20240314INT to Staff 1-2_4-15_17-19.pdf

INTERMOUNTAIN GAS COMPANY’S RESPONSES TO STAFF’S FIRST PRODUCTION REQUEST PAGE 1 OF 2
18258068.1)
Preston N. Carter, ISB No. 8462
Morgan D. Goodin, ISB No. 11184
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]

Attorneys for Intermountain Gas Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF INTERMOUNTAIN
GAS COMPANY’S 2023 INTEGRATED
RESOURCE PLAN
Case No. INT-G-23-07

INTERMOUNTAIN GAS COMPANY’S
RESPONSES TO THE FIRST PRODUCTION
REQUEST OF THE COMMISSION STAFF
Intermountain Gas Company (“Intermountain” or “Company”), in response to the First
Production Request of the Commission Staff to Intermountain Gas Company dated February 22,
2024, submits the following responses. Responsive documents are available for download using
the link provided in the accompanying email. Confidential responses and documents are subject
to the protective agreement in this case, and are available for download using a password-
protected link that will be provided separately by email. The password will be provided in a third
email.
DATED: March 14, 2024.

By:_____________________________
Preston N. Carter
Givens Pursley LLP
Attorneys for Intermountain Gas Company

RECEIVED
Thursday, March 14, 2024 3:43PM
IDAHO PUBLIC
UTILITIES COMMISSION

INTERMOUNTAIN GAS COMPANY’S RESPONSES TO STAFF’S FIRST PRODUCTION REQUEST PAGE 2 OF 2
18258068.1)

CERTIFICATE OF SERVICE

I HEREBY CERTIFY THAT on March 14, 2024, I caused a true and correct copy of the
foregoing to be served upon the following parties as indicated below:

Monica Barrios-Sanchez
Commission Secretary
Idaho Public Utilities Commission
P.O. Box 83720
Boise, Idaho 83720-0074
[e-mail]

Email
U.S. Mail
Fax
Hand Delivery

Preston N. Carter

INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Kathleen Campbell/ Brian Robertson
REQUEST NO. 1:
Since the 2021 IRP, please describe activities and results achieved in providing the
Commission with capacity enhancement project costs and NPV information when capacity
improvement projects are completed and placed in service. See Order No. 35438 at 8.
RESPONSE NO. 1:
The enhancement projects included in the 2021 IRP were as follows:
1.12 inch Untick Phase II
2.Shoshone Compressor Station
3.12 inch Boise Loop
4.State Street Uprate
5.12 inch Ustick Phase 3
6.Idaho Falls Lateral Compressor Station
The Ustick Phase II project was completed in 2021. Because Intermountain filed a general rate
case in 2022, detailed project information on this project was filed as part of INT-G-22-071. As
explained in the Response to Production Request No. 13 the Shoshone Compressor Station was
completed in December 2023. Intermountain is still awaiting final project costs on this project. It
is not uncommon for the closeouts on a project to take several months after project completion.
Once the final information is available, Intermountain will provide project cost data to the
Commission. None of the remaining projects have been placed in service. Intermountain is open
1 See INT-G-22-07, Direct Testimony of Patrick C. Darras, pages 20 – 24.
INT-G-23-07
IPUC Staff PR 1
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to discussing with Staff the best way to provide the reports contemplated by Order No. 35438.
Some potential options may be 1) an annual report in late spring on any projects that close during
the previous year, 2) a late spring report only in the years between IRPs with the IRP filing
serving as the report in years that it is filed, 3) individual reports after final costs are available on
a project.
INT-G-23-07
IPUC Staff PR 1
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Brian Robertson/ Brian Robertson
REQUEST NO. 2:
Since the 2021 IRP, please describe the Company's activities and results achieved in
providing materials to IGRAC members before meetings and making information accessible on
its website. See Order No. 35438 at 8.
RESPONSE NO. 2:
For the 2023 IRP, Intermountain updated meeting invites a week in advance with meeting
materials. Following the meeting, the Company uploaded the IGRAC presentation, meeting
minutes, and the video recording of the meeting on the Company’s dedicated IRP webpage.1
INT-G-23-07 Exhibit No. 1 contains the meeting slides as well as the meeting minutes. Although
Intermountain did not receive any pre-meeting questions or post-meeting feedback, the Company
did receive several questions during the meetings, which are captured in the meeting minutes and
the video recording (see footnote 1).
