20240509Staff Comments.pdf

RECEIVED
2024 May 9, 4:03PM
IDAHO PUBLIC
UTILITIES COMMISSION
CHRIS BURDIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 9810
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG8, SUITE 201-A
BOISE, IDAHO 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF INTERMOUNTAIN )
GAS COMPANY'S 2023 INTEGRATED ) CASE NO. INT-G-23-07
RESOURCE PLAN )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission, by and
through its Attorney of record, Chris Burdin, Deputy Attorney General, submits the following
comments.
BACKGROUND
On December 28, 2023, Intermountain Gas Company("Company") filed its 2023
Integrated Resource Plan ("2023 IRP") with the Idaho Public Utilities Commission
("Commission"). The Company requests that the Commission issue an order acknowledging the
Company's 2023 IRP. The Company files an IRP every two years to describe its plans to meet its
customers' future natural gas needs. The IRP must discuss the subjects required by several
Commission Orders' and Section 303(b)(3) of the Public Utility Regulatory Policies Act
' See Order Nos.25342,27024,27098,32855,33314 and 33997.
STAFF COMMENTS 1 MAY 9, 2024

("PURPA"), 15 U.S.C. § 3202. The Commission reviews the IRP to ensure that it discusses these
subjects and represents a diligent effort by the Company to plan for the anticipated supply and
demand for natural gas.
The 2023-2028 IRP
In the 2023-2028 IRP, the Company explains that it regularly forecasts demand of its
growing customer base and determines how to best meet the load requirements brought on by this
demand. 2023 IRP at 2-3. The Company's IRP represents a snapshot in time of the Company's
ongoing planning process; it describes the anticipated conditions over a five-year planning
horizon, the anticipated resource selections, and the process for making resource decisions. Id. at
1.
The Company sells natural gas to two major markets: the residential/commercial market
and the large volume market. Id. at 2. In 2020, roughly 50% of throughput on the Company's
system was related to large volume sales and transportation. Id. Currently, the Company serves
approximately 412,500 customers. Id. at 1.
The Company calculated peak-day delivery under base, low growth, and high growth
scenarios against current available natural gas delivery system capacity to project the magnitude
and timing of delivery deficits on a regional and a total Company perspective.
STAFF ANALYSIS
Staff examined the Company's 2023 IRP to determine whether it meets the Commission
requirements and orders, and adequately plans its future resources to meet demand from 2023
through 2028. Staff believes that the Company's 2023 IRP satisfies Commission requirements
and is reasonable. Staff recommends the Commission:
1. Acknowledge the Company's 2023 IRP;
2. Order the Company to work with Staff to implement IRP reporting that includes
system enhancement information in future IRPs, within six months of a Commission
order;
3. Order the Company to work with Staff to develop reports to the Commission of
capacity enhancement projects that include in-service dates and project costs, within
six months of a Commission order; and
STAFF COMMENTS 2 MAY 9, 2024

4. Establish the practice of authorizing the Company's Demand Side Management
("DSM") avoided costs as part of IRP filings and authorize the DSM avoided costs
associated with this filing.
Demand Forecast
The Company's demand forecast is used to determine the timing and capacity of new
plant additions. The demand forecast is an important driver of expenditures that will eventually
be included in the Company's rates. Staff reviewed the Company's methodology for estimating
future demand and believes it is adequate.
The Company's demand forecast is based on three separate components: 1) a prediction of
the number of customers; 2) a forecast of weather sensitive customers' response to temperatures;
and 3) an estimate of the weather customers may experience. Id. at 11. The Company also
includes contracted maximum deliveries to industrial customers in its demand forecast.
The Company forecasted changes in its peak-day loads due to customer growth under its
low,base case, and high growth economic scenarios. The Company forecasted total residential,
commercial, and industrial peak-day loads to increase each year for five years by an average of
1.84% (low growth), 2.56% (base case), and 3.22% (high growth). Id. at 114.
The Company identified deficits on both a total system perspective and within its Areas of
Interest("AOI"). Id. at 5. For each potential deficit, timing and magnitude were identified. The
Company evaluated and compared potential capacity improvement alternatives for each identified
capacity deficit in its optimization model. The Company calculated and compared the NPV cost,
the amount of capacity, and capacity gain for each potential capacity improvement, which are
described in greater detail in the Deficits and AOI Summaries sections below.
Deficits and AOI Summaries
Over the 2023-2028 IRP planning period, the Company projected delivery capacity
deficits within each AOI and within other areas of its territory: 1) Canyon County AOI, 2) State
Street Lateral, 3) Central Ada County AOI, 4) Sun Valley Lateral, and 5) Idaho Falls Lateral. Id.
at 98 — 110. In this IRP, the Company provided capacity analysis, identified when deficits will
occur, and described enhancements to resolve identified deficits. Staff reviewed the Company's
STAFF COMMENTS 3 MAY 9, 2024

