
approved Schedule 72 methodology updated to reflect current operating metrics and
assumptions.
I. BACKGROUND
The Commission first adopted Schedule 72, governing the interconnection of
PURPA Qualifying Facility ("QF") generators to Idaho Power's system in Idaho Power's
Idaho service area, in Case No. IPC-E-90-20. When Schedule 72 was established, a
schedule of monthly O&M charges assessed to interconnecting QFs was litigated,
established, and set forth as part of the approved tariff Schedule 72. When a PURPA QF
interconnects to the Company's facilities, the QF pays the capital costs of the facilities
necessary to connect the project to the Company's system and, once completed, the
Company assumes responsibility for all ongoing O&M associated with facilities owned by
or transferred to the Company. The O&M charges appearing within Schedule 72 are
designed to hold the Company's general body of customers indifferent to the ongoing
IDAHO POWER COMPANY'S REPLY COMMENTS -2

O&M costs of the addition of the QF project and its required infrastructure to interconnect
to the Company's bulk electric system.
On December 23, 2023, the Commission issued Order No. 36042 in Idaho Power's
2023 GRC, which approved the settlement stipulation entered into by Idaho Power,
Commission Staff, and the other parties to the general rate case including IdaHydro.
Following the conclusion of the 2023 GRC, Idaho Power and IdaHydro held informal
discussions regarding the basis for the methodology used to establish the current O&M
charges in 1990 ("Original Methodology").
In compliance with the 2023 GRC stipulation, Idaho Power filed the application in
this matter on May 8, 2025, seeking to update the existing O&M cost methodology with
current inputs and data, which had not been done since the initial approval and
implementation of Schedule 72 in 1990. On June 9, 2025, the Commission issued Notice
of the Application and set an intervention deadline. Order No. 36631. IdaHydro and the
Renewable Energy Coalition ("REC") petitioned for and were granted intervention. After
the directed intervention period, the Commission issued Notice of Modified Procedure
Order No. 36714, establishing that the Application be processed under Modified
Procedure, directing persons interested in submitting written comments to do so by
September 16, 2025, directing parties, referring to Staff and Intervenors, interested in
filing comments in reply to previously filed comments to do so by October 7, 2025, and
directing the Company to file any reply comments by October 14, 2025. Order No. 36714.
On September 16, 2025, Staff and IdaHydro filed their initial comments with the
Company filing reply comments on October 14, 2025.
IDAHO POWER COMPANY'S REPLY COMMENTS - 3

On November 6, 2025, The Commission issued Order No. 36833 to allow
additional comments by December 12, 2025, and the Company to submit reply comments
by December 19, 2025.
II. REPLY COMMENTS
Summary
The Commission has implemented a schedule of O&M charges applicable to
PURPA QF interconnections that is lawful; consistent with PURPA and federal
regulations; and makes a fair,just, and reasonable allocation of the incremental additional
cost imposed upon the Company's system by the addition of the QF — which PURPA
requires that Idaho Power's retail customers be insulated from and held indifferent to such
additional costs imposed by QFs.
The Commission approved Schedule 72, including its particular schedule of O&M
charges, in 1990 and Idaho Power has implemented the same for the last 35 years for all
PURPA QFs interconnecting to Idaho Power's system. A bedrock principle and core
concept in the implementation of PURPA's mandatory purchase obligation is that the
utility's retail customers must remain indifferent to the QF purchase, i.e., customers
should be financially unaffected by whether a utility generates its own power or purchases
power from the QF. Federal law requires the rates paid to QFs be "just and reasonable"
to the electric consumers of the utility and shall not exceed the incremental cost to the
utility of alternative energy, i.e., the avoided cost. 16 U.S.C. § 824a-3(b). Avoided cost
is specifically defined as the "incremental costs to an electric utility of electric energy or
capacity or both which, but for the purchase from the qualifying facility ... such utility would
generate itself or purchase from another source." 18 C.F.R. § 292.101(b)(6).
IDAHO POWER COMPANY'S REPLY COMMENTS -4

The Commission's implementation of Schedule 72's O&M charge is necessary to
maintain customer indifference required by PURPA by allocating the incremental cost to
the utility's system of the addition of the QF and the required additional infrastructure and
resulting increase in operation and maintenance expenses caused thereby. The system
implemented by the Commission, in its basis of average system O&M cost, synergizes
with this goal as this is the cost that retail customers are allocated, and by having the
QF's pay for their incremental portion, customers are held indifferent to what would
otherwise be an upward pressure on the rates paid by retail customers caused by the
addition of the QF to the Company's system. This is what PURPA requires, and the
Commission's system of Schedule 72 O&M charges is not only a valid and legal
implementation under PURPA, but also by design matched to the impact imposed upon
Idaho Power's customers.
FERC regulations, cited by IdaHydro, define interconnection costs as follows:
Interconnection costs means the reasonable costs of
connection, switching, metering, transmission, distribution,
safety provisions and administrative costs incurred by the
electric utility directly related to the installation and
maintenance of the physical facilities necessary to permit
interconnected operations with a qualifying facility, to the
extent such costs are in excess of the corresponding costs
which the electric utility would have incurred if it had not
engaged in interconnected operations, but instead generated
an equivalent amount of electric energy itself or purchased an
equivalent amount of electric energy or capacity from other
sources. Interconnection costs do not include any costs
included in the calculation of avoided costs.
18 C.F.R. § 292.101(7). IdaHydro cites to the "in excess of" portion of this definition and
conflates the meaning with arguments requiring a "netting" of (1) the O&M included as
compensation to the QF in the avoided cost pricing and (2) the O&M charged to the QF
IDAHO POWER COMPANY'S REPLY COMMENTS - 5

for interconnection in Schedule 72. IdaHydro Supplemental Comments at 2, 71. Idaho
Power addressed this in its October 14, 2025, Reply Comments. REC, another
intervening QF party, also addressed this in its Comments filed on September 16, 2025,
correctly pointing out that the way in which Schedule 72 requires a QF to pay for all of the
O&M costs associated with its interconnection along with the corresponding payment to
the QF of all of the O&M costs associated with the utility's avoided resource is lawful
under PURPA and "what is normally done under PURPA". REC Comments at p. 4 ("The
second option is what is normally done under PURPA, the QF is charged its full
interconnection costs (either in a tariff like Schedule 72 or the actual costs), but the
avoided cost rate compensates the QF for the avoided utility interconnection costs.").
In short, the record demonstrates that the avoided cost rates paid to the QF include
compensation for avoided interconnection costs. See p. 7, fn 2. As a result, absent the
Schedule 72 O&M charge, customers would pay twice for O&M on the QF interconnection
facilities: once via the actual O&M costs incurred, and again via the avoided cost rate. To
ensure that customers are held indifferent to upward pressure on rates as a result of the
purchase from the QF, the Schedule 72 O&M costs properly recover QF interconnection
facility O&M charges from the QF. Because Us are paid for all of the avoided
interconnection costs that the Company would have incurred absent the QF's
IdaHydro quotes several excerpts of deposition transcripts arguing that Idaho Power does not
quantify the costs and does not know they are accurate, which misconstrues the record. As stated in
comments, and in the depositions, system average costs are derived as part of a general rate case, and
actual O&M on an individual customer and individual QF basis are not tracked. As stated herein, the
relevant inquiry is whether all interconnect costs are included in the avoided cost rate methodology paid to
QFs and thus all interconnect O&M costs are appropriately charged through Schedule 72. IdaHydro filed
three of the four deposition transcripts: Riley Maloney,Aubrae Sloan, and Andres Valdepena-Delgado. For
completeness of the record, attached hereto and filed herewith as Attachment 1 is the transcript from the
fourth deposition of Eric Hackett, as well as his Deposition Exhibit No. 2, Interconnection
Point/Interconnection Facilities Drawing,which explains in detail interconnection facilities and a typical four-
pole interconnection.
IDAHO POWER COMPANY'S REPLY COMMENTS -6