1 See: Integrated Resource Plan - Intermountain Gas Company (intgas.com)
INT-G-23-07
IPUC Staff PR 2
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Brian Robertson/ Brian Robertson
REQUEST NO. 4:
For each of the three virtual IGRAC meetings conducted please provide the following:
a) Feedback submitted for each meeting including meeting date and participant
name or organization;
b) Information requests for each meeting including meeting date and participant
name or organization.
RESPONSE NO. 4:
Intermountain did not receive any pre- or post-meeting feedback. All feedback was
received during meetings. The feedback is noted in the meeting minutes which are included in
INT-G-23-07 Exhibit No. 1 or it can be viewed in the video recording posted on the Company’s
website.1
1 See:Integrated Resource Plan - Intermountain Gas Company (intgas.com)
INT-G-23-07
IPUC Staff PR 4
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Niki Ogami/ Brian Robertson
REQUEST NO. 5:
Please provide a five-year historical (2018-2022) view of the Company's Lost and
Unaccounted for ("LAUF") natural gas including supporting workpapers and PHMSA reports.
RESPONSE NO. 5:
Please see the following documents for the LAUF calculations as of June 30th for years
2018-2022:
Part G-Percent of Unaccounted For Gas 6-30-18.xlsx
Part G-Percent of Unaccounted For Gas 6-30-19.xlsx
Part G-Percent of Unaccounted For Gas 6-30-20.xlsx
Part G-Percent of Unaccounted For Gas 6-30-21.xlsx
Part G-Percent of Unaccounted For Gas 6-30-22.xlsx
Please see the following documents for the PHSMA Reports for the historical years of
2018-2022:
2018 - IGC -7100.1-1.pdf
2019 - IGC -7100.1-1 Supplemental submitted 9-14-2020
2020- IGC -7100.1-1.pdf
2021 - IGC -7100.1-1.pdf
2022 - IGC -7100.1-1.pdf
INT-G-23-07
IPUC Staff PR 5
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Michael Schoepp/ Brian Robertson
REQUEST NO. 6:
In section 3.5.4 of the IRP, the Company describes education efforts as having a positive
impact on reducing excavation damage. Please explain actions beyond education and awareness
the Company is taking to increase locate requests and reduce excavation damage.
RESPONSE NO. 6:
IGC has contracted with Enertech for additional online marketing to our Idaho Falls area.
The marketing is designed to reach our high damage excavators. This area was chosen due to the
highest excavation damages per 1000 locates in our IGC territory.
IGC is currently developing our IRTH software for locate ticket management. The
software will help determine higher risk excavators that have caused damages on the Company’s
system. Intermountain would like to provide additional information to these excavators to
reduce damages in the future.
INT-G-23-07
IPUC Staff PR 6
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Ryan Privratsky/ Brian Robertson
REQUEST NO. 7:
Please provide a worksheet that indicates the following information regarding early
vintage plastic pipe ("EVPP") in the Company's system.
a)Total amount of pipe by size and classification (main or service) that requires
replacement.
b)Total amount of EVPP pipe by size and classification (main or service) replaced
each year for the last five years.
c) Annual replacement cost.
d) A schedule by areas of interest ("AOI") of when replacement will be completed.
RESPONSE NO. 7:
a)The total amount of pipe classified as early vintage plastic pipe (“EVPP”), by size
and classification (main or service), is listed below:
Classification Size (inches) Quantity (Miles)
Services
0.5 59.11
0.75 1155.21
1.25 27.63
2 38.40
3 0.00
4 0.83
6 0.01
Mains
0.75 3.89
1 0.82
1.25 18.37
2 1086.89
4 139.19
Total 2530.35
INT-G-23-07
IPUC Staff PR 7
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b)The total amount of main and number of service lines replaced through the
Company’s System Safety Integrity Program (SSIP), by size and classification (main or service),
over the last four years, is listed below:
Classification Size (inches) 2020 2021 2022 2023
Service (#) ≤ 1-1/4" 174 288 313 239
2" 2 3 4 0
Main (ft) ≤ 2" 17,624 28,382 18,660 27,480
To date the primary focus of the Company’s SSIP has been focused on the replacement
of EVPP. Early vintage steel pipe (“EVSP”) has been replaced in conjunction with EVPP, but
totals have been negligible compared to EVPP totals. Totals above are primarily for the
replacement of EVPP. Replacement through the Company’s System Safety Integrity Program
(“SSIP”), in Idaho, didn’t formally commence until 2020.