method for determining the design day, and the resulting peak-delivery requirements under
various growth assumptions and believes the Company's analysis is reasonable.
For each of the five AOIs, Staff noted that there were differences between the year the
Company said it needs a project and when the corresponding Load Demand Curve ("LDC")
shows a capacity deficit. The Company clarified that projects must typically be started in a year
that precedes the forecasted deficit year,because projects often take more than one year to
complete. Response to Production Request No. 27. Therefore, the IRP often states that a project
is needed in a year that precedes the actual deficit.
Staff commends the Company for the improvements it has made in this section of the IRP.
As the information in this section is so foundational to subsequent capital prudence reviews, Staff
encourages the Company to include additional information for capacity enhancements that are (1)
budgeted to begin after the IRP, (2) status updates for ongoing capacity enhancements that are
budgeted to start during the IRP year, and(3)the in-service date and final cost information for
completed capacity enhancements between the previous IRP and the current one. Staff
recommends that the Commission order the Company and Staff to work together to implement an
IRP reporting methodology to include additional information on enhancement selections within
future IRPs, within six months of a Commission order. Staff believes that this additional
information will assist tracking capacity enhancements through future IRPs.
A summary of the capacity enhancements within each AOI included in the 2023 IRP and
any of Staff s specific conclusions are provided below.
Canyon County Area
The Canyon County AOI serves core market customers in Canyon County. The LDC
analysis shows an AOI deficit occurring in 2024. In the 2021 IRP, the Company considered three
alternatives to meet growth predictions, and selected"Ustick Phase III". The Company stated
that "Ustick Phase III was chosen in 2021 as the largest_ capacity increasing alternative." 2023
IRP at 100 (emphasis added).
To better understand the Company's justification for selecting the Ustick Phase III
alternative, Staff asked the Company to provide its business case analysis. The Company
explained that"Cost is a consideration in the alternative analysis but is not the decidingf ."
STAFF COMMENTS 4 MAY 9, 2024

Response to Production Request No. 28 (emphasis added). Staff is concerned that this
enhancement may not have been the least-cost least-risk alternative.
State Street Lateral
The State Street Lateral serves core market customers in the Star, Eagle, Meridian, and
northwest Boise areas. The LDC analysis shows the first AOI deficit occurring in 2028. In the
2021 IRP, the Company considered two alternatives and selected the "State Street Phase II
Uprate" as the lowest cost alternative. 2023 IRP at 102. The Company stated that it budgeted the
State Street Phase II Uprate for 2024 at an estimated cost of$902,000. Id. at 103. Staff accepts
the Company's assertion. However, for future IRPs, Staff requests that the Company present each
alternative with updated costs to confirm the preferred alternative is still lowest cost.
The Company also clarified that the State Street Phase II Uprate project will require an
additional project, the "State Penn Gate Uprate," and the Company explained why this project
was the only alternative. The Company estimated the "State Penn Gate Uprate"project will cost
$2,730,000 and targeted it for construction in 2026. Id. Staff accepts the Company's explanation
of why no alternatives could be considered for this project.
Central Ada County
The Central Ada County AOI serves core market customers in Ada County between
Chinden Boulevard and Victory Road, north to south, and east of Black Cat Road. The LDC
analysis shows the first AOI deficit occurring in 2025, with the infrastructure chokepoint being
the distribution piping immediately downstream from the Meridian Gate. In the 2021 IRP, the
Company considered three alternatives, and selected the "12-inch South Boise Loop"project
because it was "the lowest cost option with the most capacity gained." Id. at 104. The Company
believes the project will eliminate any capacity deficit until beyond 2028.
The Company estimates the 12-inch South Boise Loop project will be online in fall of
2024 and its total cost will be $17,900,000. The project consists of three major sub-projects: The
completed 12-inch Cloverdale project, the installed Kuna Gate project, and the almost completed
Victory and Cloverdale Regulator project.
STAFF COMMENTS 5 MAY 9, 2024