interconnection in the avoided cost rates, it is then appropriate that the QF pay for the
entire amount of their incremental interconnection costs, and thus the Commission-
approved paradigm and Schedule 72 effectively ensure that QFs pay for the costs that
are in excess of the costs the Company would have incurred absent the QF's
interconnection.
IdaHydro further conflates this argument by stating that because the O&M costs of
the proxy resource are embedded in the avoided cost pricing and in Schedule 72 average
system O&M costs and not separately tracked, audited, or compared to actuals that this
is violative of the federal regulation's "in excess of" and "netting". However, as noted by
REC above, this is not the case and is not required. Because ALL of the interconnection
costs of the utility proxy resource are included in the avoided cost rate2 that is paid to the
QF in the avoided cost rates, it is lawful, appropriate, and "what is normally done under
PURPA" to charge the QF its full interconnection and O&M costs in a tariff like Schedule
72. In the 1990 case establishing Schedule 723 on reconsideration the Commission found
the Schedule 72 O&M collection to be lawful because reasonable interconnect costs were
included in the administratively determined avoided cost rate and that the underlying
methodology used to calculate the O&M charges in Schedule 72 was reasonable. As
discussed in Idaho Power October Reply Comments, this remains the same and true
today. Idaho Power's administratively determined avoided cost rates contain interconnect
costs for the proxy, or avoided, resource the same previously approved methodology is
used to calculate the O&M charges in Schedule 72.
2 See, Idaho Power Reply Comments, October 14, 2025, p. 11-13; and Attachment 1 to IPC's 10/14/25
Reply Comments, Idaho Power's Supplemental Response to IdaHydro's Interrogatory No. 8.
3 Case No. IPC-E-90-20, Order No. 24025, p. 1,2,4.
IDAHO POWER COMPANY'S REPLY COMMENTS - 7

IdaHydro Comments
The entirety of IdaHydro's Comments and Supplemental Comments are intended
to call into question the legality of the methodology used in Schedule 72. The
Commission specifically addressed these issues in the original case approving Schedule
72 in 1990. The two issues heard by the Commission upon reconsideration in the 1990
case were: 1. The inclusion of interconnect costs in the administratively determined
avoided cost rate; and 2. The calculation and reasonableness of the Schedule 72
operation and maintenance service charges." Order No. 24025, p. 1, 2, 4. Order No.
24025 remains a final Order.
Idaho Power's application in this case is simply requesting the Commission
approve an update to the monthly O&M charges contained in Schedule 72 in compliance
with the settlement stipulation approved by Order No. 36042 issued in the 2023 GRC.
Idaho Power does not believe the collateral attack on the fundamental premise of Order
No. 24025 by IdaHydro is appropriate or at issue in this case, nor does Staff.' The
Commission addressed and settled the issues IdaHydro attempts to argue over three
decades ago and issued a final order, and the only issue before the Commission in this
application is the update intended to reflect current operating metrics and assumptions.
However, IdaHydro and REC's legal challenge fails, as the Commission implementation
of Schedule 72 O&M charges to QF's is entirely lawful; consistent with PURPA and
federal regulations; and makes a fair, just, and reasonable allocation of the incremental
additional cost imposed upon the Company's system by the addition of the QF — which
' "Staff does not believe this current case is appropriate to challenge the fundamental framework
underlying Schedule 72." Staff Supplemental Comments, p.3.
IDAHO POWER COMPANY'S REPLY COMMENTS - 8

PURPA requires that Idaho Power's retail customers be insulated from and held
indifferent to such additional costs imposed by QFs.
A. Interconnection O&M in Avoided Cost Payments
Idaho Power has two Commission approved avoided cost rate methodologies, the
Surrogate Avoided Resource ("SAR") methodology utilized for QF projects that are below
the published rate eligibility thresholds and the Incremental Cost Integrated Resource
Plan ("ICIRP") methodology utilized for QF projects that are over the published rate
thresholds. Both of these methodologies account for interconnection, network upgrades,
and O&M costs associated with the proxy or surrogate resource that the utility is assumed
to avoid QF. The QF is then compensated through the avoided cost rate paid to it for the
avoided interconnection and associated O&M costs of the utility.
IdaHydro posits that because Idaho Power does not directly reconcile avoided
costs to actual amounts spent it results in a double recovery or under recovery. These
accusations are unfounded. The Commission has found reasonable interconnection
costs were included in the administratively determined avoided cost rate as required by
FERC. Order 24025 at p 4. Idaho Power's administratively determined avoided cost
rates contain interconnect costs for the proxy or avoided resource which comes from the
independently Commission reviewed and approved Orders and acknowledged IRPs as
well as the same previously approved methodology used.
B. Interconnection O&M in Schedule 72
IdaHydro again attempts to confuse the issue before the Commission by claiming
Idaho Power is incorrectly assessing Schedule 72 costs due to the lack of independent
accounting for each QF. The Company has maintained since the inception of Schedule
IDAHO POWER COMPANY'S REPLY COMMENTS - 9

72 in 19905, that the O&M charge appearing within Schedule 72 is designed to reimburse
the Company for costs, using system averages associated with operating and maintaining
such interconnection facilities. System Average O&M charges are applied to QF's to
ensure administrative efficiency, fairness across projects, and consistency with
Commission precedent.
The system average O&M cost basis is what is included in retail customers' rates
and is the cost that is increased by the expansion of the Company's system to
accommodate the addition of the facilities required by the QF's interconnection. The QF
is assigned an incremental portion of the O&M costs based on the value of its required
interconnection facilities that are added to the Company's system as a part of the
interconnection. The Commission found this methodology reasonable in Order No.
240256, and Staff"maintains that the system-average framework underlying Schedule 72
is reasonable." Staff Supplemental Comments p. 2.
C. Tracking of Interconnection O&M
IdaHydro attempts to characterize Idaho Power's Commission approved system
average framework as impermissible. Idaho Power is required to follow Commission
orders and approved tariff schedules and in turn charges the O&M fees authorized and
required by Commission-approved Schedule 72. The current methodology is consistent
with traditional ratemaking methodologies, which allocate system-wide costs to develop
cost-of-service for all retail customer classes in all jurisdictions, as well as for standby
5 As approved by the Commission in Case No. IPC-E-90-20, Order No. 23631, Reconsideration Order
24025.
6 p. 4, 8.
IDAHO POWER COMPANY'S REPLY COMMENTS - 10

services, facilities charges, and Open Access Transmission Tarriff rates for transition
services.
Charging actual O&M costs for QF projects would require the establishment of an
entirely separate system of work order preparation and billing just for QF projects. The
Company currently uses a work order system to accumulate costs for various work
requests. For each cost category, the Company would need to be able to use the work
order system to specifically identify actual costs associated with each individual QF.
Currently, and once constructed, the interconnection facilities necessitated by Us
become a part of Idaho Power's overall system and are indistinguishable from the rest of
the system.
The QF facilities have not been separately identified within various property
records and system mapping software, so even identifying whether work is being
performed on QF interconnection facilities may not be possible or may require a
significant amount of research. If identification of QF interconnection facilities was
achievable, field employees would need to be trained to specifically identify work
performed on those interconnection facilities separately from non-QF interconnection
facilities. In some cases, QF interconnection facilities may be located at the exact same
location, even on the same pole, as non-QF interconnection facilities. Currently,
maintenance is performed via "blanket work order" which is not meant to be specific to an
asset, but to a function, for example "line maintenance". The same blanket work order is
used for all general line maintenance in a region. Further, many of the costs included in
"actual O&M costs" are operational in nature.
IDAHO POWER COMPANY'S REPLY COMMENTS - 11