c)Annual replacement costs associated with the Company’s SSIP, to replace EVPP,
over the next five years, is listed below:
2024 2025 2026 2027 2028
$3,868,536.94 $4,122,216.36 $4,285,615.34 $4,453,563.62 $4,589,562.26
Annual replacement costs include the replacement of EVSP main and service.
d)The Company’s SSIP is a structured replacement program for replacing EVSP
and EVPP. EVSP is steel mains, service lines, and associated fittings installed earlier than
January 1, 1970. These pipeline segments present an increased risk of failure due to age and
obsolete materials, parts, and/or equipment. EVPP is plastic mains, service lines, and associated
fittings installed earlier than 1/1/1995. Pre-1983 EVPP is pipe installed prior to 1/1/1983 that
may be susceptible to possible Low Ductile Inner Wall (LDIW) characteristics that can result in
slow crack growth and slit failures, as documented by PHMSA–2004–19856. Post-1982 EVPP
is pipe installed between 1/1/1983 and 12/31/1994 and are classified as EVPP to account for
INT-G-23-07
IPUC Staff PR 7
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different inventory levels and rates of new material adoption among the Company. The
Company’s SSIP utilizes the Company’s DIMP risk model and relative risk score to establish a
weighted average risk (WAR) score for each town within Idaho. The WAR score is then used to
identify and prioritize the Company’s highest risk systems, based on WAR scores of EVSP and
EVPP as shown below:
Pipeline operators have a requirement to implement integrity management programs
(“IMP”) that evolve and mature to fit an operator’s unique operating environment. The
evolution of an operator’s IMP program takes time and resources to collect and analyze data
to accurately identify the most current high-risk pipelines within any given system. Once a
system is prioritized and selected it typically requires multiple years to develop and execute
an action plan for full remediation or replacement. Based this information and miles of
EVPP, the Company expects the SSIP program, and EVPP replacement, to continue for the
foreseeable future.
INT-G-23-07
IPUC Staff PR 7
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Ryan Privratsky/ Brian Robertson
REQUEST NO. 8: Please provide a worksheet that indicates the following information
regarding early vintage steel pipe ("EVSP") in the Company's system.
a) Total amount of pipe by size and classification (main or service) that requires
replacement.
b) Total amount of EVSP pipe by size and classification (main or service) replaced
each year for the last five years.
c) Annual replacement cost.
d) A schedule by AOI of when replacement will be completed.
RESPONSE NO. 8:
a)The total amount of pipe classified as early vintage steel pipe (“EVSP”), by size
and classification (main or service), is listed below:
Classification Size (inches) Quantity (Miles)
Service
0.75 697.46
1.25 14.83
2 10.02
3 0.01
4 0.85
6 0.08
Main
0.75 7.96
1.25 27.70
2 1031.72
3 91.90
3.5 0.34
4 348.98
6 114.47
8 61.51
10 25.36
INT-G-23-07
IPUC Staff PR 8
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12 9.38
Total 2442.58
b)The total amount of main and number of service lines replaced through the
Company’s System Safety Integrity Program (“SSIP”), by size and classification (main or
service), over the last four years, is listed below:
Classification Size (inches) 2020 2021 2022 2023
Service (#) ≤ 1-1/4" 174 288 313 239
2" 2 3 4 0
Main (ft) ≤ 2" 17,624 28,382 18,660 27,480
To date the primary focus of the Company’s SSIP has been focused on the replacement
of early vintage plastic pipe (“EVPP”). EVSP has been replaced in conjunction with EVPP, but
totals have been negligible compared to EVPP totals. Totals above are primarily for the
replacement of EVPP. Replacement through the Company’s SSIP, in Idaho, didn’t formally
commence until 2020.
c)Annual replacement costs associated with the Company’s SSIP, to replace EVSP,
over the next five years, is listed below:
2024 2025 2026 2027 2028
$3,868,536.94 $4,122,216.36 $4,285,615.34 $4,453,563.62 $4,589,562.26
Annual replacement costs include the replacement of EVPP main and service.