Staff appreciates the Company's update of this ongoing project and encourages the
Company to document the final costs and in-service dates for the three sub-projects in the next
IRP.
Sun Valley Lateral
The Sun Valley Lateral ("SVL") serves core market customers in Blaine and Lincoln
counties. The SVL is a 68-mile long, 8-inch high-pressure pipeline, with a compressor station
located near the city of Jerome, Idaho. Most of the demand on this lateral is furthest from its
source. The LDC analysis shows the first AOI deficit occurring in 2024, with the infrastructure
chokepoint having insufficient pressure at the north end of the line, in the Ketchum area. Id. at
106.
The Company considered alternatives in the 2019 IRP and again in the 2021 IRP,both
times concluding that the Shoshone Compressor Station was the least-cost least-risk solution.
The project was completed in time for the 2023-2024 winter season and its estimated cost was
$6,700,000. The Company believes the project will eliminate any capacity deficit beyond 2028.
Staff appreciates the Company's update of this ongoing project and encourages the Company to
document the final cost and in-service date in the next IRP.
Idaho Falls Lateral
The Idaho Falls Lateral serves core market customers in Bingham, Bonneville, Fremont,
Jefferson, and Madison counties. It originates south of Pocatello and extends north approximately
100 miles to Saint Anthony. The LDC analysis shows the first AOI deficit occurring in 2027,
with the infrastructure chokepoint being at the end of the line at Saint Anthony.
The Company considered two alternatives in the 2021 IRP and chose the Blackfoot
Compressor Station as the least-cost option while providing the largest capacity to the lateral. Id.
at 108. The Company expects the project to come online in 2024, estimates its cost will be
$20,000,000, and that the project will satisfy predicted growth through 2028. Staff appreciates
the Company's update of this ongoing project and encourages the Company to document the final
cost and in-service date in the next IRP.
STAFF COMMENTS 6 MAY 9, 2024

Other AOI Capacity Projects
The Company described two gate upgrades needed to support core growth, but fall outside
of the defined AOIs. The gates that serve Payette and New Plymouth are approaching their
physical capacity limit, requiring the Company to enlarge the undersized piping and components.
The Company estimates the Payette Gate Upgrade will cost $3,490,000 and the New Plymouth
Gate Upgrade will cost $2,760,000.
Staff accepts the Company's explanation of why no alternatives are possible for these
projects but will ask for evidence that the physical capacity limits have been reached when the
Company requests a determination of prudence. Staff also encourages the Company to document
the final cost and in-service dates for each gate project in the next IRP.
Five Year Plan
One of the requirements of a natural gas IRP is for the Company to include integration of
the demand forecast and resource evaluations into a short term (e.g., two-year) and 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. As illustrated in Table No. 10 of the Company's 2023
IRP, two enhancements are detailed within the next two years; the Idaho Falls lateral compressor
in 2024 and the State Street Uprate in 2025. The Company provided the following table to
summarize its five-year plan. Id. at 111.
Table 10: Five-Year Planning and Timing of Capacity Enhancements Selected
Aol Ed
Yearl
2023 870,(N)0 12-inch S 820,000 None 1,390,000 12-inch 247,5410 Shoshone L u None
Boise Loop Ustick Compressor
Phase III station
2024 870,000 None 82(I,INNI None 1,390,000 None 247,5(N) None 1,093,M) IFL
Compressor
Station
2025 870,000 None 950,000 State Street 1390,000 None 247,5(x) None 1,093,M) None
U rate
'CO 970,000 None 950,W) State Penn 1,.390,000 None 247,500 None 10,930,M) None
Gate
Upgrade
2027 870,000 None 950,(xx) None 1390,000 None 247,5(x) None 10,930,000 None
202H 870,1N10 None 950,1NN1 None 1390,000 None 247,51M) None I 1,093,M) None
STAFF COMMENTS 7 MAY 9, 2024

