Comments_Response to Petition

CERTIFICATE OF ATTORNEY

ASSERTION THAT INFORMATION CONTAINED IN AN IDAHO PUBLIC UTILITIES
COMMISSION FILING IS PROTECTED FROM PUBLIC INSPECTION

Idaho Hydroelectric Power Producers Trust’s Petition for Idaho Power Company
to Reduce Its Operation and Maintenance Charges Applicable to Schedule 72,
Generator Interconnections to PURPA Qualifying Facility Sellers

Case No. IPC-E-26-15

The undersigned attorney, in accordance with Commission Rules of Procedure 67,
believes that the Exhibit No. 2 to Idaho Power Company’s Comments and Response to
Petition, dated October 15, 2026, contains information that Idaho Power and/or a third
party claim constitutes trade secrets or other confidential business data exempt from
disclosure under Idaho Code § 74-101, et seq., and/or § 48-801, et seq. As such, it is
protected from public disclosure, inspection, examination, or copying.

DATED this 15th day of October 2026.

Donovan E. Walker
Counsel for Idaho Power Company

IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 1
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]
[e-mail]
[e-mail]

Attorneys for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE IDAHO
HYDROELECTRIC POWER PRODUCERS
TRUST’S PETITION FOR IDAHO POWER
COMPANY TO REDUCE ITS OPERATION
AND MAINTENANCE CHARGES
APPLICABLE TO SCHEDULE 72,
GENERATOR INTERCONNECTIONS TO
PURPA QUALIFYING FACILITY SELLERS
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CASE NO. IPC-E-26-15

IDAHO POWER COMPANY’S
COMMENTS AND RESPONSE TO
PETITION

COMES Now, Idaho Power Company (“Idaho Power” or “Company”), and,
pursuant to Idaho Public Utilities Commission’s (“Commission”) Rules of Procedure 201-
204; the Notice of Modified Procedure, Order No. 37145, entered August 31, 2026; and
the Notice of Modified Schedule, Order No. 37192, entered October 2, 2026, hereby
respectfully submits the following Comments and Response to the Petition filed by Idaho
Hydroelectric Power Producers Trust (“IdaHydro”) on May 19, 2026.

IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 2
I. PROCEDURAL BACKGROUND
As summarized in the Commission’s Notice of Petition in this case, Order No.
37097, on May 8, 2025, Idaho Power filed an Application in Case No. IPC-E-25-22
requesting Commission approval to update the monthly operations and maintenance
(“O&M”) charges contained in Schedule 72, Generator Interconnections to Public Utility
Regulatory Policies Act of 1978 (“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) and were intended to reflect current operating metrics and
assumptions. In Case No. IPC-E-25-22, IdaHydro did not dispute the proposed updates
to the inputs or calculation used to determine the Schedule 72 O&M charges. Case No.
IPC-E-25-22, Order No. 36894 at 5. Instead, IdaHydro challenged the underlying
methodology that the Commission previously approved for calculating those charges, i.e.,
the system-average methodology, and advocated for a methodology based on directly
assigning actual costs to individual Qualifying Facilities (“QFs”). Id. at 5-6
The Commission rejected IdaHydro’s challenge in Case No. IPC-E-25-22, finding
that the proceeding was limited to updating the inputs used in the existing O&M charge
calculation and was not intended to revisit the validity of the Commission-approved
methodology. Id. at 12. The Commission explained that any party seeking
reconsideration of the system-average methodology could request that the Commission
open a separate proceeding dedicated to that issue. Id. The Commission also
recognized that any alternative methodology, including one based on directly assigning
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 3
actual O&M costs, warrants careful examination and consideration of its broader
regulatory and operational impacts before being adopted. Id.
On May 19, 2026, IdaHydro filed a Petition asking the Commission to re-examine
the system-average methodology and update Idaho Power’s Schedule 72 O&M charges
from the currently approved system-average methodology to actual costs, citing to the
Commission’s final Order No. 36894 from Case No. IPC-E-25-22. In its Petition at 9-10
IdaHydro states, “[t]he factual record relevant to this Petition was substantially developed
in Case No. IPC-E-25-22 through Idaho Power’s Application and supporting testimony,
the written comments of Staff and intervenors, supplemental comments, written
discovery, and deposition testimony of Idaho Power witnesses.” Idaho Power agrees and
requests that the Commission take administrative notice of its files and records developed
and contained in Case No. IPC-E-25-22 which are based upon the same allegations,
complaints, and requests of IdaHydro reiterated in its Petition.1
II. COMMENTS
A. The Commission’s Implementation of Schedule 72 is Lawful
Under PURPA, Federal Law, and Federal Regulations.

The Commission has implemented a schedule of O&M charges applicable to
PURPA QF interconnections that is lawful; consistent with PURPA and federal

1 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 in the previous
proceeding (IPC-E-25-22). For completeness of the record, Idaho Power filed the fourth deposition taken,
the deposition of Eric Hackett, in the previous proceeding. For the Commission’s convenience, Idaho
Power attaches hereto and files herewith the four deposition transcripts referred to by IdaHydro as Exhibit
No’s 1 through 4 respectively.
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 4
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.
1. History of Implementation
The Commission first adopted Schedule 72, governing the interconnection of
PURPA 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 Schedule 72. When a PURPA QF interconnects to the Company’s
system, the QF pays the capital cost of the facilities necessary to connect the project 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 O&M costs of the addition of the QF project and the
infrastructure required to interconnect it to the Company’s bulk electric system.
The entirety of IdaHydro’s allegations and complaints are intended to call into
question the legality of the methodology used in Schedule 72 and IdaHydro attempts to
rewrite the language of Order No. 36894 asserting a determination was made that the
current methodology is not lawful. In fact, the Commission approved the Company’s
methodology for updating Schedule 72 and simply said if, “IdaHydro or any other party
desire a full re-examination of the system average methodology, they may petition the
Commission to open a docket for that purpose.” Order No. 36894 at 12. The legality of
the methodology established and implemented by the Commission and by Schedule 72
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 5
has long been established and upheld by the Commission. In fact, the Commission has
specifically addressed these very 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 at 1, 2, 4. Order No. 24025 remains a
final Order. The collateral attack on the fundamental premise of Order No. 24025 by
IdaHydro was not appropriate in Case No. IPC-E-25-22 nor is it appropriate in this case.
The Commission addressed and settled the issues IdaHydro attempts to argue over three
decades ago and issued a final order. However, irrespective of the collateral attack nature
of IdaHydro’s allegations, its legal challenge fails as the Commission’s implementation of
Schedule 72’s O&M charges to QFs 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 PURPA
requires that Idaho Power’s retail customers be insulated from and held indifferent to.
2. Customer Indifference
The Commission approved Schedule 72, including its particular schedule of O&M
charges, in 1991 and Idaho Power has implemented the same for the last 35 years for all
PURPA QFs interconnecting to Idaho Power’s system in Idaho. A bedrock principle and
core concept in the Commission’s 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
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 6
“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).
The Commission’s implementation of Schedule 72’s O&M charges maintains
customer indifference, as required by PURPA, by allocating the incremental cost to the
utility’s system as a result of the QF’s interconnection, additional infrastructure, and
resulting increase in operation and maintenance expenses. The mechanism implemented
by the Commission, in its basis of average system O&M costs, conform with this goal as
this is the cost that retail customers are allocated, and by having the QFs pay for their
incremental portion, customers are held indifferent to what would otherwise be an upward
rate pressure, or cost shift. This is what PURPA requires, and the Commission’s adoption
of Schedule 72’s O&M charges is not only a valid and legal implementation under PURPA,
but also by design matches the impact imposed upon Idaho Power’s customers.
3. All Interconnection Costs for the Surrogate or Proxy Avoided
Resource are Included in the Avoided Cost Rates Paid to QFs
and Thus it is Appropriate and Lawful to Assess
Interconnection O&M Costs to QFs Through Schedule 72.

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. “Each qualifying facility shall be obligated to pay any interconnection costs which
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 7
the State regulatory authority [the Commission] (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 …” 18 C.F.R. § 292.306.
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
for interconnection in Schedule 72. Petition at 16-17, 20-21; Case No. IPC-E-25-22,
IdaHydro Supplemental Comments at 2, 7. This is not the correct interpretation or
implementation of FERC’s definition of interconnection costs cited above. Another QF
party intervening in Case No. IPC-E-25-22, Renewable Energy Coalition (“REC”), also
addressed this in its Comments filed on September 16, 2025. In particular, REC correctly
pointed 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
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 8
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 4.
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’s
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, and
as acknowledged by REC in Case No. IPC-E-25-22, 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, 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 72,3 the Commission
found, on reconsideration, Schedule 72’s 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. This remains the same and true today. Idaho Power’s administratively
determined avoided cost rates still contain interconnect costs for the proxy, or avoided,
resource and the same previously approved methodology is used to calculate the O&M
charges in Schedule 72.
It is clear that both of Idaho Power’s Commission-approved avoided cost rate
methodologies include interconnection and O&M costs in the rates paid to QFs for their
generation. See also, Exhibit No. 3, Deposition of Andres Valdepena-Delgado at 11-18.

