20220621Final_Order_No_35438.pdf

ORDER NO. 35438 1
Office of the Secretary
Service Date
June 21, 2022
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF INTERMOUNTAIN
GAS COMPANY’S 2021-2026 INTEGRATED
RESOURCE PLAN
)
)
)
)
CASE NO. INT-G-21-06

ORDER NO. 35438

On December 20, 2021, Intermountain Gas Company (“Company”) filed its Integrated
Resource Plan (“IRP”) for 2021-2026.
On January 11, 2022, the Commission issued Notice of the Company’s Filing and Notice
of Intervention Deadline. Order No. 35289. No party intervened in this case.
On March 7, 2022, the Commission issued a Notice of Modified Procedure establishing
deadlines for interested parties to comment on the Filing and for the Company to reply.
On April 28, 2022, Commission Staff (“Staff”) submitted the only comments filed in this
case.
With this Order we acknowledge the Company’s IRP.
BACKGROUND
The Company files an IRP every two years describing the Company’s plans to meet its
customers’ future natural gas needs. The IRP must discuss the subjects required by Commission
Order Nos. 25342, 27024, 27098, 32855, 33314, 33997, and 34742, and section 303(b)(3) of the
Public Utility Regulatory Policies Act of 1978 (“PURPA”), 15 U.S.C. § 3202. The Commission
reviews the IRP to ensure it discusses the required subjects and shows the Company has diligently
planned for the anticipated supply and demand for natural gas.
In Order No. 25342, the Commission adopted IRP requirements for local gas distribution
companies in response to amended Section 303 of PURPA. In Order No. 27024, the Commission
shortened the IRP’s planning horizon from 20 to 5 years. In Order No. 27098, the Commission
removed requirements that IRPs formally evaluate potential demand-side management (“DSM”)
programs and instead directed companies to explain whether cost-effective DSM opportunities
exist. In Order No. 32855, the Commission directed the Company to continue to improve public
participation in the IRP process and allowed the Company to stop filing semi-annual lost and
unaccounted for gas reports. In Order No. 33314, the Commission directed the Company to better
detail how it calculates avoided costs and uses those calculations to determine whether natural gas
DSM opportunities are cost-effective. In Order No. 33997, the Commission found it reasonable

ORDER NO. 35438 2
for the Company to convene an IRP advisory group to develop future IRPs that comprehensively
and transparently consider demand, existing resources, and potential supply and demand-side
options for meeting any deficits.
Finally, in Order No. 34742, the Commission found it reasonable for the Company to
include an analysis of the options it considered to resolve deficits and achieve the most cost-
effective, least risk solutions, and to use actual peak information from the Company’s Advanced
Metering Infrastructure (“AMI”) meters to validate the peak consumption estimates.
In summary, these orders direct the Company to file an IRP every two years that includes:
1. A forecast of future gas demand in firm and interruptible markets for each customer
class, which includes the number, type, and efficiency of gas end-users as well as
effects from economic forces on gas consumption;

2. An analysis of gas supply options for each customer class, which includes a
projection of spot market versus long-term purchases for both firm and interruptible
markets, an evaluation of the opportunities for using company-owned or contracted
storage or production, an analysis of prospects for company participation in a gas
futures market, and an assessment of opportunities for access to multiple pipeline
suppliers or direct purchases from producers;

3. A comparative analysis of gas purchasing options and improvements in the efficient
use of gas, and an explanation of whether there are cost-effective DSM
opportunities;

4. The integration of the demand forecast and resource evaluations into a long-range
(at least a five-year) plan describing the strategies designed to meet current and
future needs at the lowest cost to the utility and its ratepayers;

5. A short-term (e.g., two-year) plan outlining the specific actions to be taken by the
utility in implementing the IRP;

6. A progress report that relates the new plan to the previously filed plan; and

7. Conclusions and analyses informed by robust public participation and the most up
to date information.
THE 2021-2026 IRP
The Company stated that it regularly forecasts the demand of its growing customer base
and determines how to best meet the load requirements brought on by this demand. IRP at 1-2.
The Company represented that, as of 2021, it had 387,000 customers in two major markets: the
residential/commercial market and the large volume market. Id. at 2. The Company informed that
residential and commercial customers primarily use natural gas for space and water heating and