The Company will review its five-year plan deficits and alternatives considered for
capacity enhancement in development of the 2025 IRP. The Company will modify its plan as
needed to meet demand predictions and ensure safe, reliable service to its customers. Staff will
continue to review the capacity enhancements selected in the Company's future IRPs.
Supply Options
The Company's service territory is located between the Western Canadian Sedimentary
Basin ("WCSB") located in Alberta and British Columbia and the Rockies region located in
Wyoming, Colorado, and Utah. 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 41.
The Company utilizes natural gas storage as a capacity resource. Currently, the Company
has storage capacity in four facilities. Two of the facilities, one at Jackson Prairie and the other at
Plymouth, Washington, are operated by Northwest Pipeline. A third facility, the Dominion
Energy storage field("Clay Basin"), is located near the Utah and Wyoming border. The fourth
storage facility, the Company-owned LNG facility, located in Nampa, Idaho, is described in
greater detail below.
Nampa LNG Facility
The Nampa LNG plant is primarily used to supplement gas supply onto the Company's
distribution system. The plant is capable of storing up to 600 million cubic feet of LNG. The
plant can re-gasify approximately 60 million cubic feet per day and inject the gas into the
Company's Canyon County and Ada County distribution systems when needed.
During off-peak months, the Nampa LNG facility obtains pressurized natural gas from the
Canyon County lateral, liquifies it, and then stores it in a large steel storage tank with a capacity
equivalent to 600 million standard cubic feet of gas (about 600,000 Dth). The liquified gas is
withdrawn to supply the Company's non-utility customers; and during winter months, liquified
natural gas is trucked from the Nampa LNG facility to the Company's gasification facilities along
the Idaho Falls Lateral. Natural gas liquification is an energy intensive process and using
liquified natural gas to meet demand for purposes beyond needle peaking events can be costly.
STAFF COMMENTS 8 MAY 9, 2024

However, gas trucked from the Nampa facility to the Company's degasification facilities along
the Idaho Falls lateral is essential for meeting that lateral's needle peak demand.
Purchasing Options
As part of the IRP, the Company creates a base, high, and low natural gas price forecast
based on pricing forecasts sourced from Wood Mackenzie, EIA, S&P Global,NYMEX Henry
Hub, and Northwest Power and Conservation Council. 2023 IRP at 50. The Company states that
it utilizes a proprietary model to select a monthly base price projection for purchase points for the
AECO, Rockies and Sumas markets. The forecasts for these can be shown in Chart 1 (Figure 26)
below. The Company uses this type of analysis, along with input from its Gas Oversight
Committee, to hedge a portion of its gas supply portfolio at fixed priced forward physicals.
Chart 1. Company Natural Gas Price Forecast
IGC Natural Gas Price Forecast (as of 2023)
530.00
525.00
$20.00
m
$15.00
N
510.00
S.
50.00
,L'1. 1" .L'� .Lp ,tiP �P .1'-� "1h 'l�o .tiro 'b'o •ti'� •ti'� ;10 ,y4
Sumas Rockies AECO Weighted
Figure 26: Intermountain Price Forecast as of 03/1/2023
DSM Opportunities
Conservation Potential Assessment
In the 2023 IRP, the Company contracted with Guidehouse ("Evaluator") to conduct the
2023 Conservation Potential Assessment ("CPA") to estimate the DSM therm savings for the
forecast horizon, which is included as Exhibit No. 4. In Order No. 35663, the Commission
approved the Company's proposal to base DSM program planning on the most recently filed IRP.
STAFF COMMENTS 9 MAY 9, 2024