d)The Company’s SSIP is a structured replacement program for replacing EVSP
and EVPP. EVSP is steel mains, service lines, and associated fittings installed earlier than
January 1, 1970. These pipeline segments present an increased risk of failure due to age and
obsolete materials, parts, and/or equipment. EVPP is plastic mains, service lines, and associated
fittings installed earlier than 1/1/1995. Pre-1983 EVPP is pipe installed prior to 1/1/1983 that
may be susceptible to possible Low Ductile Inner Wall (“LDIW”) characteristics that can result
INT-G-23-07
IPUC Staff PR 8
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in slow crack growth and slit failures, as documented by PHMSA–2004–19856. Post-1982
EVPP is pipe installed between 1/1/1983 and 12/31/1994 and are classified as EVPP to account
for different inventory levels and rates of new material adoption among the Company. The
Company’s SSIP utilizes the Company’s Distribution Integrity Management Program (“DIMP”)
risk model and relative risk score to establish a weighted average risk (“WAR”) score for each
town within Idaho. The WAR score is then used to identify and prioritize the Company’s
highest risk systems, based on WAR scores of EVSP and EVPP as shown below:
Pipeline operators have a requirement to implement integrity management programs
(“IMP”) that evolve and mature to fit an operator’s unique operating environment. The
evolution of an operator’s IMP program takes time and resources to collect and analyze data to
accurately identify the most current high-risk pipelines within any given system. Once a system
is prioritized and selected it typically requires multiple years to develop and execute an action
INT-G-23-07
IPUC Staff PR 8
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plan for full remediation or replacement. Based this information and miles of EVSP, the
Company expects the SSIP program, and EVSP replacement, to continue for the foreseeable
future.
INT-G-23-07
IPUC Staff PR 8
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Russ Nishikawa/ Brian Robertson
REQUEST NO. 9:
Please provide historical deliveries of LNG gas from the Nampa LNG facility to the
system (not including LNG deliveries to the Rexburg LNG Facility or to non-core customers) by
year over the past five years. For each delivery, please provide the range of dates, and hours that
the delivery occurred, the amount of gas delivered, and the reason for each delivery.
RESPONSE NO. 9:
Nampa LNG has not been called on for peak shaving or supplemental resource supply in
the past five years. However, Intermountain did prep the Rexburg LNG Facility for potential use
during the cold weather events in 2023. The Nampa LNG facility serves as the primary source
for truck deliveries to the Rexburg LNG Facility which is available to maintain pressures on the
Idaho Falls Lateral during extreme cold weather or other emergency events. The Plant has
vaporized small amounts of product into the distribution system for testing and training purposes.
INT-G-23-07
IPUC Staff PR 9
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Kathleen Campbell/ Brian Robertson
REQUEST NO. 10:
On page 101 of the IRP, the Company states that the Ustick Phase III project has been
delayed, please provide the following:
a) Current project status;
b) The latest expected project start date;
c) Current expected and direct cost estimates.
d) Please explain in detail how the project eliminated the need for the 8-inch Happy
Valley Extension project.
RESPONSE NO. 10:
a.Ustick Phase III is currently in construction and is approximately 60% complete (as
of 2/29/2024).
b.Ustick Phase III construction started in September of 2023.
c.Expected cost is the same as the cost filed in the 2023 IRP.
Direct Cost is estimated at $12,800,000.
Expected Cost/NPV cost is $12,057,698.
d.Ustick Phase III did not eliminate the need for the 8-inch Happy Valley Extension
project it instead pushed out the need for the project and eliminated the need for the
project to meet growth expectations predicted in Intermountain’ s five-year 2023 IRP
forecast. The Ustick Phase III project will boost pressures throughout the Nampa high
pressure system and eliminated the deficit previously identified that the 8-inch Happy
Valley Extension was proposed to address.
INT-G-23-07
IPUC Staff PR 10
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Kathleen Campbell/ Brian Robertson
REQUEST NO. 11:
On page 102 of the IRP, the Company states that the State Street Lateral requires a
capacity enhancement in 2023 and the State Street Uprate Phase II was selected in the 2021 IRP.
However, on page 103 of the IRP the Company states that the State Street Phase II project is
budgeted for 2024. Please reconcile how the requirement for a 2023 enhancement will be
satisfied if the selected enhancement will not be completed until 2024.
RESPONSE NO. 11:
Every year Intermountain assesses the capital budget and can shift projects around based
on project needs, resources and competing priorities. Engineering works with management on
whether or not a project can be shifted. Projects that are shifted will be reviewed and it will be
determined whether or not they can be pushed to a future year and still not result in a deficit.