2 See, Idaho Power Reply Comments in Case No. IPC-E-25-22, October 14, 2025, at 11-13; and
Attachment 1 to Idaho Power’s October 14, 2025, Reply Comments, Idaho Power’s Supplemental
Response to IdaHydro’s Interrogatory No. 8.
3 Case No. IPC-E-90-20, Order No. 24025, at 1,2,4.
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 9
Both 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, contain and account for interconnection, network upgrade, and O&M
costs associated with the proxy or surrogate resource that the utility is assumed to avoid
in the establishment of the avoided cost rates set by such methodologies, as shown
below. The QF is therefore compensated through the avoided cost rate paid to it for the
avoided interconnection and associated O&M costs of the utility.
SAR Methodology:
For the SAR methodology, the surrogate avoided resource is a combined-cycle
natural gas combustion turbine. Interconnection costs, including the gen-tie, are included
in the capital cost component of the avoided cost rate methodology. Non-fuel costs,
including capital cost, fixed O&M, and variable O&M, are included in the methodology
and are based on the Northwest Power and Conservation Counsel’s Sixth Power Plan
and set by Commission Order No. 30738.
Capital Cost: $1,313/kW
Fixed O&M: $14.57/kW
Variable O&M: $1.77/MWh
O&M Escalation Rate: 2.0%

ICIRP Methodology:
For the ICIRP Methodology, the proxy capacity resource is a simple-cycle natural
gas combustion turbine (“SCCT”). The ICIRP methodology, rather than having capital
components set by separate Commission order as is done with the SAR methodology,
uses the proxy costs from Idaho Power’s acknowledged Integrated Resource Plan
(“IRP”). Interconnection costs and associated O&M, as well as the network upgrades to
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 10
interconnect the project to Idaho Power’s system, are included in the levelized cost of the
SCCT proxy capacity resource from the 2025 IRP. The values below are from Appendix
C of the 2025 IRP.
Network Upgrades: $191/kW
Fixed O&M: $0.80/kW-mo.
O&M Escalation Rate: 2.40%

In short, the record demonstrates that the avoided cost rates paid to the QF include
compensation for avoided interconnection costs, including O&M. See IPC-E-25-22, Idaho
Power Company’s Reply Comments at 7, footnote 2.
As a result, absent Schedule 72’s O&M charge, customers would pay twice for
O&M on the facilities needed to interconnect a QF: once via O&M costs incurred by the
Company in relation to owning and maintaining such facilities, and again via the avoided
cost rate. To ensure that customers are held indifferent to upward pressure on rates as
a result of the Company’s purchase from the QF, Schedule 72’s O&M charges properly
recover the O&M costs relating to the interconnection of the QF. Because QFs are paid,
in the avoided cost rates, for all of the avoided interconnection costs that the Company
would have incurred absent the QF’s interconnection, 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.
The Commission has found reasonable interconnection costs were included in
the administratively determined avoided cost rate as required by FERC. Order 24025 at
4. The Commission has also found the system-average framework methodology
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 11
reasonable in Order No. 240254, and Staff “maintains that the system-average framework
underlying Schedule 72 is reasonable.” Staff Supplemental Comments at 2, Case No.
IPC-E-25-22. IdaHydro’s argument that the “Commission has no lawful basis to authorize
Schedule 72 as proposed”5 is simply not true. The Commission retains the authority to
determine the avoided cost rate and the methodology under Schedule 72.
B. Actual vs. System-Average Cost
IdaHydro’s proposal to implement an actual cost basis in place of the currently
approved system-average cost basis would not account for the costs and impacts
imposed by the addition of the QF to Idaho Power’s system and would cause an
impermissible cost shift to Idaho Power’s retail customers, contrary to PURPA’s
requirements. Additionally, Idaho Power’s system of accounts, work orders, and work
flows are not designed nor set up to provide such actual tracking.
IdaHydro 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
72 in 19906 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 and infrastructure. System-average O&M charges are
applied to QFs to ensure administrative efficiency, fairness across projects, consistency
with Commission precedent, and to assure the impacts of adding the QF and its

4 at 4, 8.
5 IPC-E-25-22, Supplemental Comment of IdaHydro at 8.
6 As approved by the Commission in Case No. IPC-E-90-20, Order No. 23631, Reconsideration Order
24025.
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 12
generation to the system are captured and not improperly transferred or shifted to the
Company’s retail customers.
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.
Accordingly, 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 its interconnection. The Commission found this methodology reasonable in
Order No. 240257, and in the prior proceeding in Case No. IPC-E-25-22, Staff
“maintain[ed] that the system-average framework underlying Schedule 72 is reasonable.”
Case No. IPC-E-25-22, Staff Supplemental Comments at 2.
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 its 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 services, facilities charges, and Open Access Transmission Tariff rates for
transmission 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

7 at 4, 8.
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 13
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.
However, once constructed, the interconnection facilities necessitated by QFs become a
part of Idaho Power’s overall system (“QF interconnection facilities”) and are
indistinguishable from the rest of the Company’s system.
The QF interconnection 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. Moreover,
maintenance is currently performed via “blanket work order,” which is not specific to an
asset, but rather to a function such as “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.
Staff correctly noted 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.” Case No. IPC-E-25-22, Staff Supplemental Comments
at 3. Staff went 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.
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 14
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 Schedule 72’s existing methodology 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 the Company’s retail customers. 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 matches to the impact
imposed upon Idaho Power’s customers.
Finally, IdaHydro incorrectly characterizes total O&M costs exceeding construction
costs as over-recovery. Schedule 72’s O&M charges capture costs that increase by the
expansion of the Company’s system to accommodate the addition of the facilities required
by the QF’s interconnection. Specifically, 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. That incremental portion paid by the QF is then deducted from what
is included in retail customers’ rates for system O&M. As such, 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.
III. CONCLUSION
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
IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 15
required by FERC, and that the underlying methodology to calculate Schedule 72’s O&M
charges reasonable. Order. No. 24025 at p. 4, 8.
Idaho Power respectfully submits that IdaHydro’s criticism of the Company is
misplaced and misconstrued given the clear history of the Commission’s implementation
of interconnection costs in avoided cost 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 an order
dismissing IdaHydro’s Petition and affirming the lawfulness, appropriateness, and
reasonableness of Schedule 72 and its associated methodology as it exists today.
Respectfully submitted this 15th day of October 2026.

DONOVAN WALKER
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO PETITION – 16
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 15th day of October 2026 I served a true and
correct copy of IDAHO POWER COMPANY’S COMMENTS AND RESPONSE TO
PETITION upon the following named parties by the method indicated below, and
addressed to the following:

Commission Staff
Erika K. Melanson
Deputy Attorney General
Idaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, Idaho 83720-0074

Hand Delivered
U.S. Mail
Overnight Mail
FAX
X Email [e-mail]

IdaHydro
C. Tom Arkoosh
Nicholas J. Erekson
ARKOOSH LAW OFFICES
913 W. River Street, Suite 450
P.O. Box 2900
Boise, ID 83701

Hand Delivered
U.S. Mail
Overnight Mail
FAX
X Email [e-mail]
[e-mail]
[e-mail]

________________________________
Christy Davenport
Legal Administrative Assistant

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-26-15

IDAHO POWER COMPANY

EXHIBIT NO. 1

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) Case No. IPC-E-25-22
OF IDAHO POWER COMPANY FOR )
AUTHORITY TO UPDATE ITS OPERATION)
AND MAINTENANCE CHARGES )
APPLICABLE TO SCHEDULE 72, )
GENERATOR INTERCONNECTIONS TO )
PURPA QUALIFYING FACILITY )
SELLERS, )
_________________________________)

DEPOSITION OF IDAHO POWER COMPANY
TESTIMONY BY RILEY MALONEY
Tuesday, November 18, 2025
Pages 1 - 41