Because of this change, Staff has placed additional scrutiny on the CPA forecast used to inform
future DSM offerings. Staff is concerned that the Company used over-stated therm savings data
to calibrate its models, thus overstating the forecasted energy savings potential.
The CPA explains that models for future Energy Efficiency ("EE") offerings were
calibrated using historic data from the Company's 2021 EE Annual Report. CPA at 18. When
the 2021 EE Annual Report was filed in Case No. INT-G-22-03, Staff disagreed with the
estimates that the Company used to report savings for the Whole Home and Furnace programs. In
that report, the Company used an estimated Furnace rebate savings of 86 therms per furnace
sourced from the Company's 2019 CPA and provided an internal evaluation("Internal
Evaluation")which was used to support the use of the CPA estimate over the more recent 2020
Impact Evaluation. For the Whole Home Tier I and II rebates, the Company used estimates of
161 therms/unit and 128 therms/unit respectively. These estimates were the result of a simulation
analysis provided as part of the Company's 2020 Evaluation Measurement and Verification
("EM&V") impact evaluation.2 The 2020 EM&V included a statistically rigorous analysis based
on the measurable savings of customer bills ("Billing Analysis") and an alternative analysis that
estimated savings using Home Energy Rating System models for each project compared to a
reference model that reflected Idaho building code requirements ("Simulation Analysis").
Since the 2020 EM&V was published in Case No. INT-G-20-06, Staff has consistently
stated its concern over the use of the estimates provided by Simulation Analysis instead of Billing
Analysis to report program savings. Additionally, in Case No. INT-G-22-03, Staff commented
that the Company's Internal Evaluation was flawed by excluding a significant portion of the
program's rebates and that the therm savings should have been lower. In Order No. 35663, the
Commission directed the Company to use the Billing Analysis to evaluate the performance of the
Furnace and Whole Home measures and comported with previous orders to immediately and
continuously monitor, evaluate, and update its EE program incentives with the best available data.
The results of the Billing Analysis estimate savings of 56 therms/unit for the Furnace measure
using a matched control group analysis and 29 therms/unit using a pre-post analysis. For the
Whole Home rebate, the Billing Analysis estimates savings of 58 therms/unit using a matched
control group analysis.
2 Case No.INT-G-20-06 Supplement to Application for details on the Simulation Analysis and Billing Analysis.
STAFF COMMENTS 10 MAY 9, 2024

For the purpose of calibrating its models for these measures, the Evaluator used the result
from the Company's Internal Evaluation of 81 therms/unit for the Furnace measure. Response to
Production Request No. 24. For the Whole Home Tier I and Tier II measure, the Simulation
Analysis results of 161 therms/unit and 128 therms/unit were used. Response to Production
Request No. 33. By using therm savings estimates that are higher than what is supported by the
Billing Analysis to calibrate its models, Staff believes that the Company has overstated the
savings potential of these measures.
Further, for measures with no historic data, the model was calibrated using historical data
from existing measures that shared a similar end use. Response to Production Request No. 25.
Staff believes the inputs for the Furnace and Whole Home measures are overstated; therefore, any
measure calibrated to these inputs is likely also overstated. Staff cautions the Company on
planning any program changes to the Whole Home or Furnace measures based on the results of
this CPA or planning new measures that are calibrated using the same end uses as the Furnace and
Whole Home measures.
Overall, Staff does not anticipate any significant impact to the IRP demand forecasts due
to changes in the CPA savings potential. Currently the Company's CPA estimates less than 1.5
mmtherms saved per year, which is not a significant amount relative to the demand forecast in the
scale of hundreds of mmtherms. As the Company's DSM portfolio matures and begins to achieve
higher levels of savings, the Company's DSM portfolio will begin to have a bigger impact on
avoiding costly upgrades to the Company's system. Therefore, it is important to have accurate
CPA results. Staff notes that its observations may mean that portions of the CPA are not used or
useful because of the overstated input data; however, this does not necessarily apply to the entire
study. If possible, Staff recommends that the Company update the CPA model inputs utilizing the
Billing Analysis therm savings estimates to improve the usefulness of the CPA results for EE
program planning. Staff will review the CPA expense in the next DSM prudence filing.
Whole Home Measure Continuity
Following the 2020 EM&V, the Company implemented several of the evaluation's
recommendations into its Whole Home offering. The Company explains in its response to
Production Request No. 33, that it considers its current Whole Home offering ("Post-EM&V") as
a new measure distinct from the original Whole Home rebate ("Pre-EM&V") offered between
STAFF COMMENTS I I MAY 9, 2024