Staff notes even if there are some interconnection O&M costs that can be directly
assigned to a QF, there are "overhead costs that are ongoing, fixed in nature, and cannot
be directly assigned." Staff Supplemental Comments p. 3. Staff goes on to say they
"believe that these types of costs should be allocated across all QFs, regardless of
whether a QF's interconnection requires O&M work to be done or not." Id. at 3.
For all these reasons, Idaho Power believes a requirement to specifically track
actual O&M costs by individual QF is unreasonable and would result in unnecessary
incremental costs to customers. The present system of charging a percentage of
construction costs reasonably approximates Idaho Power's O&M costs, provides the QF
with a high level of predictability as to what their O&M costs will be over the life of the
project, and reasonably ensures that QF related O&M costs are not shifted to retail
customers. The Commission's implementation of Schedule 72's O&M charge is
necessary to maintain the required customer indifference required by PURPA by
allocating the incremental cost to the utility's system of the addition of the QF and the
required additional infrastructure and resulting increase in operation and maintenance
expense caused thereby. The system implemented by the Commission, in its basis of
average system O&M cost, synergizes with this goal as this is the cost that retail
customers are allocated, and by having the QF's pay for their incremental portion,
customers are held indifferent to what would otherwise be an upward pressure on the
rates paid by retail customers caused by the addition of the QF to the Company's system.
This is what PURPA requires, and the Commission's system of Schedule 72 O&M
charges is not only a valid and legal implementation under PURPA, but also by design
matched to the impact imposed upon Idaho Power's customers.
IDAHO POWER COMPANY'S REPLY COMMENTS - 12

D. PURPA Cost Recovery Standard
The Commission has the authority under PURPA and implementing regulations of
the Federal Energy Regulatory Commission ("FERC") to set avoided costs, to order
electric utilities, to enter into fixed term obligations, to purchase energy from small power
producers, and to implement FERC rules. 16 U.S.C. § 824a-3; and 18 C.F.R § 292 et.
seq. See also, 18 C.F.R. § 292.306 ("Each qualifying facility shall be obligated to pay any
interconnection costs which the State regulatory authority [the IPUC] (with respect to any
electric utility over which it has ratemaking authority) or nonregulated electric utility may
assess against the qualifying facility ... Each state regulatory authority ... shall determine
the manner for payments of interconnection costs ...")
The Commission has found reasonable interconnection costs were included in
the administratively determined avoided cost rate as required by FERC. Order 24025 at
p. 4. The Commission has also found the system-average framework methodology
reasonable in Order No. 240251, and Staff"maintains that the system-average framework
underlying Schedule 72 is reasonable." Staff Supplemental Comments p. 2.
IdaHydro's argument that the "Commission has no lawful basis to authorize Schedule
72 as proposed"$ is simply not true. The Commission retains the authority to determine
the avoided cost rate and the methodology under Schedule 72 as proposed by Idaho
Power in this Application.
p. 4, 8.
8 Supplemental Comment of IdaHydro p. 8.
IDAHO POWER COMPANY'S REPLY COMMENTS - 13

E. QF Charges
IdaHydro incorrectly characterizes total O&M costs exceeding construction costs
as over-recovery. The system O&M for the average system cost in Schedule 72 is the
same calculation and allocation of system O&M as is calculated for retail customers in a
general rate case. (Sloan Dep. 36:8-16). The O&M cost includes costs that increase by
the expansion of the Company's system to accommodate the addition of the facilities
required by the QF's interconnection. The QF is assigned its incremental portion of O&M
based on the value of its required interconnection facilities that are added to the
Company's system as a part of the interconnection. That incremental portion paid by the
QF is then deducted from what is included in rates for system O&M, both of which utilize
a system average O&M cost basis. IdaHydro's attempt to create a methodology that
does not look at the entirety of the O&M needed for the system would not protect retail
customers from harm by the addition of the QF.
IdaHydro's Supplemental Comments attempt to compare the actual construction
cost of a QF to the on-going O&M costs of the project as a part of a system. The two
costs are distinct. Idaho Power's duties as a regulated utility include routine inspections,
testing, vegetation management, and repair of interconnection facilities which are a part
of the Company's bulk electric system to provide safe and reliable service. The purpose
of the O&M Charge under Schedule 72 is to hold retail customers of Idaho Power neutral
by charging PURPA projects a reasonable rate for what the Company may expect to
spend on O&M over the life of the interconnection facilities required by the QF.
IDAHO POWER COMPANY'S REPLY COMMENTS - 14

III. CONCLUSION
Idaho Power appreciates Staff's review and Supplemental Comments. The
Company agrees with Staff's review of the current case and the impudence of challenging
the fundamental framework of Schedule 72. IdaHydro's on-going dissension with the
determination of the avoided cost rate and fundamental premise of interconnection O&M
charges in Schedule 72 have been previously addressed by the Commission. The
Commission found that reasonable interconnect costs were included in the
administratively determined avoided cost rate as required by FERC, and that the
underlying methodology to calculate Schedule 72's O&M charges was reasonable.
Order. No. 24025 at p. 4, 8.
Idaho Power respectfully submits that IdaHydro and REC's criticism of the
Company is misplaced and misconstrued given the clear history of the Commission's
implementation of interconnection costs in avoided costs rates since the very first
implementation of PURPA in the state of Idaho in 1980 with Order No. 15746, as well as
the consistent, fair, just and reasonable implementation of Schedule 72's O&M charges
for the protection of retail customers since the implementation of Schedule 72 in 1991.
The Commission's prior decisions have appropriately implemented PURPA's
requirements that retail customers of the utility be economically indifferent as to whether
or not Idaho Power purchases power from QFs or generates or purchases the power
itself, and to assure there is not an impermissible subsidy from customers to the QF.
Therefore, Idaho Power respectfully requests the Commission issue its order: (1)
approving the proposed changes to Schedule 72, as filed by the Company effective
January 1, 2026; (2) directing the Company to meet with Staff and interested parties to
IDAHO POWER COMPANY'S REPLY COMMENTS - 15

discuss the possibility of implementing a fully voltage-based method, instead of a hybrid
method, for determining the distribution of O&M rates in the future; and (3) finding that
the Company has satisfied its compliance obligation from the 2023 GRC Order No. 36042
to update the O&M charges in Schedule 72, to reflect current operating metrics and
assumptions.
Respectfully submitted this 19t" day of December 2025.
DONOVAN WALKER
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S REPLY COMMENTS - 16

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 191" day of December 2025, 1 served a true and
correct copy of the within and foregoing IDAHO POWER COMPANY'S REPLY
COMMENTS upon the following named parties by the method indicated below, and
addressed to the following:
IPUC COMMISSION STAFF Hand Delivered
Jeffrey R. Loll U.S. Mail
Deputy Attorneys General Overnight Mail
Idaho Public Utilities Commission X Email - eff.loll()puc.idaho.gov
P.O. Box 83720
Boise, ID 83720-0074
IDAHYDRO Hand Delivered
C. Tom Arkoosh U.S. Mail
Nicholas J. Erekson Overnight Mail
Arkoosh Law Offices X Email - tom.arkoosh(a)arkoosh.com
913 W. River St., Ste. 450 nick.erekson(a)arkoosh.com
P.O. Box 2900 erin.cecil(a)arkoosh.com
Boise, ID 83701
RENEWABLE ENERGY COALITION Hand Delivered
Irion Sanger U.S. Mail
Sanger Greene, P.C. Overnight Mail
4031 Se Hawthorne Blvd. X Email - -ion(ab_sanger-law.com
Portland, Or 97214
Stacy Gust
Regulatory Administrative Assistant
IDAHO POWER COMPANY'S REPLY COMMENTS- 17

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-22
IDAHO POWER COMPANY
ATTACHMENT NO. 1

APPLICATION OF IDAHO POWER FOR AUTHORITY
IDAHO POWER - ERIC HACKETT
November 17, 2025
30(b)(6)
ND
DEPOIDAHO
Local Reoltim.e tiCrortinq & Videogrophy Experts PO Box 44385, Boise, I D 83711
0 1 0 . 0 .