ORDER NO. 35438 3
that large volume customers transport natural gas through the Company’s system for use in boiler
and manufacturing applications. Id.
The Company stated that agricultural economy and the price of alternative fuels strongly
influence large volume demand for natural gas. Id. During 2020, large volume sales and
transportation accounted for nearly 50 percent of the throughput on the Company’s system. Id.
The Company stated it forecasted changes in its peak-day loads due to customer growth under base
case, high, and low growth economic scenarios. Id. In the IRP, the Company forecasted a base
case growth scenario in which its total residential, commercial, and industrial peak-day loads
increased each year for five years by an average of 2.18 percent in the base case scenario. Id. at
123. The Company saw no peak-day delivery deficits over the next five years when it matched its
forecasted peak-day delivery against its existing resources. Id. at 4-5.
To enhance the IRP, the Company established the Intermountain Gas Resource Advisory
Committee (“IGRAC”) Id. at 4. The intent of the IGRAC was to provide a forum to facilitate
public participation in developing the IRP. Id. The Company solicited advisory committee
members from across its service territory and held meetings on a virtual platform and provided a
comment period after each meeting to ensure timely feedback and incorporation into the IRP. Id.
at 4, 5.
The Company also analyzed different geographic areas in its service territory to plan to
meet any projected deficits in those areas. Id. at 10. In this IRP, the Company analyzed the Idaho
Falls Lateral (“IFL), the Sun Valley Lateral (“SVL”), Canyon County Area (“CCA”), the State
Street Lateral (“SSL”), Central Ada County (“CAC”), and the All Other segment. Id.
The Company represented that the IFL was 104 miles long and served cities between
Pocatello and St. Anthony in eastern Idaho. Id. at 111. In the base case scenario, customers in the
IFL were expected to increase by 9,493 (a 2.54 percent annualized growth rate) over the IRP
period. Id. at 119. The Company stated that, after completion of its proposed capacity upgrade,
there would be no deficit in the final year of the planning horizon under the base case scenario. Id.
at 157.
The Company represented that the SVL was 68 miles long and had almost its entire demand
at the far end of the lateral away from the gas source. Id. at 108. In the base case scenario,
customers in the SVL were projected to increase by 1,262 (a 1.61 percent annualized growth rate)
over the IRP period. Id. at 119. With continued demand growth, a second compressor station had

ORDER NO. 35438 4
been selected (Shoshone Compressor Station) to enhance the SVL further downstream from the
existing Jerome Compressor. Id. at 110. The Company asserted this second station would be
completed by 2023 and would increase capacity beyond the remaining five-year growth outlook
of the IRP. Id. at 111.
The Company represented that the CCA consisted of an interconnected system of high-
pressure pipelines that served communities from Star Road west to Highway 95. Id. at 96. In the
base case scenario, customers in the CCA were expected to increase by 15,324 (a 4.00 percent
annualized growth rate) over the IRP period. Id. at 119. For this IRP, the Company represented a
capacity enhancement was needed by both 2021 and 2023 to meet IRP growth predictions. Id. at
96. The Company stated that it selected Ustick Phase II (in the 2019 IRP) and Ustick Phase III to
meet the IRP growth predictions. Id. at 100. The Company indicated that Ustick Phase II would
be completed by the end of 2022 and Ustick Phase III would be completed in 2023. Id.
The Company represented that the SSL in northwest Boise was 16 miles long and served
the towns and areas of Middleton, Star, north Meridian, Eagle, and northern Boise. Id. In the base
case scenario, SSL customers were expected to increase by 12,008 customers (a 3.25 percent
annualized growth rate) for the IRP period. Id. at 119. The Company asserted this area was ideally
suited for a pipeline retest and uprate on the 2.3 miles of 12-inch high-pressure (“HP”) steel pipe
on State Street and 2 miles of 4-inch HP steel pipe on Linder Road in conjunction with the
installation of a HP regulator station. Id. at 101. The retest, uprate, and regulator station
installation, the Company asserted, was the lowest cost option, would meet 2026 growth
predictions, and would be completed in 2023. Id. at 104.
The Company represented that the CAC in the Boise area consisted of multiple high-
pressure and intermediate pressure pipeline systems. Id. at 104. In the base case scenario, CAC
customers were expected to increase by 6,300 customers (a 1.77 percent annualized growth rate)
during the IRP period. Id. at 119. The Company stated that, due to significant growth in Boise and
Meridian, the CAC area of interest required a capacity enhancement by 2022 to meet IRP growth
predictions. Id. at 104. The Company determined that installing a 3.7 mile, 12-inch HP steel pipe
on Cloverdale Road from the Kuna Gate north to Victory Road (12-inch South Boise Loop) was
the best option to meet IRP growth predictions. Id. at 105, 108. The Company represented that the
12-inch South Boise Loop was currently in the design phase, with construction planned to be
completed in 2022. Id. at 108.