2019-2021. Operating under this definition, it may not be appropriate to use the results of the
2020 EM&V's Billing Analysis to calibrate the CPA's models, invalidating Staff concern stated
above. However, Staff strongly disagrees with the Company's interpretation of the evaluation's
recommendation.
The 2020 EM&V Impact evaluation provided the following recommendations for the
Whole Home program: (1) imposing a more stringent Home Energy Rating System ("HERS")
Index Requirement for the program; (2) removing the ENERGY STAR certification requirement;
and(3) to directly target natural gas savings through specific requirements. INT-G-22-03
Supplement to Application at 106. Additionally, in the Memorandum: Residential Whole Home
Modeling Results, recommendations were provided to offer tiered rebates for the offering and
gave specific requirements for building envelope upgrades that target natural gas savings. Id. at
391 & 392. Staff s review of these recommendations suggests that the changes are not intended
to retire and rebuild the rebate, rather they are incremental adjustments to the continued offering.
It is common for EE programs to adjust incentives and program requirements in response to
participation and to increase realization of energy savings. Staff analysis of Pre-EM&V offering
and the Post-EM&V Whole Home savings mechanisms is provided in Table No. I below. This
table demonstrates that while the ENERGY STAR certification was removed, the savings
mechanisms used by the rebate remains the same, establishing continuity between the Pre- and
Post- EM&V offerings. Analysis of the evaluation recommendations and savings mechanisms
suggest that the Whole Home offering is a continuation of the original program; therefore, the
results of the 2020 EM&V Billing Analysis are applicable; and the CPA models should be
calibrated using the historical therm savings as indicated by the Billing Analysis.
H
STAFF COMMENTS 12 MAY 9, 2024

Table No. 1: Comparison of the Savings Mechanisms of the ENERGY STAR Certified New
Construction and Company's Post-EM&V Whole Home Offering
Pre-EM&V Post EM&V
ENERGY STAR certified
new construction v 3.1 ' Tier 1 Tier 2
Cooling Equipment N/A N/A
Heating Equipment:
95 AFUE ENERGY STAR Furnace efficiency>= Furnace efficiency>=
as furnace 97%AFUE 95%AFUE
Envelope,Windows&Doors: Air sealing<=3ACH50
3 ACH50 Ceiling insulation>=R-49 Air sealing<=4ACH50
Water Heater N/A N/A
Thermostat&Ductwork: Ducts and air handler located Ducts and air handler located
All ducts and air handlers inside conditioned space or duct inside conditioned space or duct
modeled within conditioned leakage to outside of less than 4 leakage to outside of less than 4
space CFM25/100ft2 CFA. CFM25/100ft2 CFA.
Lighting&Appliances
(refrigerators dishwasher and
ceiling fans) N/A N/A
HERS rated at<75 HERS rated HERS rated
DSMAvoided Cost
In Order No. 33314, the Commission directed the Company to include more detail in
future IRPs about how the Company calculates avoided costs and uses those calculations to
determine whether natural gas DSM opportunities are cost-effective. Order No. 33314 at 9. In
Order No. 33997, the Commission directed the Company to describe how avoided costs change
because of the IRP. In describing the avoided cost calculation in the 2021 IRP, the Company
clearly identified how the avoided cost are calculated and how they changed because of the IRP.
2021 IRP at 90-91. In the 2021 IRP, the avoided cost calculation did not include distribution
costs.
In Order No. 34536, the Commission ordered the Company to review its avoided cost
calculation as part of its Energy Advisory Group. Through this group, the Energy Efficiency
Stakeholder Committee's ("EESC") avoided cost subcommittee reached a census on the
3 ENERGY STAR feature categories contain several options depending on fuel type and climate zone. Continuous
requirements are noted as applicable.
STAFF COMMENTS 13 MAY 9, 2024