Intermountain may have operational options to avoid a deficit like a temporary LNG feed and/or
manual bypassing to meet peak hour demands. The State Street lateral has experienced delays
due to land acquisition needs for the regulator station relocate. Intermountain has not been able
to acquire a regulator station site. A regulator station site is required to move the existing station
that cuts pressure from 500# to 330# further east at the end of the pressure uprate. The retest
needs to occur in summer so if IGC does not have the land required in time for the pressure
increase by this summer this project will need to be further pushed to 2025. If the project is
pushed to 2025, Intermountain will review the impacts of not completing this project and will
come up with a cold weather action plan to avoid service interruptions during cold weather
events.
INT-G-23-07
IPUC Staff PR 11
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Kathleen Campbell/ Brian Robertson
REQUEST NO. 12:
On page 104 of the IRP, the Company states that Central Ada County requires a capacity
enhancement in 2023. On page 105 of the IRP, the Company states that the project will be online
this fall. Please provide the following:
a) Current project status including regulator parts and fabrication;
b) The latest expected project completion date;
c) Current expected and direct cost estimates; and
d) Please explain in detail how 2023 capacity requirements were fulfilled absent this
enhancement.
RESPONSE NO. 12:
a.12-inch Cloverdale HP project is in-service Cloverdale/Victory regulator station is
mechanically complete but is not in-service since we are waiting to install some
equipment at the Kuna Gate Station to address operational issues. The Kuna Gate Station
is mechanically complete but is currently shut-in since Intermountain had some
operational issues to address.
b.The full Project should be online in the Spring of 2024.
c.The Project costs have not changed from the 2023 IRP filing. Current expected/NPV cost
is $17,254,430. Direct cost is estimated at $17,900,00.
d.The project was mechanically complete on 12-5-2023 and was placed into service but
was taken out of service following regulator pilot issues. The project is still useful and
could be used in an extreme weather event to boost pressures in the Ada County high
INT-G-23-07
IPUC Staff PR 12
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pressure system and avoid a deficit if warranted. Intermountain expects the full project to
be in-service Spring of 2024.
INT-G-23-07
IPUC Staff PR 12
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Kathleen Campbell/ Brian Robertson
REQUEST NO. 13:
On page 107 of the IRP, the Company states that the Shoshone Compressor will be
commissioned in September. Please provide the following:
a) Current project status;
b) The actual or expected project completion date;
c) Current or expected actual and direct costs.
RESPONSE NO. 13:
a.The Shoshone compressor is operational.
b.The Shoshone compressor was placed into service in December 2023.
c.Project costs have not significantly changed from the 2023 IRP filing. Current
expected/NPV cost is $8,769,994. Direct cost is estimated at $6,700,00. Once the
final invoices are processed, Project costs are expected to be slightly higher than
estimated due to increased contractor costs due to winter construction.
INT-G-23-07
IPUC Staff PR 13
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Brian Robertson/ Brian Robertson
REQUEST NO. 14:
On page 155 of the IRP, the Company states that the Gas Supply Oversight Committee
("GSOC") makes final decisions to address transportation shortfalls. Please provide the
following:
a) Current members of the GSOC by job title and name;
b) How often the GSOC meets and topics discussed at meetings;
c) Alternatives the GSOC evaluated to satisfy transportation constraints or shortfalls.
RESPONSE NO. 14:
a)Members of GSOC, per IGC Gas Supply Risk Management Program Appendix A:
Title Member
EVP, Business Development & Gas Supply Scott Madison (Chair)
Chief Utilities Officer Garret Senger
VP, Regulatory Affairs & Customer Service Mark Chiles
VP, Safety Process Improvement & Operations Systems Hart Gilchrist
Controller Tammy Nygard
Director, Regulatory Affairs Lori Blattner
Director, Gas Supply Chris Robbins
Upstream Resources & Special Projects Manager Mark Sellers-Vaughn
Manager, Gas Supply Eric Wood
Representative, IGI Resources, Inc. (non-voting) Randy Schultz (Recording
Secretary)
INT-G-23-07
IPUC Staff PR 14
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b)How often the GSOC meets and topics discussed at meetings;
The GSOC generally meets in one of three ways during the year (1) formal in-person and
via Teams meeting (2) semi-formal meeting via email and (3) less formal conversations (verbal
or otherwise) to discuss matters of general importance to the members and the Company. The
GSOC does not have a prescribed timing of these meetings but is more geared to matters of
importance to the Company and its customers as they arise and require discussion and potential
decisions to be acted upon.