ORDER NO. 35438 5
In sum, the Company stated the IRP analyzed residential, commercial, and industrial
customer growth and its impact on the Company’s distribution system using design weather
conditions under various scenarios. Id. at 5. The Company further stated it analyzed resources to
meet any projected deficits within a framework of options to help determine the most cost-effective
means to manage the deficits. Id. The Company stated these options allow its core market and firm
transportation customers to rely on uninterrupted service now and in the future.
STAFF COMMENTS
Staff believed that the Company’s IRP satisfied Commission requirements, was
reasonable, and should be acknowledged.
1. Demand Forecast
Staff noted that the Company’s demand forecast was used to determine the timing and
capacity of new plant additions which will eventually be included in the Company’s rate base.
Staff believed the Company’s methodology for estimating future demand was adequate.
Staff noted the Company forecasted changes in its peak-day loads due to customer growth
under its low growth, base case, and high and low growth economic scenarios. Staff further noted
the Company forecasted total residential, commercial, and industrial peak-day loads to increase
each year for five years by an average of 1.14 percent (low growth), 2.18 percent (base case) and
3.10 percent (high growth). Staff Comments at 4.
Staff noted the Company identified the timing and magnitude of potential deficits on both
a total system perspective and within its Areas of Interest (“AOI”). Id. Staff noted the Company
evaluated and compared potential capacity improvement alternatives for each identified capacity
deficit in its optimization model and calculated and compared the net present value (“NPV”) cost,
the amount of capacity, and capacity gain for each potential capacity improvement. Id.
Per Staff’s recommendation in the 2019 IRP, the Company validated the accuracy of peak
estimates obtained from the per customer usage models in the 2021 IRP. However, Staff still
believed, as it believed in the 2019 IRP, that the Company should quantify the effects of new
building codes and the Company’s energy efficiency programs and incorporate estimates into its
per customer usage models.
2. Deficits and AOI Summaries
Staff noted the Company projected the following deficits in its service territory over the
2021–2026 IRP planning period: (1) Canyon County AOI; (2) SSL; (3) CAC; (4) SVL; and (5)

ORDER NO. 35438 6
IFL. Id. at 5. Staff noted the Company provided capacity analysis, identified when deficits would
occur, and described enhancements to resolve identified deficits. Staff recommended the Company
provide Staff with capacity and cost information as enhancement projects were completed and
brought online.
3. Supply Options
Staff stated the Company’s service territory was located between the Western Canadian
Sedimentary Basin (“WCSB”) located in Alberta and British Columbia and the Rockies region
located in Wyoming, Colorado, and Utah. Staff noted that a “bi-directional interstate pipeline
operated by Northwest Pipeline runs through the Company’s territory and enables purchases from
both regions. The WCSB supplies approximately 79% of the Company’s natural gas.” Id. at 8.
Staff noted that the Company utilized natural gas storage as a capacity resource and
currently had storage capacity at four facilities—one of which was owned by the Company and
located in Nampa, Idaho.
a. Nampa LNG Facility
Staff noted that, while liquifying natural gas is energy intensive and that using liquified
natural gas to meet demand beyond needle peaking events was costly, gas from the Nampa facility
was essential for meeting the IFL’s needle peak demand. Id. at 9.
b. Demand Side Management (DSM)
Staff noted the Company continued to use the 2019 Conservation Potential Assessment
(“CPA”) conducted by Dunsky to estimate the 2021 IRP DSM therm savings. Staff was concerned
that the Company’s estimated therm savings may be overstated from using the 2019 CPA. Staff
recommended the Company vet future CPA results to ensure the savings estimates and
assumptions were reasonable and achievable. Staff cautioned that, as “the Company’s DSM
portfolio matures and begins to achieve higher levels of savings, the . . . portfolio will begin to
have a bigger impact on avoiding costly upgrades to the Company’s system” and, therefore,
accurate CPA results were important. Id.
c. DSM Avoided Cost
Staff noted that the 2021 IRP avoided cost calculation did not include distribution costs.
However, Staff further noted that it was refining the avoided cost calculation with the Company
and the Company’s Energy Efficiency stakeholder group.