Idaho Power - Eric Hackett 30 (b) (6) 11/17/2025
APPLICATION OF IDAHO POWER FOR AUTHORITY
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF IDAHO POWER ) Case No . IPC-E-25-22
COMPANY FOR AUTHORITY TO )
UPDATE ITS OPERATION AND )
MAINTENANCE CHARGES APPLICABLE )
TO SCHEDULE 72, GENERATOR )
INTERCONNECTIONS TO PURPA )
QUALIFYING FACILITY. )
SELLERS . )
RULE 30 (b) (6) DEPOSITION OF IDAHO POWER COMPANY
TESTIMONY OF ERIC HACKETT
TAKEN NOVEMBER 17, 2025
REPORTED BY:
Beverly A. Benjamin, CSR No . 710
Notary Public
DepoIdaho, PO Box 44385, Boise, ID 83711 (208) 345-3704

Idaho Power - Eric Hackett 30 (b) (6) 11/17/2025
APPLICATION OF IDAHO POWER FOR AUTHORITY
Page 2
1 THE RULE 30 (b) (6) DEPOSITION OF IDAHO POWER
2 COMPANY, TESTIMONY OF ERIC HACKETT, was taken on behalf
3 of IdaHydro at the Arkoosh Law Offices, 913 W. River
4 Street, Suite 450, Boise, Idaho, commencing at 9 : 53 a.m.
5 on November 17, 2025, before Beverly A. Benjamin,
6 Certified Shorthand Reporter and Notary Public within
7 and for the State of Idaho, in the above-entitled
8 matter.
9 A P P E A R A N C E S :
10 For IdaHydro:
11 Arkoosh Law Offices
12 BY MR. NICHOLAS J. EREKSON
13 MR. C. TOM ARKOOSH
14 913 W. River Street, Suite 450
15 Boise, Idaho 83701
16 nick.erekson@arkoosh. com
17 [e-mail]
18 For Idaho Power Company:
19 Idaho Power Company
20 BY MR. DONOVAN E. WALKER
21 MS . LISA C. LANCE
22 1221 W. Idaho Street
23 Boise, Idaho 83707
24 dwalker@idahopower. com
25 (Appearances continued. )
DepoIdaho, PO Box 44385, Boise, ID 83711 (208) 345-3704