REPORTED BY:
SARAH L. GOEKLER, CSR No. 1178
Notary Public
Page 2
1 THE DEPOSITION OF RILEY MALONEY was taken on
2 behalf of the IDAHO POWER COMPANY, TESTIMONY BY RILEY
3 MALONEY at the offices of Arkoosh Law Offices, 913 W.
4 River Street, Suite 450, Boise, Idaho, commencing at
5 8:58 a.m. on Tuesday, November 18, 2025, before Sarah L.
6 Goekler, Certified Shorthand Reporter and Notary Public
7 within and for the State of Idaho, in the above-entitled
8 matter.
9
10 APPEARANCES:
11
12 FOR IDAHYDRO:
13 ARKOOSH LAW OFFICES
NICHOLAS J. EREKSON, ESQ.
14 C. TOM ARKOOSH, ESQ.
913 W. River Street, Suite 450
15 Boise, Idaho 83701
[e-mail]
16 [e-mail]
17
18 FOR IDAHO PUBLIC UTILITIES COMMISSION:
19 DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
20 ERIKA K. MELANSON, ESQ.
11331 W. Chinden Blvd., Building 8
21 Suite 201-A (83714)
Boise, Idaho 83720
22 [e-mail]
23
24
25
Page 3
1 APPEARANCES (CONTINUED):
2
3 FOR IDAHO POWER:
4 IDAHO POWER COMPANY
DONOVAN E. WALKER, ESQ.
5 1221 W. Idaho Street (83702)
Boise, Idaho 83707
6 [e-mail]
7
8 ALSO PRESENT:
9 Connie Aschenbrenner, Idaho Power
10 Lisa Lance, Idaho Power
11 Yao Yin, Public Utilities Commission
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1 I N D E X
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3 TESTIMONY OF RILEY MALONEY PAGE
4 Examination by Mr. Erekson ...........................5
5 Examination by Mr. Walker ...........................38
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10 Exhibit 3 Transmission Monthly Operations and 26
Maintenance Charge; 1 page
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1 Tuesday, November 18, 2025 8:58 a.m.
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3 RILEY MALONEY,
4 having first been duly sworn by a Certified Shorthand
5 Reporter for the State of Idaho, was examined and
6 testified as follows:
7 EXAMINATION
8 BY MR. EREKSON:
9 Q. Good morning. Can you please state your full
10 name for the record and spell your last name for the
11 record?
12 A. Yeah. My name is Riley Maloney,
13 M-A-L-O-N-E-Y.
14 Q. And, Riley, have you been deposed before?
15 A. No.
16 Q. I'm just going to go over a few ground rules,
17 first of which is, it's a question and answer. I'll ask
18 the questions, you answer. Second is, you were just
19 sworn in. So make sure -- you are under oath under the
20 penalty of perjury. You need to produce truthful
21 content. The third is, this is stenographically
22 recorded, and so it's preferable if you use things like
23 yeses instead of mm-hm, and head nods won't work either.
24 Do you understand?
25 A. Yes.
Page 6
1 Q. Okay. All right.
2 So we're here today -- Idaho Power has filed
3 an application to update the Schedule 72 charges, and
4 initially offered testimony and support.
5 So can you provide a little bit about your
6 background before we jump into this?
7 A. Yeah. So I'm a Policy and Strategy Leader at
8 Idaho Power in the Regulatory Affairs Department. And,
9 there, I oversee the provision of regulatory supports
10 and strategic guidance related to kind of, like,
11 integrated resource planning, demand side management,
12 wildfire activities, among other various topics.
13 Q. Okay. How long have you been in this role?
14 A. I've been in my current role for a little bit
15 less than a year, but I've been with Idaho Power for --
16 coming up on five years now.
17 Q. Five years?
18 A. Yeah.
19 Q. What'd you do prior to that?
20 A. When I first started at Idaho Power, I was in
21 tariff admin, so working a lot with Commission rules
22 and --
23 (Reporter interruption; off the record.)
24 BY MR. EREKSON:
25 Q. So what'd you get hired on as for Idaho Power?
Page 7
1 A. Yeah, so when I first started, I was working
2 in tariff admin. So working a lot with Commission rules
3 and company's Commission-approved tariffs. So ensuring
4 compliance with all the rules either the Commission
5 requires or that is stated within our tariff.
6 Q. And including 72, Schedule 72 or different
7 tariffs?
8 A. Primarily different tariffs, Schedule 72 to a
9 very limited extent --
10 Q. Okay.
11 A. -- just because there are some synergies with
12 Schedule 72 to what we refer to as rule age, which is
13 kind of distribution interconnects for customers.
14 Q. Okay. And then prior to working at
15 Idaho Power, where did you work?
16 A. I was at a nonprofit called Boise Valley
17 Economic Partnership.
18 Q. How long were you there?
19 A. A little less than two years.
20 Q. And what was your role?
21 A. So I was conducting economic research and
22 project management for prospective businesses wanting to
23 relocate to the Valley.
24 Q. What kind of research?
25 A. So, like, demographic research. Mostly when
Page 8
1 businesses would want to either relocate here or expand
2 their operations -- they were really interested in kind
3 of the talent pipeline.
4 Q. Was it qualitative? Quantitative? Both?
5 A. Both.
6 Q. You did work with, like, models, like economic
7 models?
8 A. Yes.
9 Q. Okay. And then prior to that?
10 A. I was at a firm that was outside of
11 San Francisco. It was called Research Data Group. So
12 at that firm -- they had an office in Boise, and so at
13 that firm, working with publicly traded companies that
14 were filing their 10-Ks and 10-Qs with the SEC.
15 Q. Okay.
16 A. So mostly kind of on the formatting side.
17 So -- I'm not sure if you're familiar with the term
18 EDGAR. That's the SEC's kind of electronic database
19 where all the files get electronically submitted. So
20 mostly just formatting to ensure they look good in HTML
21 format, but also ensuring compliance, to some extent,
22 with the SEC requirements.
23 Q. Was that your first job out of college?
24 A. It was.
25 Q. Okay. And where'd you go to school?
Page 9
1 A. Boise State.
2 Q. What did you -- what's your degree in?
3 A. Economics.
4 Q. Master? Bachelor's?
5 A. Bachelor's.
6 Q. Okay. Did you -- any particular area within
7 economics that you focused on?
8 A. No. Just general.
9 Q. Did you have an honor's, like a dissertation
10 or some kind of senior capstone project?
11 A. No. I mean, there was a -- there was a
12 renewable project that -- I don't know if I'd call it
13 honor's or capstone, but if you -- it was displayed, and
14 I forget the name.
15 Q. Was it energy related?
16 A. Yeah. Because I was in an environmental
17 economics course --
18 Q. Okay.
19 A. -- but, I mean, very far distance from what
20 we're talking about here.
21 Q. Okay. Fair enough.
22 So you filed -- well, you provided some
23 testimony that you gave in response to questions as far
24 as changing the current tariff of the 72 schedule.
25 So, I guess, in your words, why does
Page 10
1 Idaho Power want to make this change?
2 A. Well, it primarily results from provision out
3 of our '23 general rate case settlement stipulation
4 where we agreed to update Schedule 72 to reflect current
5 operating assumptions and metrics. So that is what has
6 prompted the update to a previously Commission-approved
7 methodology where we're just updating operating
8 assumptions and metrics to reflect more current costs.
9 Q. So you're proposing changing from an escalated
10 rate to just an average rate?
11 A. Correct -- a levelized rate.
12 Q. A levelized rate.
13 And that's different than some kind of
14 average?
15 A. The 35-year de-levelized or inclining rate
16 that is currently under Schedule 72 uses the same
17 underlying basis as what we're proposing for the fixed
18 levelized rate.
19 Q. Okay. And under the current schedule, it's
20 over 35 years. It says de-levelize, but it's
21 escalating -- correct? -- over the 35 years?
22 A. Yeah, right. So it's de-levelized on the
23 beginning half and then escalates on the latter half.
24 Q. The idea being that a QF has more operating
25 and maintenance over time?
Page 11
1 A. That is what the argument was at the time that
2 the Commission required us to implement that.
3 Idaho Power -- my understanding is at the time when this
4 was established, we did not advocate for that kind of
5 treatment. We had advocated for a levelized, but
6 ultimately the Commission asked that we implement a
7 de-levelized approach for a number of reasons.
8 Q. So just for purposes of this record, can you
9 explain how the -- how the rates would increase over
10 time in a de-levelized approach?
11 A. Are you asking under Schedule 72 as it
12 currently exists --
13 Q. Exactly.
14 A. -- why did the rates escalate?
15 Q. Yeah. Just explain how they escalated.
16 A. At the end of the day, we're trying to get to
17 the same amount. And so as I had previously mentioned,
18 the de-levelized rate is using the same underlying
19 amount. It's just de-levelized. Right?
20 So the very beginning amounts are lower,
21 whether there's an inflation adjustment and some other
22 assumptions that are included that then -- because the
23 rate is lower on the front end, then we have to kind of
24 ramp it up over time to ensure at the very end of that
25 35-year period, it's more or less equal to what we would
Page 12
1 have recovered had a levelized rate just been
2 established throughout the entirety of that period.
3 Q. So a QF in Years, you know, 1 through 5 pays
4 less in interconnection O&M than a QF in Year 20, just
5 to break it down; correct?
6 A. That's correct.
7 Q. Okay. And then at the end of that 35-year
8 rate, just for the record, what happens?
9 A. It switches to a levelized rate, so exactly
10 what we're proposing here.
11 Q. Okay. Now -- let's see.
12 So we're switching from this escalating to a
13 de-levelized -- that kind of creates winners and losers.
14 Right. There's some people that will pay more and some
15 that will pay less?
16 A. Depending on where they're at on the current
17 schedule, yes.
18 Q. So if they're past some kind of median tipping
19 point, you know, closer to Year 35, the current
20 schedule, they're going to pay less?
21 A. Correct.
22 Q. But if they were before that, that tipping
23 point, they're going to pay more just by virtue of kind
24 of an accounting change?
25 A. Yeah. Although I would also clarify, had we
Page 13
1 not changed it -- I mean, they will eventually pay more
2 over time. Right? And so long-term, they should be
3 indifferent to the change; it's more of a cash flow.
4 Because, again, we're targeting that same levelized
5 amount. Right?
6 Q. Yeah, but you're talking, like, if they
7 renewed. But -- I mean, the ones that switch over
8 they're not just going to -- it's not necessarily just
9 dollar for dollar; right?
10 A. Correct.
11 Q. There's winners and losers?
12 A. Again, depending upon where they're at on that
13 schedule, but had -- had we maintained the same
14 schedule, we would be targeting that same fixed amount.
15 Q. Okay.
16 A. And so, yes, today they may pay more, but over
17 that 35-year period, they would pay the same amount.
18 Q. Okay. In your testimony, you talked about the
19 simplification?
20 A. Mm-hm.
21 Q. I mean, it's apparent -- I can see the
22 simplification when you explain it. But are there other
23 ways in which this change would simplify things for
24 Idaho Power?
25 A. Well, it's also kind of reflective of the
Page 14
1 current environment in which PURPA contracts are
2 established, I mean, when this methodology was first
3 implemented. My understanding is most contracts are
4 roughly 35 years in length, and now they can range from
5 2 to 20 years.
6 So to really reflect that variability, a
7 levelized rate is more appropriate so that you don't
8 have folks falling off after the first couple of years,
9 and -- I mean, there is a subsidy occurring there in the
10 first couple of years where they're not paying the full
11 operation of maintenance costs. Right? And so to have
12 a levelized, that ensures that we're appropriately
13 recovering.
14 Q. And are those mostly, like, wind and solar
15 folks that have the shorter contracts?
16 A. I believe so, but I'm not an expert in that
17 area.
18 Q. Fair enough.
19 So now, are there less assumptions used, I
20 think, in the method that you're proposing to switch to
21 than the prior method?
22 A. Yeah. We don't have to assume, like, an
23 inflation factor or other various things. It's much
24 more straightforward.
25 Q. It's a simpler calculation; right?
Page 15
1 A. Correct.
2 Q. Can you explain what the calculation is?
3 A. Yeah. So, I mean, at a very high level, we're
4 essentially taking the proportion of either distribution
5 or transmission plant, identifying what proportion of
6 O&M-related costs should apply to that plant. And so
7 maybe a better way of framing this -- so for
8 transmission, because that's a cleaner example, we look
9 to determine how -- what proportion of overall
10 transmission plant should be allocated to O&M costs in
11 respect to Schedule 72's monthly charge.
12 Q. And you used the term O&M broadly, but I think
13 you're specifically referring to interconnection O&M?
14 A. I'm referring to system-level transmission
15 O&M, which we then proportion or allocate a portion of
16 to Schedule 72.
17 Q. And then you do that based on the relative
18 size of the initial capital investment?
19 A. So when we're developing the monthly rate for
20 transmission, as we have currently proposed -- right now
21 on Schedule 72, there's a 138 kV, and a 161 kV amount
22 that's contemplated of, I believe, it's Table 1.
23 So we've taken that proportion of plant