calculation of avoided costs for the Company's DSM programs. In Case No. INT-G-22-03, the
Company proposed several changes to its avoided cost practices. The Commission approved the
proposals in Order No. 35662. Because of these changes, DSM related considerations have
additional significance in the IRP. Accordingly, Staff has placed additional scrutiny on its review
of the DSM avoided costs and CPA used to inform future DSM offerings.
The 2023 IRP describes the three major components of the DSM avoided costs as the
commodity cost, transportation cost, and variable distribution cost. 2023 IRP at 83. The
commodity cost represents the purchase price of natural gas. In this IRP, the Company forecasted
the commodity cost of gas using a weighted average price from the Company's three primary
supply basins and adjusting the prices by the Heating Degree Days ("HDD") of each month. The
transportation cost is the cost incurred by the Company for the delivery of gas to its distribution
system. For this IRP, the Company used the transportation and storage costs incurred as of the
2022 Purchased Gas Adjustment("PGA"). These prices rarely change by significant amounts.
The variable distribution cost is the cost associated with deferred or delayed capacity expansion
projects. In this IRP, the distribution cost remains at zero. In support, the Company compared its
demand forecast with and without the energy savings forecast provided by its CPA. The lack of
delayed or deferred capacity expansion projects supports the conclusion that the DSM offerings
have not offset any capacity projects.
This avoided cost calculation and the support for its components are consistent with
discussions from the EESC avoided cost subcommittee. Staff believes that the Company's 2023
DSM avoided costs and supporting methodologies are reasonable. Staff recommends that the
Commission establish the practice of authorizing the Company's DSM avoided costs as part of
IRP filings and authorize the DSM avoided costs associated with this filing.
Renewable Natural Gas
Renewable Natural Gas ("RNG") is pipeline quality gas that is fully interchangeable with
conventional natural gas. RNG is produced from the decomposition of organic material aka
biomass and is processed to meet purity standards. After processing RNG to industry purity
standards, the gas can then be used within the Company's system. 2023 IRP at 66.
The Company is involved with the growth and development of the RNG industry in Idaho.
In 2020, the Company filed an application with the Commission for authority to facilitate RNG
access. In Order No. 34693, the Commission approved the Company's RNG facilitation plan.
STAFF COMMENTS 14 MAY 9, 2024

The Company's RNG Facilitation Agreement allows RNG producers access to the Company's
distribution system to transport RNG to their end use customers. Id. at 9. Currently, the
Company has multiple RNG producers located in the Magic Valley supplying RNG from dairy
operations and expects additional RNG producers to come onto its system.
Progress Since the Previous IRP
In Order No. 35438, Case No. INT-G-21-06, the Commission acknowledged Staff s
comments and recommendations and stated:
The Commission also acknowledges Staffs 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.
The Company discussed each of Staffs recommendations in the 2023-2028 IRP.
Capacity Enhancement Project Cost and NPV Information
The Company did not provide information on project enhancements when they were
completed and placed in service or include details within this IRP. Staff requested in Production
Request No. 1 that the Company provide activities and results achieved in providing the
Commission with capacity enhancement project costs and NPV information. The Company
provided the following response:
The enhancement projects included in the 2021 IRP were as follows:
1. 12-inch Ustick Phase II;
2. Shoshone Compressor Station;
3. 12-inch Boise Loop;
4. State Street Uprate;
5. 12-inch Ustick Phase 3; and
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-22-01. 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
STAFF COMMENTS 15 MAY 9, 2024

project cost data to the Commission. None of the remaining projects have been
placed in service. Intermountain is open 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, and 3) individual reports after
final costs are available on a project.
As stated earlier, the IRP is foundational to subsequent capital prudence reviews. Staff is
receptive to discussing alternatives with the Company to deliver a method of reporting outside of
the IRP for when projects are placed in-service, and costs are known. Staff recommends that the
Commission order the Company and Staff to work together to complete, within six months, a
methodology for reporting to the Commission capacity enhancement projects that include when
each are placed in-service and actual and NPV project costs.
Public Participation Materials and Website Access
The Company made some improvements on providing materials in advance of
Intermountain Gas Resource Advisory Committee ("IGRAC")meetings and website access
improvements. Staff requested in Production Request No. 2 that the Company provide activities
and results achieved in providing materials to IGRAC members before meetings and making
information accessible on its website. The Company provided the following response:
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. 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.
Staff appreciates the improvements implemented by the Company. As a next step, Staff
believes there could be merit in making access of meeting materials prior to IGRAC meetings to
the Intermountain Gas IRP webpage to allow active participation from the public and parties.
Public Participation
In Order No. 33997, the Commission directed the Company to convene an IRP advisory
group and work with it to develop future IRPs that comprehensively and transparently consider
STAFF COMMENTS 16 MAY 9, 2024