Idaho Power - Eric Hackett 30 (b) (6) 11/17/2025
APPLICATION OF IDAHO POWER FOR AUTHORITY
Page 3
1 For Idaho Public Utilities Commission :
2 BY MR. JEFF LOLL
3 Deputy Attorney General
4 11331 W. Chinden Blvd. , Building 8
5 Suite 201-A (83714 )
6 Boise, Idaho 83720
7
8 ALSO PRESENT : Ms . Yao Yin
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1 I N D E X
2 TESTIMONY OF ERIC HACKETT PAGE
3 Examination by Mr. Erekson 5
4
5
6 E X H I B I T S
7 NO. DESCRIPTION PAGE
8 Exhibit 2 Interconnection Point/ 6
9 Interconnection Facilities
10 drawing
11
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13
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1 ERIC HACKETT,
2 first duly sworn to tell the truth relating to said
3 cause, testified as follows :
4
5 EXAMINATION
6 QUESTIONS BY MR. EREKSON:
7 Q. Good morning.
8 A. Good morning.
9 Q. Can you please state your full name and spell
10 your last for the record.
11 A. Eric Hackett . Last name is H-A-C-K-E-T-T .
12 Q. Have you ever been deposed before?
13 A. I have not .
14 Q. I ' ll just go over a few ground rules .
15 Everything you say is being stenographically
16 transcribed and recorded, so it is important that you
17 speak clearly and slowly so we can make an accurate
18 record.
19 You are under oath, so it' s important that you
20 tell the truth. If there are any objections, just wait
21 for your attorneys and then you can answer.
22 I see that you came pre-prepared with an
23 exhibit. Do you want to explain what this exhibit is?
24 A. Sure . I ' ll just give a high-level overview,
25 and then if it ' s helpful to go through in any more
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1 detail, happy to do that.
2 But basically, there ' s been some discussion
3 about the four-pole package. It ' s a general term that
4 we utilize at Idaho Power, but what it ' s really meant to
5 portray are the interconnection facilities pursuant to
6 Schedule 72 .
7 So this is just a depiction that I put
8 together to help clarify those facilities that are
9 deemed interconnection facilities . These look similar
10 to what you may actually see out on the road connected
11 to an interconnection facility or to a generator. And
12 thought it might be helpful just to talk through some of
13 the details and some of the equipment that Idaho Power
14 installs on behalf of new generation projects .
15 Q. Thank you.
16 MR. EREKSON: Can we have this just be
17 Exhibit 2 .
18 (Exhibit 2 marked. )
19 Q. (BY MR. EREKSON) Would these be the same for
20 transmission and distribution?
21 A. Substantively they' d be the same . It ' s the
22 same type of equipment where we have disconnect
23 switches, protection equipment, metering equipment.
24 It ' s just at a higher voltage . And so effectively it
25 provides the same service . It just is slightly
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1 different equipment because it ' s typically inside of a
2 substation as opposed to just out at the end of a
3 distribution facility. But the same material equipment .
4 Q. Let me slow you down for a minute.
5 Inside of a substation would be for
6 transmission?
7 A. Correct.
8 Q. Versus outside of a distribution would be for
9 distribution?
10 A. That ' s right.
11 Q. So in layman' s terms, what do these do?
12 A. So I 'm going to work from right to left on
13 this drawing. What we start with is we have an existing
14 Idaho Power system. So you can think about this as a
15 standard distribution overhead feeder running down the
16 side of a road. Typically wooden poles, conductor,
17 that ' s our existing system that is utilized for load
18 service to any number of customers that may be attached
19 to the distribution feeder.
20 So then starting at pole 1 through pole 4,
21 this would be the four-pole package that we install on
22 behalf of whoever the applicant is bringing on their
23 generation facility. So on the far left of the page you
24 see the small yellow dot. That ' s meant to represent a
25 generator of whatever technology. Typically the dark
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1 blue weighted line is facilities installed by the
2 seller. So that could be their own protection
3 equipment, such as a circuit breaker, typically a
4 step-up transformer, and ultimately cables that then
5 connect to Idaho Power system.
6 So you can see left of pole 4 the dashed line,
7 if you can read that it says "point of change
8 ownership. " That ' s an important point because
9 everything to the right is all facilities owned and
10 operated and maintained by Idaho Power; everything to
11 the left would be facilities installed by the seller.
12 So what these represent, again working right
13 to left, is pole 1, we have the first device as you come
14 down the pole is called a disconnect or a disconnect
15 switch. That ' s just a physical switch. It can be
16 fused, but what it does is it actually can disconnect
17 the system in a manual operation if at any time we need
18 to do maintenance on our facilities .
19 So by opening that switch it disconnects all
20 generation and all equipment to the left side of the
21 screen, or the left side of the paper, from Idaho Power
22 system. So there ' s no energy able to transfer at that
23 point.
24 Just below that is a transformer, and that ' s
25 typically used to provide local service . So any of the
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1 rest of this equipment that requires auxiliary power to
2 power the electronics, that would be coming off of that
3 Idaho Power feeder.
4 Coming down the pole is just some equipment
5 that is -- it' s conduit . There ' s some low voltage cable
6 running in that.
7 Q. We ' re still on pole 4?
8 A. Pole 1 .
9 So you can see there ' s some conduit, and it
10 comes down to a box that ' s labeled "AC load center. "
11 That just means alternating current load center. It ' s
12 the piece of equipment we utilize to, again, power these
13 different devices that are electronic in nature.
14 But at the bottom of pole 1 you can see the
15 black lines, the double lines are meant to represent
16 conduit that goes underground and connects to each of
17 the other poles, 2, 3, and 4 .
18 So moving to pole 2, this is where the meter
19 resides . So at the top we have relaying CTs and PTs .
20 And what that stands for is current transformers and
21 potential transformers . So you can see the wires come
22 down into these different devices . They' re simply
23 measurement devices that then have low voltage data
24 cables that run down pole 2, into the box at the bottom
25 labeled "meter box" and "relay test box. "
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1 That ' s equipment that not only will read the
2 meter for settlement purposes, but also provides the
3 intelligent nature of the power electronics that are
4 within the four-pole package.
5 Q. Something goes down, it sends a relay out?
6 A. That ' s right.
7 So again, there ' s conduit over to pole 3 . At
8 the top of pole 3 on the right is what' s labeled
9 "recloser. " That ' s the same thing as a circuit breaker.
10 So that actually can interrupt power as it ' s flowing.
11 Meaning if there ' s a disturbance on the system or a
12 disturbance at the generator, the intelligence of the
13 relay will sense that instability, and then it will tell
14 the recloser to open. And it uses gas-insulated
15 equipment inside of a box. So it actually disconnects
16 the electricity at that point . It creates what ' s called
17 an open. So again, no power can flow left to right,
18 right left at that point.
19 But it ' s the intelligent device that can
20 actually break current, meaning if the generator is
21 generating, or for whatever reason, if there were
22 backflow on the system, this can actually cut that power
23 in real time . As opposed to the disconnect switches are
24 meant to be open once their power is already
25 disconnected.
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1 They' re what we call a visual open so our
2 lineman can go out there and actually see the disconnect
3 switch opened so no power will flow. You can' t see
4 inside of the recloser, and so it ' s just an additional
5 safety device .
6 Q. Double safety?
7 A. Yes .
8 On the left side of that pole is another
9 transformer, and you see it ' s labeled "synchronizing. "
10 What that transformer does is senses voltage and current
11 to ensure that when a generator wants to generate and be
12 synced up with our system, it ' s just another device to
13 make sure that the frequency of the generator is in line
14 with the frequency of our distribution or transmission
15 system so that they aren't off phase or they' re not
16 causing any faults and they run harmoniously.
17 At the bottom of that pole it ' s called the
18 "GINT box, " generation interconnection box. This is
19 where a lot of the control mechanisms are that actually
20 operate the recloser. It also has communication devices
21 so that we can get information back to our remote
22 operation center or load serving operation.
23 And that box is -- also when you come to the
24 left, more conduit comes out and ultimately is an
25 opportunity to have the generator or the seller have
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1 connections so that they can monitor things like the
2 status of the breaker. Is it open? Is it closed? It
3 also provides for some syncing of the generator breakers
4 and the Idaho Power four-pole breakers in case there is
5 some beneficial synchronous tripping to help us protect
6 the system.
7 Then the last pole is another disconnect
8 switch. So between pole 4 and pole 1, any time we were
9 to do maintenance on any of this equipment we would open
10 both of those disconnect switches so we could see
11 physically and visually that there ' s no power that can
12 flow from either the system or the generator.
13 Q. I understand what you're saying. Thank you.
14 That was a lot of information.
15 I take it that you have an advanced degree to
16 be able to explain this in that level of detail . I
17 probably should have covered that at the start. What is
18 your background?
19 A. Sure . So I 'm a civil engineer through
20 education. I graduated from Boise State. I have an MBA
21 also from Boise State. But my primary role is I am the
22 director of our projects and resource development. What
23 that means is my team of project managers works with our
24 matrix organization, which includes our engineers and
25 technicians, to design, procure, and ultimately
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1 construct these facilities on behalf of an executed
2 generation interconnection agreement .
3 Q. Is that all you do?
4 A. That is the primary role as it relates to
5 Schedule 72 .
6 I also have a more generic role of all project
7 management for our infrastructure projects . Generation
8 interconnection agreements are just a small portion.
9 Q. This is a slice of your work.
10 A. This is a slice of the overall project
11 management effort, yes .
12 Q. When I hear the term or I see the term
13 "gen-tie, " can you explain how that relates to what you
14 just explained.
15 A. Yeah. Again, gen-tie can be somewhat of a
16 generic term. But generally what it is referring to are
17 the facilities utilized and built by the seller between
18 the generation facility and the point of change
19 ownership, which is the dashed left line on the left
20 side of pole 4 .
21 What that really means is it ' s generation
22 facilities that are ultimately required to interconnect
23 the generator to Idaho Power system. And that system
24 starts with our existing system. We install the
25 four-pole interconnection package, and at the end of
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1 that four-pole interconnection package we change
2 ownership. And everything beyond that point is
3 generator and gen-tie .
4 Gen-tie usually refers to the circuit or the
5 line . So whether that ' s a distribution extension -- it
6 would typically be at whatever the nominal voltage is on
7 the Idaho Power system.
8 So if a generator generates at some low
9 voltage, maybe 480 volts, it goes through the
10 transformer and steps it up to a typical system voltage,
11 which is either 12 . 5 or 34 . 5 kilovolts . And at that
12 point from the transformer to the point of change
13 ownership is generally determined to be called the
14 gen-tie or the generator .
15 Q. Who maintains the gen-tie?
16 A. The seller maintains the gen-tie .
17 Q. The seller maintains the gen-tie because it is
18 left of the line?
19 A. That ' s right .
20 Q. And then your maintenance would start just
21 right of the line?
22 A. That ' s correct .
23 Q. What sort of things go wrong in these
24 interconnection facilities?
25 A. So these are pretty standard applications
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1 across our system, but they are electronic in nature .
2 So we have and treat these facilities no different than
3 we do the rest of our maintenance practices . So we have
4 devices at substations and we have devices out on
5 distribution facilities, be it transformers, reclosers,
6 capacitors, whatever the device is that keeps the system
7 operational .
8 So not only do they have routine preventative
9 maintenance that occurs, whether that ' s inspection, they
10 have to do some testing, they have to make sure that all
11 these devices are in compliance with the National
12 Electric Reliability Council, or NERC. We also have
13 FERC, which is Federal Energy Regulatory Commission
14 oversight. So all these items have to be maintained
15 such that they' re in compliance . So that ' s from a
16 preventative perspective.
17 And in turn, if anything were to fail, so
18 there can be internal failures on any of the actual
19 electrical equipment, meaning the transformers,
20 reclosers, metering CTs and PTs, if any of those devices
21 were to actually fail, then they would have to be
22 replaced. And they get replaced like they would if they
23 were on any other distribution feeder going to someone ' s
24 house or shop.
25 Q. How often on the preventative side do you send
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1 somebody out there?
2 A. The preventative side, feeders get inspected
3 routinely. These are just considered feeder assets,
4 meaning distribution feeder assets .
5 So as our patrolmen do, I believe it ' s
6 quarterly inspections, that ' s just really from a system.
7 They drive by, they stop, they evaluate, they do visual
8 inspections . Because these pieces of equipment function
9 somewhat similar to substation equipment, where they
10 have electronic controls, then we also have quarterly
11 and more routine annual, and then 3-year compliance
12 cycles where we have to get in and actually test things,
13 like the relay, test things like the recloser
14 functionality, make sure there ' s no contacts broken.
15 So it gets maintained through a number of
16 different avenues and different technician work groups .
17 Q. So it' s not just quarterly. You've got these
18 annual and then these every 3-year type of --
19 A. And I think there ' s a 5-year maintenance cycle
20 depending on the designation of each type of equipment .
21 Q. Just one minute .
22 (Discussion held off the record. )
23 Q. (BY MR. EREKSON ) How long do these systems
24 last?
25 A. They last, I think from an accounting
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1 treatment perspective, they function under our typical
2 FERC accounting rules . But from a practical
3 perspective, which is what I 'm obviously more familiar
4 with, they do last a long time . We 've had them last the
5 life of the generation interconnection agreement,
6 assuming we maintain them appropriately.
7 Q. 35 years?
8 A. 35 years .
9 And maybe just to elaborate a bit. Our
10 obligation under the generation interconnection
11 agreement is to maintain the service throughout the life
12 of the generation interconnection agreement. And that
13 either then gets terminated or it gets renewed.
14 And so the facilities that are installed while
15 the function is maintained, if we have to change
16 something out or maintain it, an individual component of
17 the overall interconnection facilities may have a
18 shorter or longer life . But when we look at the system
19 from an interconnection facilities definition, that will
20 last the life of the generation interconnection
21 agreement.
22 Q. When these are renewed, are they replaced
23 wholesale or do you just step back in and reuse the same
24 equipment?
25 A. It just depends . We ' ll go out and do an
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1 evaluation just like we would when we get an initial
2 application. So we ' ll review the equipment that ' s
3 there, we ' ll review the equipment ' s functionality, and
4 we ' ll review if it meets whatever our current standards
5 are, based on the right types of equipment to install .
6 So we ' ll do the similar studies that we would
7 have otherwise done if it were a new application to
8 evaluate with our engineers and technicians on what the
9 equipment is and whether it ' s capable of serving the
10 purpose as intended.
11 MR. ARKOOSH: We ' re going to take a recess .
12 (Recess taken. )
13 Q. (BY MR. EREKSON) That' s a lot of information.
14 I appreciate it. It' s like drinking from a fire
15 hydrant. You have to take it in.
16 So when these need maintenance, are you the
17 one that oversees the maintenance crew?
18 A. Not my responsibility, no. Purely from a
19 project management, we execute on the initial
20 installation, or if there are any significant repairs
21 that need to be made that need to be managed at a
22 project management level as opposed to just simply
23 maintaining the system, that ' s the only time that my
24 group would come back involved.
25 Q. So it would have to be like a big deal for you
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1 guys to. . .
2 A. It would be something that needs actual design
3 resources or procuring new material . It ' s something we
4 handle and our technicians don' t . But generally if it ' s
5 just for like replacement of some of the components, our
6 technicians can handle that just under their blanket
7 work tasks that they use when they do all their
8 maintenance .
9 Q. What would be an example of something that
10 would rise to your level?
11 A. It would be something in the power electronics
12 typically, meaning down in one of the boxes where it
13 requires an actual subject matter expertise and
14 engineering to put together particular settings .
15 If it ' s just a transformer failure, that ' s
16 very common for our maintenance crews to be able to just
17 handle under our typical maintenance practices . So it
18 would require something where we have to get back
19 involved because there ' s been something that is
20 insurmountable just to be completed by the technicians
21 on-site .
22 Q. Okay. I 'm going to ask you questions. If you
23 don' t know the answer, that' s okay. I just don' t know
24 the extent, like where you pass the baton to somebody
25 else.
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1 When your crew gets deployed and you have to
2 replace something large, does the bill for that
3 replacement ultimately go to the QF? How is that
4 handled? Who pays for that?
5 A. Well, I can tell you from a wholesale
6 perspective, when we 've got back involved on the major
7 replacements, it ' s typically at the time where there ' s
8 been an actual renewal . So there ' s an updated cost
9 estimate to bring the facility into compliance.
10 Most things that we 've done have actually been
11 able to occur in the field or working directly through
12 our team, but under the existing distribution feeder
13 level maintenance activities .
14 Q. So that' s on a renewal . What about if it' s
15 not on a renewal, who would pay for that replacement
16 piece?
17 A. If we were to do -- and we just differentiate
18 that to be just -- again, this is somewhat lingo, what
19 we call a capital project, which just means that Idaho
20 Power, our project management office is involved. That
21 would be set up as a singular task, and it would be
22 handled by Idaho Power under our obligations in
23 Schedule 72 .
24 Meaning Idaho Power' s project management team
25 would be involved, but it would be coordinated with the
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1 techs, and it would be completed more from a practical
2 basis to have project management involved. But it
3 wouldn ' t be something that were billed back to the
4 seller on a unique or distinct request .
5 Q. They wouldn' t get like an invoice for the part
6 or --
7 A. Not once it ' s operational or what we call
8 in-service . I mean, it ' s commercially operational . So
9 if it happens years into the cycle, then it would be,
10 quote, unquote, "operations and maintenance expense"
11 towards that particular feeder that it was connected to .
12 Q. Not invoiced to the seller.
13 A. Not invoiced to the seller.
14 Q. Okay. At that point is it capitalized,
15 becomes part of the capital cost of the project?
16 A. It ' s not . It would go against the 0&M
17 activity.
18 Q. The part as well?
19 A. Yeah.
20 MR. EREKSON: I have no other questions .
21 MR. WALKER: I don' t have any.
22 (Deposition concluded at 10 : 16 a.m. )
23 (Signature requested. )
24
25
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Page 22
1 CERTIFICATE OF WITNESS
2 I, ERIC HACKETT, being first duly sworn, depose
3 and say:
4 That I am the witness named in the foregoing
5 deposition, consisting of pages 1 through 23; that I
6 have read said deposition and know the contents thereof;
7 that the questions contained therein were propounded to
8 me; and that the answers contained therein are true and
9 correct, except for any changes that I may have listed
10 on the Change Sheet attached hereto:
11 DATED this 2 day of D,�, _m0e-�, 20 .
12
13
14
15 ERIC HACKETT
16
17 SUBSCRIBED AND SWORN to before me this - " day
18 of /✓ 202 .
19
CHRISTY L N DAVENPORT
Notari tubli -State of Idaho NAME OF NOTARY PUBLIC
Commissio Number 52970
My Com son pires Sep 10,2026 NOTARY PUBLIC FOR 1 C �
23 RESIDING AT
24 MY COMMISSION EXPIRES
25
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Page 23
1 REPORTER' S CERTIFICATE
2 I, BEVERLY BENJAMIN, CSR No . 710, Certified
3 Shorthand Reporter, certify:
4 That the foregoing proceedings were taken before
5 me at the time and place therein set forth, at which
6 time the witness was put under oath by me.
7 That the testimony and all objections made were recorded
8 stenographically by me and transcribed by me or under my
9 direction.
10 That the foregoing is a true and correct record
11 of all testimony given, to the best of my ability;
12 I further certify that I am not a relative or
13 employee of any attorney or party, nor am I financially
14 interested in the action.
15 IN WITNESS WHEREOF, I set my hand and seal this
16 25th day of November 2025 .
17
18
19
01
apTAR�-.Z
20 _
21 NoG:O BEVERLY A. BENJAMIN' CSR No. 710
7.
OF
1
22 "" Notary Public
23
24
25
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bring communicati CTS
Exhibits A B 20:9 on 9:19 15:20
bringing 11:20 current
EXH 2 Hacket a.m. back 7:22 completed 9:11,20 10:20
t 111725 21:22 11:21 17:23 broken 19:20 21:1 11:10 18:4
4:8 6:17,18 AC 18:24 19:18 16:14 compliance customers
9:10 20:6 21:3 built 15:11,15 16:11 7:18
1 accounting backflow 13:17 20:9 cut
16:2517:2 10:22 component 10:22
1 accurate background C 17:16 cycle
7:20 8:13 9:8,14 5:17 12:18 components 16:19 21:9
12:8 activities based cable 19:5 cycles
10:16 20:13 18:5 9:5 concluded 16:12
21:22 activity basically cables 21:22
12.5 21:17 6:2 8:4 9:24 conductor D
14:11 actual basis call 7:16
15:18 19:2,13 21:2 11:1 20:19 21:7 conduit dark
2 20:8 baton called 9:5,9,1610:7 7:25
additional 19:24 8:14 10:16 11:24 dashed
2 11:4 behalf 11:1714:13 connect 8:613:19
6:17,18 9:17,18, advanced 6:14 7:22 13:1 capable 8:5 data
24 12:15 beneficial 18:9 connected 9:23
agreement 12:5 capacitors 6:10 21:11 deal
3 13:217:5,11,12, big 15:6 connections 18:25
21 18:25 capital 12:1 deemed
3 agreements bill 20:19 21:15 connects 6:9
9:1710:7,8 13:8 20:2 capitalized 9:16 definition
3-year alternating billed 21:14 considered 17:19
16:11,18 9:11 21:3 case 16:3 degree
34.5 annual bit 12:4 construct 12:15
14:11 16:11,18 17:9 causing 13:1 depending
35 applicant black 11:16 contacts 16:20
17:7,8 7:22 9.15 center 16:14 depends
application blanket 9:10,1111:22 control 17:25
4 18:27 19:6 change 11:19 depiction
applications blue 8:7 13:18 14:1, controls 6:7
4 14:25 8:1 12 17:15 16:10 deployed
7:20 8:6 9:7,17 appropriately Boise circuit coordinated 20:1
12:813:20 17:6 12:20,21 8:310:914:4 20:25 deposed
480 ARKOOSH bottom civil correct 5:12
14:9 18:11 9:14,2411:17 12:19 7:714:22 deposition
assets box clarify cost 21:22
5 16:3,4 9:10,24,25 6:8 20:8 21:15 design
assuming 10:1511:18,23 closed Council 12:2519:2
5-year 17:6 boxes 12:2 15:12 designation
16:19 attached 19:12 commercially covered 16:20
7:18 break 21:8 12:17 detail
7 attorneys 10:20 Commission creates 6:112:16
5:21 breaker 15:13 10:16 details
72 auxiliary 8:310:912:2 common crew 6:13
6:6 13:5 20:23 9:1 breakers 19:16 18:17 20:1 determined
avenues 12:3,4 crews 14:13
16:16 19:16
DepoIdaho, PO Box 44385, Boise, ID 83711 (208) 345-3704
Index: 1 to determined