24 investment relative to overall transmission plant
25 investment, and I think it came out to be about
Page 16
1 20 percent. Then we take that 20 percent and say, okay,
2 well, because those are -- that's the proportion of
3 those two line voltages, then 20 percent of
4 transmission-related O&M is what is being captured in
5 that monthly charge. And then we also proportionally
6 allocate some administrative costs.
7 Q. Okay. So I'm going to slow you down a little
8 bit, both for the record and just for my own personal so
9 I understand. This is a little bit of another language
10 when you start breaking this out.
11 So you take all the -- you mentioned two
12 different rates. Can you say those rates again, the
13 160?
14 A. So that's the voltages.
15 Q. That's the transmission --
16 A. Transmission.
17 Q. -- what you classify as transmission?
18 A. Yes.
19 Q. It was 161?
20 A. And 138.
21 Q. Okay. So 161 is the transmission, and 138 is
22 the distribution?
23 A. 138 is what is also contemplated in Table 1,
24 which we would consider to be, like, transmission-level
25 interconnects.
Page 17
1 Q. Okay. So those two are both transmission
2 levels?
3 A. Yes.
4 Q. And you look at the whole systemwide and you
5 say, Hey, how much was the initial capital investment
6 into this system?
7 A. We are using the plant investment for those
8 two line voltages --
9 Q. Okay.
10 A. -- and then comparing that to the overall
11 transmission plant to say what is this proportion, which
12 we then use as kind of the allocation factor for
13 overall, like, transmission O&M costs.
14 Q. So when you say "systemwide," do you mean over
15 all of Idaho Power systems?
16 A. Specific to transmission.
17 Q. Okay. So over the whole state?
18 A. Correct.
19 Q. Anything that uses those two -- the 161 or the
20 138?
21 A. No. In any O&M that is classified as
22 transmission --
23 Q. Okay.
24 A. -- then gets a 20 percent share. So, again,
25 using that 20 percent base --
Page 18
1 Q. You say "any O&M that's" -- I just want to
2 make sure I understand.
3 You mean any facility that's O&M -- any
4 facility gets allocated that because -- can you clarify
5 what you mean by that?
6 A. Yeah. So I guess I'm not sure how familiar
7 you are with, like, the FERC accounts. So there's -- we
8 have our plant, and so the -- to determine that
9 20 percent allocation, we're looking purely at the plant
10 amounts. Right? And so we have that 20 percent. And
11 then further down -- I want to say it's in the 500s,
12 it's -- there's specific accounts that are solely for
13 transmission O&M activities.
14 Q. You're talking about 565, FERC 565?
15 A. I don't know if it's --
16 Q. You mentioned it in your testimony.
17 A. So the one that I mentioned in the testimony
18 is one that we pulled out of the calculation because it
19 was related to wheeling charges that Idaho Power incurs
20 when we import energy.
21 Q. Like, out of state, like a contract with
22 California, kind of thing?
23 A. Yeah. Just when we're importing energy, that
24 had previously been included in the calculation for the
25 transmission rate. When I was updating this, I realized
Page 19
1 it was not appropriate to include it because, again,
2 generation interconnects are not incurring or causes us
3 to incur that cost. Right? And so we should not be
4 recovering that portion.
5 Q. So it's going to be helpful for me and helpful
6 for the record, I think, when we're talking about
7 interconnection O&M versus O&M that just relates just to
8 transmission lines.
9 A. Well, so --
10 Q. Are they the same, or is there a difference?
11 A. So we do not differentiate interconnection O&M
12 to system O&M; it's all one in the same.
13 Q. It's all just O&M?
14 A. Yeah. Well, because once the interconnect --
15 once a project interconnects to our system, that portion
16 of plant is now just incorporated into our broader bulk
17 electric system, and we treat it as any other facility
18 on our system.
19 Q. So you don't know how much O&M goes to any
20 specific interconnection?
21 A. No.
22 Q. You just don't track it?
23 A. No.
24 Q. Okay. So -- let's see.
25 So you mentioned this 20 percent number. Can
Page 20
1 you explain where that 20 percent comes from?
2 A. Yeah. So, again, it's based off of 13-month
3 averages of plant relative to, in transmission's case,
4 the 138 kV lines and 161 kV lines.
5 So, for example, let's say that summed up to
6 5 million, just for simple purposes --
7 Q. Just a hypothetical?
8 A. Yeah, hypothetical.
9 -- but then our overall transmission plant was
10 25 million. So now we have 5 million divided by
11 25 million, you get 20 percent.
12 Q. And that would be just one of the 138? Is
13 that --
14 A. No. That's for both.
15 Q. For both of those?
16 A. Yes.
17 Q. So that's systemwide, if you look at those
18 two -- look at those two, the 161 and the 138,
19 systemwide they -- the O&M is 20 percent over, like, all
20 of Idaho Power's O&M?
21 A. Right. Well, because we're saying -- I mean,
22 all of our transmission O&M has to relate to our
23 transmission facilities. Right? If these two line
24 voltages account for 20 percent of our transmission
25 investment, then it's reasonable to assume that
Page 21
1 20 percent of O&M would be associated with those
2 facilities too.
3 Q. Okay. And the interconnection O&M is a part
4 of that 20 percent?
5 A. It would be, yeah, because it --
6 Q. Okay.
7 A. -- again, it's incorporated into our broader
8 bulk electrical system, and so there's not a specific
9 interconnection O&M amount that gets added. It's
10 just --
11 Q. Okay.
12 A. -- when we go and perform work, it's just
13 included in broad O&M.
14 Q. So to get to what is, quote/unquote,
15 transmission O&M under those two levels, it's
16 essentially all of Idaho Power's O&M times .2?
17 A. Transmission --
18 Q. Transmission?
19 A. -- O&M, yeah.
20 Q. Okay. All of Idaho Power's transmission O&M
21 times .2?
22 A. Yeah. And then there's some adding of general
23 plant and administrative and general costs.
24 Q. Do those add up to something material or?
25 A. I would have to look exactly at the exhibit to
Page 22
1 tell you.
2 Q. If you want to take a look, that's okay.
3 All right. So did you get a chance to look at
4 the exhibit?
5 A. I did.
6 Q. Okay. So is that material to the -- that
7 20 percent when you start talking about add-ins? I just
8 want to make sure I understand this before I --
9 A. Yeah, I --
10 Q. -- I don't want to oversimplify.
11 A. When looking at this specific to the exhibit
12 that was included in my prefile testimony, it's
13 approximately half of the overall costs that then are
14 used to establish the monthly rate.
15 Q. Okay. So it bumps it from 20 percent to
16 30 percent?
17 A. No, no. I guess the 20 percent -- we're not
18 taking a -- we're not taking the 20 percent and then
19 adding 10 percent to it. We're using that 20 percent to
20 then further allocate broad system A&G.
21 Q. A&G?
22 A. Administrative and general.
23 Q. Okay.
24 A. So we're using that 20 percent to then develop
25 additional allocation factors as I've shown in my
Page 23
1 exhibit here to then determine how much A&G should be
2 included.
3 Q. Okay. So break this down a little bit for me.
4 So the 20 percent -- when you say "half," what
5 do you mean by half? Does it add up to half the
6 20 percent?
7 A. So what I mean by half is -- on line 14 of
8 this table -- I'm not sure if you guys have it.
9 Q. I have your direct testimony.
10 MR. WALKER: Is that Exhibit 1 of your prefile
11 direct testimony?
12 THE WITNESS: It is, yeah.
13 MR. WALKER: And you're looking at page 1?
14 THE WITNESS: Correct.
15 MR. EREKSON: I have the correct testimony.
16 Is that from the original?
17 THE WITNESS: Yeah. I mean, it's going to be
18 included in both.
19 MR. WALKER: Yeah, he was looking at the
20 original one. I've got a copy if you'd like.
21 MR. EREKSON: Do you care if I look at your
22 copy, Donovan, so I don't have to go print it out?
23 Thank you.
24 MR. WALKER: Mm-hm.
25 THE WITNESS: So if you look at line 14 in
Page 24
1 this exhibit, you can see transmission O&M assigned to
2 what we're calling transmission service lines. Is about
3 5.3 million.
4 BY MR. EREKSON:
5 Q. Okay.
6 A. And then if you look further down on line 28,
7 it says, "Total A&G Assigned." It's about 4.4 million.
8 Q. Okay.
9 A. And so the total O&M that we're looking to
10 recover that's inclusive of A&G is about 9.7 million,
11 and that is the amount that -- we're taking that amount
12 and then dividing it by the total transmission plant,
13 which includes kind of general plant to an allocable
14 share of general plant to develop that 3.326 percent on
15 line 30, which we then just divide by 12 to arrive at
16 the -- in this case, .28 percent, but I know my --
17 Q. That's the distribution amount, not the
18 transmission?
19 A. No. This is transmission.
20 Q. Okay. And distribution is the .96 or .9 in
21 this particular --
22 (Simultaneous colloquy; reporter
23 interruption.)
24 BY MR. EREKSON:
25 Q. -- in the nonupdated?
Page 25
1 A. Yes.
2 Q. Okay.
3 -- testimony?
4 A. Yeah, in the nonupdated testimony it's .96.
5 Q. It may be helpful -- and I'm guilty of this
6 too, but I'll finish, and then you start, and then you
7 finish and I'll start. And I'll try not to interrupt
8 you --
9 A. Okay.
10 Q. -- if you try not to interrupt me. Okay?
11 A. Okay.
12 Q. We're just going to take a minute and mark
13 this and make it an exhibit --
14 A. Yeah.
15 Q. -- and I'll ask you some more questions and
16 it'll --
17 A. Sure.
18 Q. -- be part of a record.
19 Do you care if we use your exhibit?
20 MR. WALKER: No.
21 MR. EREKSON: We can take a copy and mark it
22 and we can give you your original back.
23 MR. WALKER: That'd be great.
24 And I'd just like to note that that's
25 Exhibit 1 to his original prefiled direct testimony and
Page 26
1 it was subsequently updated. So the numbers that are
2 being sought in the case are different than the numbers,
3 but for purposes of the original methodology, that's --
4 MR. EREKSON: It's the same?
5 MR. WALKER: It's all the same, yeah.
6 (Off the record.)
7 (Exhibit 3 was marked for identification.)
8 MR. WALKER: Yeah, and just one more note for
9 the record, that the updates to that exhibit were filed
10 with the errata and corrected pages filing --
11 MR. EREKSON: Oh. Okay.
12 MR. WALKER: -- that was made on August 8th,
13 2025, and it went through with corrections to that same
14 page and format.
15 BY MR. EREKSON:
16 Q. Okay. Well, just for purposes of explaining
17 how this works, I'm okay using the nonupdated if you
18 are --
19 A. Yeah.
20 Q. -- if you want us to hunt down the --
21 A. No.
22 Q. Okay. So when I look at line item 13, that's,
23 you know, $25.8 million approximately?
24 A. Mm-hm.
25 Q. That's for that -- we're excluding that 565
Page 27
1 account. That's total O&M expense for -- that's
2 transmission O&M expense for all of Idaho Power?
3 A. Correct.
4 Q. Not just on those two -- those two, the 168
5 [sic] and the 131 [sic].
6 A. No. That allocation occurs on the line below
7 at 14. So where we're taking line 13 and multiplying it
8 by the 20 percent that's shown on line 3.
9 Q. Okay. And those two are -- those two are
10 specifically related to QF interconnection? Like, why
11 those two numbers?
12 A. Those two numbers were used because those are
13 the voltages that are currently contemplated in
14 Schedule 72, like that's shown above Table 1.
15 Q. Okay. Okay.
16 And then nothing else Idaho Power uses those
17 voltages?
18 A. We do allow interconnects at other voltage
19 levels, so all transmission levels. I will note -- I
20 mean, staff, in their comments in this case, had noted
21 that too and have proposed a slightly different approach
22 to consider those different voltage levels.
23 Q. Okay. Does it -- when considering staff's
24 approach, does it change the story much?
25 A. For transmission, I don't think so.
Page 28
1 There's -- really, staff's approach is to weight the O&M
2 charge. So if we have more interconnections occurring
3 at, let's say, 161 kV than we do at 230 kV, then we
4 would provide greater weight to that O&M rate for
5 that -- for the 161 compared to 230, right, just to show
6 that there's more interconnects occurring at that
7 161 voltage.
8 Q. Okay.
9 A. I'm not entirely certain, though, how much it
10 changes the end result, given for transmission. It's
11 all using the same initial plant amounts and kind of
12 proportionally allocating there. And so...
13 Q. So this, you know, 25.8 million, that's
14 over -- that's all the transmission in Idaho Power over
15 all the different volts?
16 A. For transmission, yes.
17 Q. Okay. And so these PURPA interconnections
18 you're saying are about a fifth of those?
19 A. We're saying the allocable share when we're
20 determining the system average amount, that we are using
21 that 5 million, plus the A&G, to come up with this .28
22 in this case, which we are then saying essentially for
23 every dollar in transmission plant for these -- for
24 those voltage levels is roughly 28 cents of O&M.
25 And so then we take that and for the
Page 29
1 interconnection -- the initial cost of, like, PURPA
2 interconnections, that's why we don't use the capital
3 costs that was initially required and applying these
4 rates to that to, again, reflect for every dollar this
5 is how much O&M we can anticipate.