demand, existing resources, and potential supply and demand-side options for meeting any
deficits.
The Company established the IGRAC with the intent to provide a forum through which
public participation can occur as the IRP is developed. 2023 IRP at 4. Advisory committee
members were solicited from across the Company's service territory as representatives of the
communities served by the Company. The Company stated that it held three IGRAC meetings in
2023 on a virtual platform. The Company states it provided a comment period after each meeting
to ensure feedback was timely and could be incorporated into the IRP. Id. Staff members
attended each of the meetings. Staff recognizes the Company's efforts to enhance public
participation, appreciates the opportunity to participate in the IGRAC, and looks forward to the
Company improving public involvement in development of future IRPs.
Lost and Unaccounted for Gas
In Order No. 32855, the Commission directed the Company to describe how Lost and
Unaccounted for Gas ("LAUF") is managed and explain how results were achieved and ordered
the Company to include a LAUF gas section within future IRPs. The Commission permits the
Company to recover a maximum of 0.85% of its total throughput as LAUF.4 The Company's
2023 IRP reports that its LAUF rate for the period of July 2021 through June 2022 was -0.48%,
which is one of the best in the industry. 2023 IRP at 68. Staff recognizes the Company's efforts
in this area and believes the Commission requirements were satisfied in this filing. Staff will
continue to review LAUF in the Company's annual PGA filings and future IRPs.
STAFF RECOMMENDATIONS
The Company's IRP analyzed residential, commercial, and industrial customer growth and
its impact on the Company's system under multiple scenarios. The IRP results show that there
are peak day delivery deficits when forecasted growth is matched against existing resources for
the 2023 through 2028 IRP period. The Company provided sufficient information to describe
how deficits were determined and selected alternatives and resource enhancements to resolve
them.
4 Order No.30649.
STAFF COMMENTS 17 MAY 9, 2024

Staff believes the Company's 2023-2028 IRP meets Commission IRP requirements. Staff
recommends that the Commission:
1. Acknowledge the Company's 2023 IRP;
2. Order the Company to work with Staff to implement IRP reporting that includes
system enhancement information in future IRPs, within six months of a Commission
order;
3. Order the Company to work with Staff to develop reports to the Commission of
capacity enhancement projects that include in-service dates and project costs, within
six months of a Commission order; and
4. Establish the practice of authorizing the Company's DSM avoided costs as part of IRP
filings and authorize the DSM avoided costs associated with this filing.
Respectfully submitted this 91h day of May 2024.
6A ti.
Chris Burdin
Deputy Attorney General
Technical Staff: Kimberly Loskot
Vicki Stephens
Matt Suess
Jason Talford
I:\Utility\UMISC\COMMENTS\INT-G-23-07 COMMENTS.docx
STAFF COMMENTS 18 MAY 9, 2024

CERTIFICATE OF SERVICE
11
I HEREBY CERTIFY THAT I HAVE THIS C 1 .y DAY OF MAY 2024,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. INT-G-23-07, BY E-MAILING A COPY THEREOF, TO THE FOLLOWING:
LORI BLATTNER PRESTON N CARTER
DIR—REGULATORY AFFAIRS GIVENS PURSLEY LLP
INTERMOUNTAIN GAS CO 601 W BANNOCK ST
PO BOX 7608 BOISE ID 83702
BOISE ID 83707 E-MAIL: prestoncarter(@givenspursle
E-MAIL: lori.blattner(a),intgas.com stephaniew(i� ivenspursley.com
i
PATRICIA JORDAN
CERTIFICATE OF SERVICE