Idaho Power - Eric Hackett 30 (b) (6) 11/17/2025
APPLICATION OF IDAHO POWER FOR AUTHORITY
development effort exhibit flow 5:7,8 in-service
12:22 13:11 5:23 6:17,18 10:17 11:3 graduated 21:8
device elaborate existing 12:12 12:20 includes
8:13 10:19 11:5, 17:9 7:13,1713:24 flowing ground 12:24
12 15:6 Electric 20:12 10:10 5:14 individual
devices 15:12 expense four-pole group 17:16
9:13,22,23 electrical 21:10 6:3 7:21 10:4 18:24 information
11:2015:4,11, 15:19 expertise 12:4 13:25 14:1 11:2112:14
20 19:13 frequency groups 18:13
differentiate electricity 11:13,14 16:16
10:16 explain guys
infrastructur
20:17 electronic 5:2312:16 full g191 e
directly 9:13 15:1 16:10 13:13 5:9 13:7
20:11 explained function
electronics p H initial
director 9:210:319:11 13:14 16:817:1,15 18:1,19
12:22 end extension functionality inside
disconnect 14:5 16:1418:3 H-A-C-K-E-T-
7:2 13:25 T 7:1,5 10:15 11:4
6:22 8:14,16 extent fused
10:23 11:2 12:7, energy 5:11 inspected
10 8:22 15:13 19:24 8:16 Hackett 16:2
disconnected engineer 5:1,11 inspection
10:25 12:19 F G handle 15:9
disconnects engineering 19:4,6,17 inspections
8:1910:15 19:14 facilities gas-insulated 16:6,8
6:5,8,9 8:1,9,11, 10:14 handled
discussion engineers 20:4,22 instability
6:2 16:22 12:24 18:8
1813:1,17,22 g en-tie 10:13
14:24 15:2,5 happy
13:13,15 14:3,4,
distinct ensure 17:14,17,19 6:1 Install
14,15,16,17
21:4 11:11 facility general harmonious) 7:21 13:24 18:5
distribution equipment 6:117:3,23 6:3 y installation
6:20 7:3,8,9,15, 6:13,22,23 7:1,3 13:18 20:9 11:16 18:20
19 11:14 14:5 8:3,20 9:1,4,12 fail generally installed
15:5,2316:4 10:1,1512:9 13:1614:13 hear 8:1,1117:14
15:19 16:8,9,20 15:17,21 19:4 13:12
20:12 installs
disturbance 17:2418:2,5,9 failure generate held
equipment's 19:15 11:11 16:22 6:14
10:11,12 dot 18:3 failures generates helpful insurmounta
EREKSON 15:18 14:8 5:25 6:12 b 19
le
7:24 19:20
double 5:6 6:16,19 familiar generating high-level
16:23 18:13 17:3 10:21 5:24 intelligence
9:15 11:6 21:20 10:12
faults generation higher
drawing Eric 11:16 6:14 7:23 8:20 6:24 intelligent
7:13 5:1,11 Federal 11:1813:2,7,18, house 10:3,19
drinking estimate 15:13 2117:5,10,12, 15:24 intended
18:14 20:9 feeder 20 hydrant 18:10
drive evaluate 7:15,19 9:3 generator 18:15 interconnect
16:7 16:718:8 15:2316:3,4 6:11 7:25 10:12, 13:22
duly evaluation 20:12 21:11 20 11:11,13,25 I interconnecti
5:2 18:1 feeders 12:3,12 13:23 on
EXAMINATIO
16:2 14:3,8,14 Idaho 6:5,9,11 11:18
E N FERC generic 6:4,13 7:14 8:5, 13:2,8,25 14:1,
15:13 17:2 13:6,16 24 17:5,10,12,
INT
5:5 GNT 10,21 9:3 12:4 17,19,20
education execute field 13:2314:7
12:20 18:19 20:11 18 20:19,22,24 internal
effectively executed fire give important 15:18
6:24 13:1 18:14 5:24 5:16,19 8:8 interrupt
Good 10:10
DepoIdaho, PO Box 44385, Boise, ID 83711 (208) 345-3704
Index: developmen to interrupt