6 Q. Okay. So there's an underlying assumption in
7 your model, correct, that -- the ratio, you know, stays
8 the same, the ratio between, you know, idaho Power's O&M
9 and it's initial, you know, capital investment and also
10 that of the PURPA interconnection facility; correct?
11 A. I might not be understanding. Can you
12 rephrase that?
13 Q. Yeah.
14 So it strikes me that you've developed this
15 ratio that you're saying, Hey, systemwide your O&M
16 really relates to how much your initial asset is, right,
17 your initial capital investment -- there's a
18 relationship?
19 A. Correct.
20 Q. And that same relationship, you use to
21 allocate cost to an interconnection facility?
22 A. Correct.
23 Q. Despite there being differences in
24 infrastructure?
25 A. Differences in infrastructure? How so?
Page 30
1 Q. So these interconnection facilities -- and
2 this was Exhibit...
3 MR. ARKOOSH: 2.
4 (Exhibit 2 was previously marked for
5 identification.)
6 BY MR. EREKSON:
7 Q. Exhibit 2 are just essentially these four-pole
8 interconnection facilities, but the whole transmission
9 system of Idaho Power is not just comprised of four-pole
10 interconnection facilities; correct?
11 A. Correct. Although I would clarify, for the
12 four pole, I would assume that would be under a
13 distribution, like the distribution rate.
14 Q. Are you asking me a question or?
15 A. I'm saying I don't know exactly what voltage
16 levels the four poles may be. But if this is for --
17 depending upon the voltage level of the four pole, it
18 might be under the distribution.
19 Q. I guess my point is that these interconnection
20 facilities -- it's not the same equipment as the rest of
21 Idaho Power's transmission; right? These are very,
22 like -- they have a very discrete function; correct?
23 A. We're not developing the rate based off
24 specific equipment though. It's, really, to recognize
25 how much -- on system average, how much O&M would we
Page 31
1 anticipate incurring relative to each dollar of
2 additional investment, irrespective of type of
3 equipment.
4 Q. Yeah, that's the point though; right? You're
5 not taking into account that it is different equipment;
6 you're treating all the equipment the same?
7 A. We still have same kind of maintenance
8 activities for all different types of equipment. So we
9 still have to inspect poles regardless of whether it's
10 under our four-pole methodology here or if it's for a
11 broad stretch of transmission poles.
12 Q. You have to inspect them, but this isn't the
13 same equipment that's used throughout your system.
14 You're not saying that, are you, that you don't just
15 have these replicas of -- that's all Idaho Power has in
16 their transmission and -- or distribution?
17 A. I mean, we have poles and wires on our system.
18 I guess I'm not entirely following.
19 Q. So, I guess, your testimony, then, is that
20 it's -- they have the same costs, all -- these
21 interconnections facilities have the same costs as
22 everything else, or is it that you just treat them the
23 same?
24 A. We are using a previously Commission-approved
25 methodology that has recognized that, again, on a per
Page 32
1 dollar of capital investment or plant addition, how much
2 additional O&M would we expect to incur, which is,
3 really, irrespective of the type of plant being
4 installed.
5 Q. It doesn't matter what the plant is; it's the
6 same methodology?
7 A. Yeah. It doesn't matter if it's a wood pole
8 here or a wire because, again, we're accounting for all
9 of that O&M within the transmission expense.
10 Q. That current -- and I grant it this is
11 Commission approved, but it does treat them all the same
12 even though they're different; correct?
13 A. I guess I wouldn't characterize them as being
14 different because it's -- again, we're looking at the
15 capital and -- like the additional plant that's coming
16 on our books, right, and then comparing that relative to
17 the expected O&M.
18 Q. But aren't you just looking at the additional
19 interconnection facility, not the whole plant?
20 A. As far as assigning the proportional share of
21 O&M?
22 Q. Yeah.
23 A. We are looking at the -- yes, the interconnect
24 capital cost.
25 Q. Just that piece of that plant?
Page 33
1 A. Correct.
2 Q. Not the entire plant; correct?
3 A. The entire plant being Idaho Power's broad
4 system?
5 Q. Well, the QF. Right? Like, when you're -- it
6 just strikes me that we're allocating -- you're taking a
7 ratio based on Idaho Power's transmission costs to their
8 initial capital investment. You're developing this
9 rate, and then you're applying it to a very discrete
10 portion of a QF, the interconnection facility; correct?
11 A. Correct.
12 Q. You're not looking at just, you know, the O&M
13 for Idaho Power just for their interconnections for --
14 throughout. You're looking at Idaho Power's -- their
15 entire transmission system, and then you're applying it
16 just to a QF interconnect?
17 A. Right. But that --
18 Q. And the assumption is that they cost about the
19 same? That's the assumption?
20 A. Yes. Because when we look to recover these
21 costs from customers -- again, we're not differentiating
22 them; it's all based off of system averages and
23 allocation. Right? So in order to ensure customers
24 remain indifferent to a QF's interconnection, we have to
25 assume -- make that assumption.
Page 34
1 Q. I mean, there -- you said you have to assume
2 to make that assumption. Why is that?
3 A. I guess I should say that is the assumption
4 that we have been directed to assume based off of the
5 Commission-established methodology.
6 Q. Okay. So, I guess, now that we've established
7 this assumption exists that we treat the interconnection
8 facility the same as the transmission facility
9 systemwide -- I think we agree on that, that's -- and
10 that's the current methodology. Whether you're
11 levelized or de-levelized, that's happening?
12 A. Correct.
13 Q. Has that assumption been tested? Have you
14 ever tested that assumption?
15 A. I would say that assumption's tested every
16 time we go in for a rate case where the credit that is
17 applied to customers -- so all the Schedule 72 revenue
18 that we recover is then treated as a revenue credit in
19 customer's rates when we're developing their rates. And
20 so I would say this assumption is tested and validated
21 in that forum where -- the reasonableness of are we
22 recovering enough.
23 Q. So earlier today you testified that you didn't
24 track these -- the O&M related to these interconnection
25 facilities. You just don't have a separate record of
Page 35
1 it; correct?
2 A. Correct.
3 Q. So you have no idea to know what you're
4 allocating to this interconnection facility is actually
5 what's been charged to these QFs.
6 A. We know what we're allocating to this
7 interconnection is the same proportional share that our
8 customers would otherwise have to shoulder if we didn't.
9 Q. Agree that you know that that's the same
10 proportional share, but you don't know if that -- if
11 that is the same as -- or anywhere near your actual
12 costs for maintaining this interconnection facility --
13 correct? -- because you just don't track it?
14 A. We don't track it.
15 Q. So you don't know then?
16 A. I would assume that's to be the case, yes.
17 Q. You'd assume that to be the case? I mean, do
18 you agree --
19 A. Yeah, we --
20 Q. -- you don't know. It could be that -- it
21 could be higher or it could be lower?
22 A. Correct. Yeah, we don't track it, and
23 therefore there is nothing to necessarily compare
24 Interconnection A to, you know, some O&M amount. We
25 just -- we don't track it because, again, it gets
Page 36
1 brought into our bulk electric system, and it's just a
2 part of our overall maintenance.
3 Q. So when you have a distribution facility
4 that's charged, you know, .28 percent of that -- well, I
5 guess it's an updated number. Is the updated
6 number .26?
7 A. Transmission facility.
8 Q. Transmission facility. It's .26?
9 A. Correct.
10 Q. Which is what, a quarter of a percent a month
11 about?
12 A. Correct.
13 Q. So 1 percent every four months, 3 percent a
14 year. That could be much more than it costs Idaho Power
15 to actually maintain that facility then; correct?
16 A. On average, that's what we would expect, an
17 additional dollar of investment.
18 Q. That's what you would expect based on the
19 assumptions; correct?
20 A. Correct. And that --
21 Q. But you don't know whether that's accurate
22 because it's not tested; correct?
23 A. Those are the same costs that are recovered in
24 customer's rates and therefore that's why that
25 assumption exists.
Page 37
1 Q. Yeah, but you don't know whether it's higher
2 or lower for what the QFs actually -- the maintenance
3 that's actually incurred to the QF?
4 A. That's correct. Because we don't separately
5 track that.
6 Q. And so same for -- this is the distribution
7 that's at the higher rate?
8 A. Yes.
9 Q. And is that a -- was that .9 or .96?
10 A. The initial filing was .96, and then the
11 corrected version that Donovan had mentioned was .9.
12 Q. Okay. So a little under a percent a month
13 puts you at, what, 10 percent a year?
14 A. 11.4-ish based off the initial --
15 Q. I was being conservative --
16 A. Yeah.
17 Q. -- but 11.4 percent per year. And so I
18 just -- just to make this -- let's say it's a half a
19 million dollar facility, 500,000. And, you know, even
20 at 10 percent, it would be $50,000 in operating and
21 maintenance per year. If it's 11 percent, it's 55. And
22 that could be -- because this is just based on
23 assumptions, this is based on what you'd expect, that
24 could be much higher than what the actual operating
25 maintenance that goes into this facility, or it could be
Page 38
1 lower, but you don't know because you don't track;
2 correct?
3 A. Correct.
4 MR. EREKSON: Okay. Do you have any other
5 questions?
6 MR. ARKOOSH: I think we need to mark that as
7 Exhibit 3.
8 MR. EREKSON: Oh, this? She did it.
9 Do you have any follow-up questions, Donovan?
10 MR. WALKER: I don't think so, no.
11 Well, maybe just one.
12 EXAMINATION
13 BY MR. WALKER:
14 Q. So, Mr. Maloney, we talked about transmission
15 and 138 kV and 161 kV and that -- that comes from the
16 delineation on page 13 of Schedule 72; correct?
17 A. That's correct.
18 Q. And there's two charts on that page; right?
19 A. That's correct.
20 Q. And the other -- so all of our discussion was
21 about Table 1 and transmission?
22 A. Correct.
23 Q. And there's a second table for 138 and below,
24 and that's what's referred to as distribution?
25 A. For purposes of Schedule 72, yes.
Page 39
1 Q. And then those both have their different
2 sheets and calculations?
3 A. Correct.
4 Q. But it's the same Commission-directed
5 methodology?
6 A. That's correct.
7 Q. And the numbers that you testified here about
8 populating were just the exercise that you referred to
9 from the direction from the rate case of populating
10 existing methodology with updated numbers; right?
11 A. Correct.
12 MR. WALKER: I don't have any more.
13 MR. EREKSON: I don't have any questions based
14 on that.
15 MR. WALKER: Should I --
16 MR. EREKSON: Again, it went --
17 THE REPORTER: Off the record?
18 MR. EREKSON: We're okay going off the record.
19 (Deposition concluded at 9:47 a.m.)
20 ---o0o---
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Idaho Power Company -Riley Maloney
APPLICATION OF IDAHO POWER FOR AUTHORITY
CERTIFICATE OF RILEY MALONEY
11/18/2025
Page 40
I, Riley Maloney, being first duly sworn,
depose and say:
That I am the witness named in the foregoing
deposition, that I have read said deposition and know
the contents thereof; that the questions contained
therein were propounded to me; and that the answers
contained therein are true and correct, except for any
change that I may have listed on the Errata Sheet
attached hereto.
DATED this ~ day of UL-<vAD<-< , 20 7-S.
CHANGES ON ERRATA SHEET YES1_ NO __
SUBSCRIBED AND SWORN to before me this
----~o_ -----~ day of 1)(v(v\\pV
1 CHRIS,:::V +YN )AVENPORT •
1 Notary PUIJHc -tate of Idaho •
1 Commission Nt mber 52970 t
1 My Commiss~~Exp res Sep 10, 2026 •
23
24
25
~
NAME OF NOTARY PUBLIC
RESIDING AT hJ~IM ~ I \ D
MY COMMISSION EXPIRES q I \ 0 121.o
Depoidaho, PO Box 44385, Boise, ID 83711 [phone]
Page: Line: Reads:
Change and Correction Sheet
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Page 41
1 REPORTER'S CERTIFICATE
2
3 I, SARAH L. GOEKLER, CSR No. 1178, Certified
4 Shorthand Reporter, certify:
5 That the foregoing proceedings were taken before
6 me at the time and place therein set forth, at which
7 time the witness was put under oath by me.
8 That the testimony and all objections made were
9 recorded stenographically by me and transcribed by me or
10 under my direction.
11 That the foregoing is a true and correct record
12 of all testimony given, to the best of my ability.
13 I further certify that I am not a relative or
14 employee of any attorney or party, nor am I financially
15 interested in the action.
16 IN WITNESS WHEREOF, I set my hand and seal this
17 2nd day of December 2025.
18
19
20 · · ·_____________________________
21 SARAH L. GOEKLER, CSR No. 1178
22 Notary Public
23 PO Box 44385
24 Boise, Idaho 83711
25 My commission expires March 17, 2028
Idaho Power Conpany -
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY
Riley Mal oney 11/ 18/ 2025