The general topics discussed at the GSOC meetings include but are not limited to:
Current and future expected natural gas fundamentals and their effect on security of
supply and pricing
Projected PGA WACOG’s for the current PGA year and up to 4 additional out years
– these WACOG projections take into account any current fixed price hedges in place
plus an assumption that the price for all remining unhedged volumes for the
applicable PGA year were to be fixed (or locked in) based on the current futures price
curve at that moment in time.
Discussion of any additional hedging directives to be given to IGI to execute on
behalf of the Company based on the WACOG’s presented and futures prices
embedded in those WACOG’s as per the above
Adequacy of Company’s current long-term natural gas supply portfolio
Adequacy of Company’s current storage portfolio and discussion of any incremental
storage opportunities that may be available in the Company’s region
Adequacy of Company’s firm transportation portfolio for service to its customers
now and well into the future. Also, a discussion of any potential opportunities and
INT-G-23-07
IPUC Staff PR 14
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need to subscribe to any available firm transportation that may arise or discussion of
any proposed expansion projects on the horizon to participate in and the economics
associated with such to the Company and its customers
Discussion of the continuation and if so – timing and solicitation of an RFP for an
Asset Management Arrangement on the Company’s Jackson Prairie and Clay Basin
storage
Other matters of importance that may arise during the year
c)Alternatives the GSOC evaluated to satisfy transportation constraints or shortfalls.
Intermountain’s evaluation of the adequacy of its current transportation portfolio and its ability
to satisfy any constraints, OFO’s or shortfalls includes several factors – for example:
Current renewal options on existing capacity which generally are one of three options
(1) unilateral evergreen where only Intermountain could terminate the contract (2)
bilateral evergreen where both parties must agree to a renewal and (3) ROFR – right
of first refusal
Potential future capacity acquisitions via (1) permanent release from third parties or
(2) proposed participation in a pipeline expansion
Proper matching of upstream capacity on Nova, Foothills and GTN such that firm
GTN delivery at Stanfield equals the firm takeaway at Stanfield on Northwest
Pipeline
IGI’s ability to insure Intermountain adheres to any realignment or general OFO
declared by Northwest
Purchase of any renewable natural gas (RNG) that may be developed in
Intermountain’s service territory and delivered direct into its local distribution system
INT-G-23-07
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Dave Swenson/ Brian Robertson
REQUEST NO. 15:
On page 161 of the IRP, the Company discusses the potential of new commercial LNG
facilities in the region as a risk to LNG sales. Please describe and quantify all current and
potential LNG facilities that pose a risk to the Company's LNG sales.
RESPONSE NO. 15:
The statement regarding the potential risk of new commercial LNG facilities was a
generic comment to provide insight into any risks regarding the LNG facility. At this moment,
Intermountain isn’t aware of any potential projects in the region that would add risk to LNG
sales. Additionally, the Company’s sales volumes have increased year over year.
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IPUC Staff PR 15
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Brian Robertson/ Brian Robertson
REQUEST NO. 17:
On page 134 of the IRP, the Company explains that it is using PLEXOS for its
optimization model. However, in multiple areas of the IRP, the use and outputs of SENDOUT
are described or referenced. Please explain what models were used to prepare this IRP and where
they apply.
RESPONSE NO. 17:
Intermountain can confirm that SENDOUT was not used for the 2023 IRP for modeling
purposes. In many cases, using Figure 51 on page 135 as an example, an image of SENDOUT
was used because visually, the system design that shows the system map is much better than the
current system design maps in PLEXOS. Intermountain will work with PLEXOS prior to the
next IRP to improve the system design view so the Company can replace all SENDOUT images
with PLEXOS images. In an effort to clarify, the term ”sendout” (intentionally not all
capitalized), which is defined as “The total gas that is produced, purchased, or withdrawn from
underground storage in certain interval of time” is used throughout the IRP to describe total
throughput. The term “sendout” is not referring to the upstream optimization model SENDOUT.
Admittedly, Intermountain did not capture all cases of SENDOUT when referencing the
upstream optimization model in the IRP narrative. Intermountain can confirm that all modeling
was completed using PLEXOS. In an effort to clarify some reference issues, Intermountain has,
or will be, providing the word version that also includes clarification language between sendout,
SENDOUT, and PLEXOS.