Idaho Power - Eric Hackett 30 (b) (6) 11/17/2025
APPLICATION OF IDAHO POWER FOR AUTHORITY
invoice measuremen open pays procuring
21:5 M t 10:14,17,24 20:4 19:3
invoiced 9:23 11:112:2,9 perspective project
21:12,13 made mechanisms opened 15:1617:1,3 12:2313:6,10
involved 18:21 11:19 11:3 20:6 18:19,22 20:19,
18:24 19:19 maintain meets opening phase 20,24 21:2,15
20:6,20,25 21:2 17:6,11,16 18:4 8:19 11:15 projects
items maintained meter operate physical 6:14 12:22 13:7
15:14 8:1015:14 9:18,2510:2 11:20 8:15 protect
16:1517:15 metering operated physically 12:5
K maintaining 6:2315:20 8:10 12:11 protection
18:23 minute operation piece 6:23 8:2
kilovolts maintains 7:4 16:21 8:17 11:22 9:12 20:16 provide
14:11 14:15,16,17 monitor operational pieces 8:25
maintenance 12:1 15:7 21:7,8 16:8 PTS
L 8:18 12:9 14:20 morning operations point 9:1915:20
15:3,9 16:19 5:7 8 21:10 8:7,8,23 10:16, Purely
labeled 18:16,1719:8, moving opportunity 1813:1814:2, 18:18 purpose 11:25
9:10,25 10:8 16,17 20:13 12 21:14
21:10 9 18
11:9 opposed pole 18:10
major 7:20 8:6,13,14
large 7:2 10:23 18:22 purposes
20:6 N
20:2 organization 9:4,7,8,14,18,24 10:2
layman's make 122:24 10:7,811:8,17 pursuant
5:1711:13 National 12:7,813:20
7:11 15:1016:14 15:11 overhead poles 6:5
left managed nature 7:15 7:16 9:17 put
7:12,23 8:6,11, 18:21 9:13 10:3 15:1 oversees 6:7 19:14
13,20,21 10:17, portion
1811:8,24 management NERC 18.17 13:8
13:1914:18 13:7,1118:19, 15:12 oversight portray Q
level 22 20:20,24 nominal 15:14 6:5
12:1618:22 21:2 14:6 overview potential QF
19:10 20:13 managers number 5:24 9:21 20:3
life 12:23 7:1816:15 owned power quarterly
17:5,11,18,20 manual 8:9 6:4,13 7:14 8:5, 16:6,10,17
lineman 8:17 p ownership 10,219:1,2,3,12 questions
11:2 marked 8:8 13:19 14:2, 10:3,10,17,22, 5:6 19:22 21:20
lines 6:18 &m 13 24 11:3 12:4,11 quote
13:23 14:7 21:10
9:15 material 21:16 19:11 20:20,22
lingo 7:319:3 oath P
g Power's
matrix 5:19 2
20:18 0:24R
12:24 package
load objections ctical read 6:3 7:21 10:4 pra
7:17 9:10,11 matter 5:20 ra 21:1
19:13 13:25 14:1 8:7 10:1
11:22 obligation practices MBA 17:10 p
local paper real
15:319:17
12:20 8:21 10:23
s:25 obligations e- re
long meaning 20:22 part p5re P pared
reason
16:23 17:4 10:11,20 15:19 21:5,15,18 10:21
16:419:12
occur pretty
pass p y recess
17:18
longer 20:11 14:25
20:24 19:24 18:11,12
lot means occurs
er
9 rs patrolmen preventative reclos
9:1112:23 16:5 15:8,16,2516:2 10los 11:4,20
18:1312:14 13:2120:19 office pay primary 16:13
20:20 12:2113:4 recloser$
low meant 20:15
6:4 7:24 9:15 on-site procure 15:5,20
9:5,23 14:8 10:24 19:21 12:25
DepoIdaho, PO Box 44385, Boise, ID 83711 (208) 345-3704
Index: invoice to reclosers