160 allocable assigned
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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
Index: $25.8 to break

Idaho Power Conpany -
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY
Riley Mal oney 11/ 18/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711
| ndex:
[phone]
breaking to escal at ed

Idaho Power Conpany -
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY
Riley Mal oney 11/ 18/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
| ndex: escalates to leve

Idaho Power Conpany -
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY
Riley Mal oney 11/ 18/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
Index: |evelized to quarter
Idaho Power Conpany -
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY
Riley Mal oney 11/ 18/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
| ndex: question to tines

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-26-15

IDAHO POWER COMPANY

CONFIDENTIAL EXHIBIT NO. 2

EXHIBIT NO. 2
IS CONFIDENTIAL AND WILL BE PROVIDED TO THOSE PARTIES THAT EXECUTE
THE PROTECTIVE AGREEMENT IN THIS MATTER
BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-26-15

IDAHO POWER COMPANY

EXHIBIT NO. 3

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 ANDRES V. DELGADO
TAKEN NOVEMBER 17, 2025
REPORTED BY:
Beverly A. Benjamin, CSR No. 710
Notary Public
Page 2
1 THE RULE 30(b)(6) DEPOSITION OF IDAHO POWER
2 COMPANY, TESTIMONY OF ANDRES V. DELGADO, was taken on
3 behalf of IdaHydro at the Arkoosh Law Offices, 913 W.
4 River Street, Suite 450, Boise, Idaho, commencing at
5 9:02 a.m. on November 17, 2025, before Beverly A.
6 Benjamin, Certified Shorthand Reporter and Notary Public
7 within 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 [e-mail]
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 [e-mail]
25 (Appearances continued.)
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
9
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Page 4
1 I N D E X
2 TESTIMONY OF ANDRES V. DELGADO PAGE
3 Examination by Mr. Erekson 5
4 Examination by Mr. Walker 24
5
6
7 E X H I B I T S
8 NO. DESCRIPTION PAGE
9 Exhibit 1 Response to Interrogatory No. 15 10
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Page 5
1 ANDRES V. DELGADO,
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 name just for the record.
11 A. Yeah. My name is Andres Valdepena Delgado.
12 You spell it V-A-L-D-E-P-E-N-A, and then Delgado is
13 D-E-L-G-A-D-O.
14 Q. Have you ever been in a deposition before,
15 Andres?
16 A. Not a deposition.
17 Q. I'm going to go over just a few ground rules
18 then.
19 A. Okay.
20 Q. It is being stenographically recorded. So it
21 is important that you speak audibly and that you speak
22 slow enough that she can keep an accurate transcript.
23 A. Okay.
24 Q. You are under oath, so there are a few things
25 that come along with that. You have to answer
Page 6
1 truthfully so as not to be held in contempt or there
2 could be accusations of misconduct.
3 So this is a question-and-answer format. I'll
4 ask the questions and you provide the answers. If you
5 don't understand my question, it's okay to ask for a
6 clarification.
7 We'll just jump right in. So do you know why
8 you're here today, Andres?
9 A. Yes, I do.
10 Q. There's specific questions I'm going to focus,
11 specific areas. One of those is the segregation of
12 interconnection costs. The other is the inclusion of
13 interconnection costs and avoided cost methodologies.
14 Actually, segregation was for another witness.
15 So, the other is assumptions regarding avoided O&M.
16 Can you give me a little bit about your
17 background. Like, how did you get to this spot in Idaho
18 Power?
19 A. I've been with Idaho Power for about 12 years
20 now, all of them in planning. So I did 5 years in
21 distribution planning, I did about 4 years in system
22 planning, and I have been in this new role for about
23 2 years.
24 Part of my role is to support regulatory with
25 cases, which includes this one. And then planning
Page 7
1 department, we provide some inputs to different dockets,
2 such as this, inclusion of interconnection costs, of
3 what it costs. So part of the IRP, which is kind of
4 what fits one of our programs, which is the ICIRP, comes
5 from the planning department. So that's how I have been
6 involved over the years.
7 Q. What is your education?
8 A. I have a bachelor's in engineering, a master's
9 and a Ph.D. in electrical and computer engineering.
10 Q. The bachelor's and the master's are electrical
11 and computer engineering also?
12 A. Bachelor's electrical; master's and Ph.D.
13 electrical and computer.
14 Q. Where did you go school?
15 A. My undergrad is at Durango Institute of
16 Technology back in Mexico. Master's and Ph.D. at Boise
17 State.
18 Q. What did you study to get your Ph.D.?
19 A. I did, we designed what is called a
20 Residential Static VAR Compensator, which is a voltage
21 regulating device.
22 Q. Now, for your day-to-day, what do you do for
23 Idaho Power?
24 A. So as assistant consultant engineer, I provide
25 some support to all three of the planning groups. So
Page 8
1 inside the planning department we have system planning,
2 which they handle pretty much anything in the system or
3 transmission level, which is 100kV and above. And then
4 we also provide support to the distribution planning,
5 which is 100kV and below. And resource planning, which
6 is in charge of procuring resources to meet Idaho Power
7 load.
8 Q. Is that 100 kilovolt, is that like an
9 arbitrary amount? Why is above that transmission and
10 below that distribution --
11 A. That's what NERC defines as the BES, or bulk
12 electric system. So that is a NERC defined voltage.
13 Q. But besides that there's no other reason to
14 kind of draw the line in the sand right there?
15 A. Anything that is part of the bulk electric
16 system --
17 (Reporter clarification.)
18 (Discussion off the record.)
19 THE WITNESS: What I was trying to say is:
20 Transmission is regulated by FERC. And distribution is
21 usually regulated by the utility commission, so by
22 state. There is a difference on who oversights the
23 different processes.
24 Q. (BY MR. EREKSON) And that 100 kilovolt, they
25 both use that same delineator between transmission and
Page 9
1 distribution?
2 A. There are more rules of what accounts as
3 transmission and distribution, not only the voltage, but
4 voltage is one of the main ones, the easiest ones.
5 Q. Then for purposes of interconnection O&M
6 tariffs, that's the cutoff that's being used?
7 A. You have to check with Mr. Maloney, but I
8 believe so.
9 Q. So how familiar are you with the SAR, the
10 surrogate avoided resource model?
11 A. I'm pretty familiar.
12 Q. And what is the model?
13 A. So the model, the SAR, it tries to capture the
14 costs, all-inclusive costs, of a combined cycle to get
15 the rate of what we will pay contracts under the
16 published threshold.
17 Q. How is the SAR developed?
18 A. Well, it was developed back in 2008, is the
19 last time it has some changes. And it gets updated
20 every year. And some of the updates that we do is the
21 gas prices. And then every other year we update
22 capacity positions.
23 But in terms of the cost, they are set by an
24 order from the Idaho Public Utility Commission, and
25 those costs have not changed.
Page 10
1 Q. That's Order 30738?
2 A. Correct.
3 Q. You had referenced that in your discovery
4 response; correct?
5 A. That is correct.
6 Q. You wrote the discovery response to
7 Interrogatory No. 15?
8 I printed it out for you if it's helpful as an
9 exhibit. It's Exhibit 1.
10 (Exhibit 1 marked.)
11 THE WITNESS: Yeah. I did respond to that.
12 Q. (BY MR. EREKSON) In that you have a footnote
13 referencing this order. And you have a second footnote
14 referencing the Northwest Power and Conservation
15 Council, their Sixth Conservation and Electric Power
16 Plan. Is that the basis for the SAR model that was
17 adopted in Order 30738?
18 A. It is the basis for the cost.
19 Q. Just for like the cost assumptions?
20 A. Yes.
21 Q. Now, when the Northwest Power and Conservation
22 Council comes out with an additional report, like they
23 do every 5 years, is the model updated or is it just
24 left back in the 2000-2006 report?
25 A. To my knowledge, it has not been updated. It
Page 11
1 is still the same cost from the sixth power plan.
2 Q. And that's because that is the last time that
3 the avoided cost rate was set was in 2008?
4 A. The fixed costs, yes. The actual avoided rate
5 changes with gas prices and other inputs.
6 Q. The variable costs.
7 A. Correct.
8 Q. Now, how familiar are you with those
9 assumptions that go into this model?
10 A. I would say relatively familiar. I read over
11 them.
12 Q. So the variable and the fixed rate operating
13 and maintenance, were those inclusive or exclusive of
14 interconnection operating and maintenance?
15 A. The fixed costs included, there is a fixed O&M
16 that gets added to the capital cost. So they are
17 included on the cost.
18 Q. On the fixed costs?
19 A. On the fixed costs.
20 Q. Are they included on the variable costs?
21 A. The variable costs they are -- I'll have to
22 double-check. I know the fixed costs for sure they are.
23 Q. What are the units on the fixed costs? Like
24 we talked about them being included but --
25 A. Usually they are given in dollars-per-kilowatt
Page 12
1 month.
2 Q. Per kilowatt month?
3 A. Or kilowatt year, depending on the time. So
4 it's a fixed payment based on kW every year.
5 Q. So if it's month, it would change per month
6 based on the amount of power produced?
7 A. No. It's based on nameplate. So it does not
8 change. So if you have 100kW, and the fixed on them is
9 $2 per kW per month, then it gets multiplied 100 times 2
10 every month.
11 Q. So if it was per kilowatt per year, it would
12 be the same every year.
13 A. Correct.
14 Q. It's just a fixed cost. It doesn't change
15 regardless of how much --
16 A. Based on escalation rate that changes that
17 every year.
18 Q. It changes that every year.
19 A. Correct.
20 Q. But that base fixed just stays the same,
21 notwithstanding the escalation rate?
22 A. Correct.
23 Q. That escalation rate, that's an assumption.
24 Is that pulled from the --
25 A. Conservation Council.
Page 13
1 Q. From the sixth report.
2 A. Correct.
3 Q. Is that updated as new reports come out, or do
4 you still look at the sixth report?
5 A. To my knowledge, it has not been updated
6 because those values are set by the order. So the order
7 has the values.
8 Q. So when you reference cells D37, D39, and D40,
9 you're talking about the SAR fixed O&M of $14.57 per --
10 is this kilowatt month or kilowatt year?
11 A. Those are kilowatts...
12 Q. Well, the fixed O&M, is that done per kilowatt
13 month or per kilowatt year, or is that just per
14 kilowatt?
15 A. Per kilowatt. And then when you go into the
16 model, they get calculated on a yearly basis.
17 Q. So if it's per kilowatt, it does change based
18 on the amount of power that's produced?
19 A. Usually it's based on nameplate, so it will
20 not.
21 Q. Okay. So what portion of that $14.57 would be
22 for interconnection O&M?
23 A. I don't have the actual breakdown. When you
24 look at the power plan for the Power and Conservation
25 Council, they do not have a breakdown of which one, each
Page 14
1 line item. They have it all together.
2 Q. So it's just not segregated out?
3 A. They do include on the write-up when you look
4 at that, what is included on the price. But they don't
5 have a line item. They don't have like this dollar,
6 this dollar, this dollar. They just have a total amount
7 that includes everything.
8 Q. So we have no way of knowing whether it's $1
9 or $5?
10 A. You have to contact them.
11 There is some data on that appendix that I
12 referenced, but it's not line by line.
13 Q. It doesn't ever break it out.
14 A. They do have a breakdown for transmission,
15 local transmission connection. Part of that is
16 broke down, but that is the only one that they break