ORDER NO. 35438 7
d. Renewable Natural Gas
Staff stated that renewable natural gas (“RNG”) was produced by the decomposition of
organic material and was pipeline quality gas that was fully interchangeable with conventional
natural gas. Id. at 10. Staff noted the Company’s involvement with the development of the RNG
industry in Idaho and that the Company currently had multiple RNG producers on its system in
the Magic Valley and expected more. Id. at 11.
4. Progress Since the Previous IRP
Staff appreciated the Company’s incorporation of Staff’s recommendations from the
previous IRP in the 2021–2026 IRP, particularly in the following areas: (1) Cost-Effective Least
Risk Solutions; (2) Peak Consumption Validation; and (3) use of the IGRAC. That said, Staff
encouraged the Company to continue to enhance the Peak Consumption Validation process as
more AMI data became available. Staff also believed the Company could increase participation in
the IGRAC by providing materials to members before meetings and making IRP information
accessible on its website. Id. at 12.
5. Lost and Unaccounted for Gas (LAUF)
Staff recognized the Company’s efforts in managing LAUF Gas and believed the
Commission requirements were satisfied in this filing.
6. Staff Recommendations
Staff believed the Company’s IRP met the Commission’s requirements and recommended
the Commission acknowledge it. Staff further recommended that the Company: (1) provide
capacity enhancement project costs and NPV information when capacity improvement projects
were completed and placed in service; and (2) continue to enhance public participation through
the IGRAC process.
FINDINGS AND DISCUSSION
The Company is a natural gas corporation and public utility. See Idaho Code §§ 61-116, -
117, and -129. The Commission has jurisdiction over the Company and the issues in this case
under Title 61 of the Idaho Code, including Idaho Code § 61-501.
The Commission has reviewed the record, including the Company’s IRP, and Staff’s
comments. Based on our review, the Commission finds the IRP substantially complies with the
Commission’s prior orders. The Commission thus acknowledges that the Company has filed its
IRP. In doing so, we reiterate that an IRP is a working document that incorporates many

ORDER NO. 35438 8
assumptions and projections at a specific point in time. It is a plan, not a blueprint, and by issuing
this Order we merely acknowledge the Company’s ongoing planning process, not the conclusions
or results reached through that process. With this Order, we do not approve the IRP or any resource
acquisitions referenced in it, or endorse any particular element in it, and we offer no opinion on
the prudency of the Company’s election of its preferred resource portfolio. The appropriate place
to determine the prudence of the IRP or the Company’s decision to follow or not follow it, and the
validation of predicted performance under the IRP, will be a general rate case or other proceeding
in which the issue is noticed. Order Nos. 24981 and 25342.
The Commission also acknowledges Staff’s comments and recommendations. In
particular, we find it reasonable that the Company provide capacity enhancement project costs and
NPV information when capacity improvement projects are completed and placed in service. We
further find it reasonable that the Company continue to enhance public participation through the
IGRAC process by providing materials to members before meetings and making IRP information
accessible on its website.

[Remainder of this page intentionally left blank]

ORDER NO. 35438 9

O R D E R
IT IS HEREBY ORDERED that the filing of the Company’s 2021-2026 IRP is
acknowledged.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order regarding any matter
decided in this Order. Within seven (7) days after any person has petitioned for reconsideration,
any other person may cross-petition for reconsideration. See Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 21st day of
June 2022.

ERIC ANDERSON, PRESIDENT

//Abstained to Avoid Conflict//
__________________________________________
JOHN CHATBURN, COMMISSIONER

JOHN R. HAMMOND JR., COMMISSIONER

ATTEST:

__________________
Jan Noriyuki
Commission Secretary

I:\Legal\GAS\INT-G-21-06 IRP\orders\INTG2106_final_rn.docx