Idaho Power - Eric Hackett 30 (b) (6) 11/17/2025
APPLICATION OF IDAHO POWER FOR AUTHORITY
record resources set starts systems transformers
5:10,18 16:22 19:3 20:21 13:24 16:23 9:20,21 15:5,19
recorded responsibilit settings state transmission
5:16 y 19:14 5:9 12:20,21 T 6:20 7:6 11:14
referring 18:18 settlement status treat
13:16 rest 10:2 12:2 talk 15:2
refers 9:115:3 shop stenographic 6:12 treatment
14:4 reuse 15:24 ally task 17:1
Regulatory 17:23 shorter 5:15 20:21 tripping
15:13 review 17:18 step tasks 12:5
relates 18:2,3,4 side 17:23 19:7 truth
13:4,13 rise 7:16 8:20,21 step-up team 5:2,20
relating 19:10 11:8 13:20 8:4 12:23 20:12,24 turn
5:2 road 15:2516:2 steps technician 15:17
relay 6:10 7:16 signature 14:10 16:16 type
9:2510:5,13 role 21:23 stop technicians 6:2216:18,20
16:13 12:2113:4,6 significant 16:7 12:25 18:8 19:4, types
relaying routine 18:20 studies 6,20 18:5
9:19 15:816:11 similar 18:6 technology typical
Reliability routinely 6:9 16:9 18:6 subject 7:25 14:1017:1
15:12 16:3 simply 19:13 techs 19:17
remote rules 9:2218:22 Substantivel 21:1 typically
11:21 5:14 17:2 singular y term 7:1,16,25 8:3,25
renewal run 20:21 6:21 6:3 13:12,16 14:6 19:12 20:7
20:8,14,15 9:2411:16 slice substation terminated
renewed running 13:9,10 7:25 16:9 17:13 U
17:13,22 7:15 9:6 slightly substations terms
repairs 6:25 15:4 7:11 ultimately
18:20 S slow switch test 8:4 11:24 12:25
replace 7:4 8:15,19 11:3 9:25 16:12,13 13:22 20:3
20:2 safety slowly 12:8 testified underground
replaced 11:5,6 5:17 switches 5:3 9:16
15:2217:22 Schedule small 6:2310:23 testing understand
replacement 6:6 13:5 20:23
7:24 13:8 12:10 15:10 12:13
19:5 20:3,15 screen someone's sworn thing unique
replacements 8:21
15:23 5:2 10:9 21:4
20:7 seller sort synced things unquote
represent 8:2,1111:25
14:23 11:12 12:1 14:23 21:10
7:24 8:12 9:15 13:17 14:16,17 speak synchronizin 16:12,13 20:10 updated
request 21:4,12,13 5:17 g thought 20:8
21:4 send spell 11:9 6:12 utilize
requested 15:25 5:9 synchronous time 6:4 9:12
21:23 sends standard 12:5 8:17 10:23 12:8 utilized
require 10:5 7:15 14:25 syncing 17:4 18:23 20:7 7:17 13:17
19:18 sense standards 12:3 top
required 10:13 18:4 system 9:1910:8 V
13:22 senses stands 7:14,17 8:5,17, transcribed
requires 11:10 9:20 2210:11,22 5:16 Versus
9:119:13 service start 11:12,1512:6, transfer 7:8
resides 6:25 7:18 8:25 7:13 12:17 12 13:23,24 8:22
14:710 15:16 VISU81
, ,
9:19 17:11 14:20 transformer 11:116:7
16:6 17:18
resource serving starting 18:23 8:4,2411:9,10 Visually
12:22 11:2218:9 7:20 14:10,1219:15 12:11
DepoIdaho, PO Box 44385, Boise, ID 83711 (208) 345-3704
Index: record to visually

Idaho Power - Eric Hackett 30 (b) (6) 11/17/2025
APPLICATION OF IDAHO POWER FOR AUTHORITY
voltage
6:24 9:5,23
11:10 14:6,9,10
volts
14:9
W
wait
5:20
WALKER
21:21
weighted
8:1
wholesale
17:23 20:5
wires
9:21
wooden
7:16
work
7:12 13:9 16:16
19:7
working
8:12 20:11
works
12:23
wrong
14:23
Y
years
17:7,8 21:9
yellow
7:24
DepoIdaho, PO Box 44385, Boise, ID 83711 (208) 345-3704
Index: voltage to yellow

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GENERATION 4-POLE
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FACILITIES
EX-IBIT: I I
WITNESS: 9A Q167"r
DEPOIDAHO