17 down.
18 Q. How much did that breakdown at?
19 A. I don't remember off the top of my head, but
20 I'll have to look at the number.
21 Q. In your response you didn't reference that it
22 was broken out anywhere.
23 A. So in my response I put kind of the language
24 of what everything includes. If you go into the
25 reference and dive into the appendix, specifically they
Page 15
1 do break down a little bit more what gets included, but
2 they don't have a line item.
3 Q. There's no number. Qualitatively they're
4 saying that it's there.
5 A. Correct.
6 Q. But quantitatively they don't get to see the
7 number.
8 A. Correct.
9 Q. We just take their word for it that it's in
10 the overall rate --
11 A. Correct.
12 Q. -- that's paid to the QF.
13 So it would be very difficult to compare, or
14 impossible to compare the actual, like a 72 charge, to
15 what someone is being paid on the front end.
16 A. To my knowledge, those are different costs,
17 but yes. If you don't have the breakdown, you cannot
18 compare them.
19 Q. There's no way to do a comparison. Okay.
20 Same thing for the IRP model?
21 A. No, that is different. So the IRP model, the
22 costs there, the capital cost and the fixed O&M, they
23 come from the Renewable Energy Lab, NREL. And the
24 transmission and the connection costs, they come from
25 the Idaho Power interconnection queue.
Page 16
1 Q. So the interconnection costs are broken out.
2 Are the interconnection O&M broken out?
3 A. No. The O&M is a fixed number that gets
4 applied to everything.
5 Q. Can you explain this for someone who doesn't
6 have a Ph.D. Just break it down.
7 A. So we provided some -- Interrogatory 16.
8 Q. Yes.
9 A. So there's a fixed O&M component on the fifth
10 column. So that fixed O&M includes everything. It's
11 not breaking it down piece by piece. So it is fixed O&M
12 that gets applied to the total.
13 Q. And that's for the whole plant.
14 A. Correct.
15 Q. So, again, is the interconnection O&M broken
16 out? Just on the interconnection piece.
17 What kind of plant is the IRP?
18 A. So the IRP will have the cost. Let's say the
19 simple-cycle combustion turbine. So the capital cost
20 that is included here that we provided, that capital
21 cost also has some assumptions that includes everything
22 of what is called the fence line. So it's the plant
23 plus the gen-tie, plus the transformer, and they end at
24 the high side of the transformer. So that is the
25 capital.
Page 17
1 And then you have the transmission and
2 interconnection costs, which is column three on
3 Interrogatory 16, transmission and interconnection
4 costs. So that gets added into the capital costs.
5 And then you have the fixed O&M that gets
6 applied to the total capital.
7 Q. So I see $81 per kilowatt for the transmission
8 and interconnection capital for the --
9 A. For the SCCT, simple-cycle combustion turbine.
10 Q. And this is with respect to the ICIRP?
11 A. That is the ICIRP.
12 Q. Then I see $2.10 per kilowatt month, a fixed
13 O&M for the same model. Which one of these numbers
14 would represent interconnection operating and
15 maintenance?
16 A. It would be included as part of the fixed O&M.
17 Q. How much of the $2.10?
18 A. It's not broken down by that.
19 Q. But it's less than $2.10?
20 A. I would assume so.
21 Q. It's not all of it.
22 Can you point to anywhere here that that
23 interconnection O&M is broken out, like a separate line
24 item?
25 A. It's not.
Page 18
1 Q. It's not.
2 A. Correct.
3 Q. So I guess in the context of why we're here,
4 it's a Schedule 72 rate case. Again, it's impossible to
5 compare the unknown amount of interconnection O&M that's
6 paid to a QF on the front end to what's proposed being
7 charged kind of on the back end.
8 A. To my understanding about the cost, ICIRP and
9 the SAR model, they compensate for the entire plan,
10 including O&M, including interconnection facilities.
11 All of that gets paid into the avoided costs.
12 Schedule 72 is incremental costs that Idaho Power incurs
13 by maintaining those facilities, because we include
14 everything on the avoided costs.
15 Q. But any avoided cost modeling under both
16 models, neither one of them has a line item for
17 interconnection operating and maintenance; correct?
18 A. Correct. They are included. They are part of
19 entire.
20 Q. There's a broader cost that includes them, but
21 we can't see whether it's 50 cents out of this $2.10 per
22 kilowatt month or whether it's 1 cent or whether it's
23 $2, we don't know.
24 A. Correct. But we know they are included in
25 there.
Page 19
1 Q. Just we don't know to what extent they are
2 included.
3 A. Correct.
4 Q. So it's kind of like apples and oranges
5 comparing the two.
6 A. Well, on one side you have the entire cost of
7 the avoided -- right? -- these avoided resource, either
8 in the SAR methodology or the ICIRP methodology, they
9 are included everything that is in there. Schedule 72
10 was incremental to that to maintain those facilities.
11 Q. So we don't know -- I guess, we don't know
12 whether the amount under Schedule 72 is greater than the
13 amount that was included under the avoided cost modeling
14 or whether it's less than; correct?
15 A. Correct.
16 Q. We have no idea.
17 A. They are different.
18 Q. They are different?
19 A. Yes. Because one of them you have a
20 theoretical resource for what it costs, and the Schedule
21 72 are actuals. So it's hard to compare them when you
22 have a proxy resource versus actual.
23 Q. Yeah. Just hypothetically -- we get to talk
24 hypothetically since I don't have a Ph.D. so I
25 understand this.
Page 20
1 If the Schedule 72 tariff were more than the
2 actual cost, would the company have a gain, a financial
3 gain?
4 A. Well, they are different so -- they serve
5 different purposes, so it's hard to do that. Because
6 you have a hypothetical resource that gets avoided cost
7 that we pay to the QFs, and then you have actuals of
8 what was actually incurred to maintain that system.
9 Q. The QF is not an actual, but I get what you're
10 trying to say. The QF is another model -- the Schedule
11 72 is another model. You would agree that it's not
12 actual cost.
13 A. From my understanding, it's averages of actual
14 costs for the company.
15 Q. So I guess to repeat my question: So let's
16 say, because we don't know, it's somewhere between zero
17 and $2.10 per kilowatt month; right?
18 A. Per kW, yes, month.
19 Q. What does the kW stand for?
20 A. Kilowatt.
21 Q. Kilowatt month.
22 We don't know whether it's 5 cents or if it's
23 $2; correct?
24 A. Correct.
25 Q. And that set Schedule 72 tariff has different
Page 21
1 units, but it could come out, you could put it in terms
2 of a kilowatt month; right?
3 You could; I couldn't.
4 A. Right.
5 Q. You're the Ph.D.
6 So to the extent it is more than the
7 interconnection O&M, would that be a gain for the
8 company?
9 A. So your question is if those are different,
10 could be gain or could be a lose; right? It depends.
11 Q. If they're different, it has to be a gain or a
12 loss; correct?
13 A. Yeah. Again, we're comparing two different...
14 Q. We're comparing two different things. This is
15 a hypothetical question.
16 If it's less, it would be a loss to the
17 company. You can agree with that; right?
18 A. This hypothetical scenario? Yes.
19 Q. If the model had one rate and they were paid
20 back at another that was less than, they would have a
21 loss.
22 A. Hypothetical it could be more or less.
23 Q. Same thing, the contrapositive, if the
24 Schedule 72 rate were more than was in the model, it
25 would be a gain to Idaho Power; correct?
Page 22
1 A. Hypothetical, yes. If they are different, it
2 could be a gain or a loss.
3 Q. So if it were more it would be a gain.
4 A. In this hypothetical scenario, yes.
5 Q. But we don't know whether it's more or less.
6 We know it's not exactly though; correct?
7 A. Correct.
8 Q. When you are reviewing these models and their
9 assumptions, does Idaho Power have any actual data that
10 you can use to test the validity of these models?
11 A. Which ones? So for --
12 Q. I guess we can start out with SAR. It would
13 be easier to talk about one model at a time.
14 A. We don't compare those.
15 Q. You just kind of take them at their face?
16 A. Yeah. So the Power Conservation Council, they
17 go through a lot of validation data. The same thing
18 with the ICIRP.
19 For the SAR model, there's nothing we can do.
20 That's in the order. We have to use that.
21 For the ICIRP, we do a little vetting on
22 public sources to make sure they are good data.
23 Q. Then ultimately you adjust some of the inputs
24 for the model for the ICIRP?
25 A. The costs we do not. We take them from either
Page 23
1 NREL --
2 Q. But there's no like independent analysis. You
3 just accept these because somebody else has done them.
4 A. Yes. But they go through a lot of vetting
5 before they publish those numbers.
6 Q. With this case pending, have you done any of
7 your own research with respect to interconnection O&M
8 costs?
9 A. I have not.
10 Q. Has anybody, to your knowledge?
11 A. Not to my knowledge.
12 Q. Are you aware of any, as far as quantitative
13 evidence, that relates to specifically the
14 interconnection O&M at Idaho Power?
15 A. Not to my knowledge.
16 Q. No modeling specifically of that particular
17 piece?
18 A. Not to my knowledge. At least not in the
19 planning department.
20 MR. ARKOOSH: Let's take just a moment's
21 break.
22 (Off the record.)
23 MR. EREKSON: That's all the questions I have,
24 unless you want to follow up.
25 MR. WALKER: I have just one quick follow-up.
Page 24
1 EXAMINATION
2 QUESTIONS BY MR. WALKER:
3 Q. I usually just say "Mr. Andres," by the way,
4 instead of trying to correctly pronounce...
5 So there was a little bit of talk and question
6 back and forth about, in the hypothetical, about whether
7 it would be a loss or a gain to the company under
8 different hypotheticals.
9 And to the extent that you know, or maybe this
10 is more appropriate for one of the other witnesses, but
11 does the company make a gain or a loss on any kind of
12 O&M collection or under-collection or over-collection?
13 A. To my knowledge, it does not. It's a
14 pass-through on a rate case.
15 Q. In other words, it would be something that
16 other customers would pay more or less in this gain or
17 loss, it wouldn't be a gain or a loss to the company.
18 A. Correct.
19 Q. And the company doesn't earn any authorized
20 return or profits on any type of O&M?
21 A. That is correct.
22 MR. WALKER: That's the only follow-up I had.
23 MR. EREKSON: No further questions.
24 (Deposition concluded at 9:37 a.m.)
25 (Signature requested.)
Page 2 5
1 CERTIFICATE OF WITNESS
I,ANDRES V.DELGADO,being first duly sworn,2
depose and say:3
That I am the witness named in the foregoing4
deposition,consisting of pages 1 through 26;that I5
have read said deposition and know the contents thereof;6
that the questions contained therein were propounded to7
and that the answers contained therein are true and8me;
correct,except for any changes that I may have listed9
on the Change Sheet attached hereto:10
day of bfl >20 2S.3DATEDthis11
12
13
14
15 ANDRES V.DELGADO
16
17 .ay
of18 ,20
19
20
NAME OF NOTAR'PUBLIC
NOTARY PUBLIC FOR
RESIDING AT
24
25
(
i
ID 83711
ID 83711
[phone]
[phone]
11/17/2025
11/17/2025
CHRISTY LYN DAVENPORT
Notary Put He -State of Idaho
CoSunissi in Number 52970
My Commission Expires Sep 10,2026
SUBSCRIBED AND SWORN to before me this
V\o
MY COMMISSION EXPIRES I
Depoldaho,PO Box 44385,Boise,
Depoldaho,PO Box 44385,Boise,
Idaho Power -Andres Delgado 30(b)(6)
A?McWr°-F«®|hoF0RMWY
APPLICATION OF IDAHO POWER FOR AUTHORITY
Page 26
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
20 · · _______________________________
21 · · · · BEVERLY A. BENJAMIN, CSR No. 710
22 Notary Public
23
24
25
Idaho Power - Andres Del gado
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY
30(b) (6) 11/ 17/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
Index: $1 to DE-L-GA