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IPUC Staff PR 17
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Brian Robertson/ Brian Robertson
REQUEST NO. 18:
In the Supply Resources section of the IRP on page 140, The Company explains that
DSM resources are modeled as a supply resource in SENDOUT. Please clarify if modeling DSM
as a supply resource was done using SENDOUT OR PLEXOS and answer the following:
a)Please explain the methodology and rationale for modeling DSM programs in this
IRP;
b)Please explain what other considerations the Company gave to modeling the therm
saving impact of its DSM programs;
c)Please explain how this methodology selects DSM resources in an amount that
corresponds with the Company CPA savings estimates;
d)Please explain how selected DSM measures are used to inform the development of
the DSM supply resource;
e)Please explain how a selection of a DSM resource for an applicable AOI accounts for
the DSM impact in the relevant AOI;
f)Please explain how DSM resources are selected within the model or excluded as a not
least cost resource. Please detail all situations where DSM resources were not
selected.
RESPONSE NO. 18:
Intermountain can confirm that all upstream optimization modeling for the 2023 IRP was
completed using PLEXOS.
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IPUC Staff PR 18
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a.Demand Side Management (DSM) is an integrated process where it utilizes the
avoided cost, the conservation potential assessment, and resource integrated. The
avoided cost is the cost to serve the next unit of gas. If the Company is able reduce a
unit of gas through energy efficiency at a cheaper rate, it is in the Customers best
interest to reduce load through DSM. To determine which DSM programs are cost-
effective, the Company uses the Conservation Potential Assessment (CPA). The
CPA then estimates a projected savings amount. The projected savings amount is
then allocated to the different AOIs based on the usage system weight and is
populated into PLEXOS as a decrement to customer usage.
b.The Company modeled three DSM scenarios in addition to the Business as Usual
(BAU) case; unconstrained historical budget, medium adoption, and a high adoption.
Each of these provided the Company with differing levels of projected therm savings
and were modeled in PLEXOS. A qualitative decision was made to use the BAU
case because, as described in the IRP, “The BAU scenario is most closely aligned and
calibrated with historic program activity based on program accomplishments.”
c.Since the DSM measures were found to be cost-effective, or in other words, least
cost, the Company used all projected DSM savings from the business as usual case as
a decrement to demand in the PLEXOS model.
d.DSM measures decrement demand, which results in a lower need for an upstream
supply resource such as supply, transportation, and storage. Again, the appropriate
costs for these upstream supplies are included in the avoided cost, which is used to
measure which DSM programs are cost-effective in reducing these upstream supplies.
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IPUC Staff PR 18
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e.Once the projected savings are established from the BAU case, as well as the
scenarios, Intermountain uses a town weighting system to allocate the DSM savings
by AOI. This is currently the best methodology to include DSM into PLEXOS, which
is modeled at the AOI level. Similar to response d, DSM resources reduce demand,
which lowers the need for an upstream supply resource.
f.All cost-effective projected therm savings for the business as usual case were
included in the PLEXOS model as they are determined to be least cost through the
Avoided Cost and CPA process. All DSM resources were selected in PLEXOS.
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IPUC Staff PR 18
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INTERMOUNTAIN GAS COMPANY
CASE INT-G-23-07
FIRST PRODUCTION REQUEST OF THE COMMISSION STAFF
Preparer/Sponsoring Witness: Brian Robertson/ Brian Robertson
REQUEST NO. 19:
Please reconcile the Company's customer forecast annual growth rate of 2.8% on page
112 and base case scenario annual growth rate of 2.56% on page 114. Additionally, please
answer the following:
a)Please explain which growth rate was used in the 2023 IRP model; and
b)Please explain the impact the used growth rate had on the modeled customer demand
in the 2023 IRP.
RESPONSE NO. 19:
a)It appears the growth rate on page 112 was mislabeled. The correct growth rate is
2.56% and 66,100 customers.
b)The growth rate value is a result of the Company’s econometric models that are
described on page 12. Intermountain utilizes ARIMA models, along with population
and employment growth rates to estimate the Company’s residential and commercial
customer count growth by each AOI. Utilizing the forecasted customer growth
counts, Intermountain can then calculate a growth rate.
INT-G-23-07
IPUC Staff PR 19
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