Idaho Power - Andres Del gado
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY 30( b) (6) 11/ 17/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
| ndex: D87 to make

Idaho Power - Andres Del gado
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY 30( b) (6) 11/ 17/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
|ndex: Maloney to spot

Idaho Power - Andres Del gado
APPLI CATI ON OF | DAHO POWER FOR AUTHORI TY 30( b) (6) 11/ 17/ 2025

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Depol daho, PO Box 44385, Boise, ID 83711 [phone]
| ndex: stand to years

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-26-15

IDAHO POWER COMPANY

EXHIBIT NO. 4

· · · ·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
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· · · · · ·[e-mail]
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· · · · · ·[e-mail]
25· ·(Appearances continued.)
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
·9
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Page 4
·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
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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 O&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.)
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·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 _____ day of __________, 20___.
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14· · · · · · · · ·______________________________________
15· · · · · · · · ·ERIC HACKETT
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17· · · · · ·SUBSCRIBED AND SWORN to before me this ____ day
18· ·of ______________________, 20___.
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20· · · · · · · · ·______________________________________
21· · · · · · · · ·NAME OF NOTARY PUBLIC
22· · · · · · · · ·NOTARY PUBLIC FOR ____________________
23· · · · · · · · ·RESIDING AT __________________________
24· · · · · · · · ·MY COMMISSION EXPIRES ________________
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·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.
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20· · · · · · · · · · · · · ·_______________________________
21· · · · · · · · · · · · · ·BEVERLY A. BENJAMIN, CSR No. 710
22· · · · · · · · · · · · · ·Notary Public
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