20200731Final_Order_No_34742.pdf

ORDER NO. 34742 1

Office of the Secretary
Service Date
July 31, 2020
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATER OF INTERMOUNTAIN GAS
COMPANY’S 2019-2023 INTEGRATED
RESOURCE PLAN
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CASE NO. INT-G-19-07

ORDER NO. 34742

On October 18, 2019, Intermountain Gas Company (“Intermountain” or “Company”)
filed its Integrated Resource Plan (“IRP”) for 2019-2023. Intermountain 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 section 303(b)(3) of the Public Utility Regulatory Policies Act (“PURPA”), 15
U.S.C. § 3202. The Commission reviews the IRP to ensure it discusses these subjects and shows
the Company has diligently planned for the anticipated supply and demand for natural gas.
On December 3, 2019, the Commission issued its Notice of Filing, Notice of
Intervention Deadline, and Order. See Order No. 34497. The Idaho Conservation League (“ICL”)
was granted intervention into the case. See Order No. 34522. The Commission issued its Notice
of Parties on January 8, 2020. On January 31, 2020, the Commission issued its Notice of Modified
Procedure setting a comment deadline of April 23, 2020, for interested persons and parties to
submit comments on Intermountain’s IRP and a May 4, 2020, reply comment deadline for the
Company. The Commission Staff (“Staff”) and ICL filed comments. The Company filed reply
comments on May 4, 2020.
The Commission now issues this Order acknowledging the IRP.
BACKGROUND
A natural gas IRP describes a company’s plans to meet its customers’ future natural
gas needs. 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. Order No. 27098 removed
any requirement that IRPs formally evaluate potential demand-side management (“DSM”)
programs, and instead directed the companies to explain whether cost-effective DSM opportunities
exist. In summary, these orders direct the Company to file an IRP every two years that includes:
ORDER NO. 34742 2

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. Public participation.

Additionally, in Order No. 32855 the Commission: 1) directed the Company to continue to
improve public participation in the IRP process; and 2) allowed the Company to stop filing semi-
annual lost and unaccounted for gas (“LAUF Gas”) reports. Order No. 32855. The IRP’s LAUF
Gas section must explain the Company’s: (a) framework for how it has tested for, identified, and
remediated equipment measurement errors or leaks; and (b) business process for alleviating
measurement errors through its financial accounting of nominations, scheduling, measurements,
flow volume allocation, and billing. See Order No. 32855 at 5-6.
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. See Order No. 33314 at 9.
Last, in Order No. 33997 the Commission found it reasonable that the Company should
convene an IRP advisory group and work with it to develop future IRPs that comprehensively and
transparently consider demand, existing resources, and potential supply and demand-side options
for meeting any deficits. See Order No. 33997 at 8.
ORDER NO. 34742 3

INTERMOUNTAIN’S IRP FILING
The Company regularly forecasts the demand of its growing customer base and
determines how to best meet load requirements brought by this demand. IRP at 1-2.
Intermountain’s IRP is a snapshot in time of the Company’s ongoing planning process; it describes
expected conditions over a five-year planning horizon, the anticipated resource selections, and the
process for making resource decisions. Id. at 1-2. The Company represented it sells natural gas
to two major markets: the residential/commercial market and the large volume market. Id. at 1
and 6. In 2018, the Company served 364,512 customers, 330,000 of those are residential
customers. Id. at 1. Residential and commercial customers primarily use natural gas for space and
water heating. Id. Industrial customers use natural gas for boiler and manufacturing applications.
Id. at 1-2. The agricultural economy and price of alternative fuels strongly influences large volume
demand for natural gas. Id. at 2. In 2018, industrial sales and transportation accounted for 50%
of the throughput on the Company’s system. Id.
The Company forecasts changes in its peak-day loads due to customer growth under
base, high, and low case growth economic scenarios. Id. In this IRP, the Company forecasts a
base case growth scenario where its total residential, commercial, and industrial peak-day loads
increase each year for five years by an average of 2.08%. Id. at 95. The Company asserted this
increase in peak-day loads corresponds to expected growth in the Company’s markets for
residential and small commercial customers. Id. at 3-4. The Company sees no peak-day delivery
deficits over the next five years when it matches its forecasted peak-day delivery against its
existing resources. Id. at 3-4.
To enhance the IRP, the Company established the Intermountain Gas Resource
Advisory Committee (“IGRAC”). Id. at 3; See also Order No. 33997 at 8. The IGRAC is a forum
where public participation can occur as the IRP is developed. Id. Advisory committee members
were solicited from across the Company's service territory. Id. The Company represented it held
meetings across its service territory to ensure travel would not impact the ability of committee
members and the public to participate. Id. The Company stated a comment period was provided
after each meeting to ensure feedback was timely and incorporated into the IRP. Id.
The Company represented it also analyzes different geographic areas in its service
territory (“AOI” or “AOIs”) so it can plan to meet projected deficits in those AOIs. Id. at 8. In
this IRP, the Company analyzed the Idaho Falls Lateral, the Sun Valley Lateral, Canyon County
Area, the State Street Lateral, Central Ada County, and the All Other segment. Id.
ORDER NO. 34742 4

The Company represented the Idaho Falls Lateral (“IFL”) is 104 miles long and serves
cities between Pocatello and St. Anthony in eastern Idaho. Id. at 128. In the base case scenario,
customers in the IFL are expected to increase by 7,772 (a 2.92% annualized growth rate) over the
IRP period. Id. at 91. The Company claimed earlier system enhancements give it the capacity to
serve the IFL for the next five years. Id. at 129. During this IRP period, the Company will add a
second liquefied natural gas (“LNG”) storage tank at the Rexburg LNG Facility in 2022. Id. The
Company asserted the second tank will increase total storage at this facility, as potential
vaporization flow requirements increase. Id.
The Company represented the Sun Valley Lateral (“SVL”) is 68 miles long with the
majority of demand at its far end. Id. at 129. The base case scenario projects customers in the
SVL will increase by 1,304 (a 2.26% annualized growth rate) over the IRP period. Id. at 91. With
continued demand growth, the Company has selected a second compressor station to enhance the
SVL further downstream from the Jerome Compressor. Id. at 129. The Company asserted it will
complete the second station in 2021, which will increase capacity beyond this IRP’s remaining
five-year growth outlook. Id.
The Company asserted the Canyon County Area (“CCA”) consists of an interconnected
system of high-pressure pipelines that serve communities from Star Road west to Highway 95. Id.
at 127. In the base case scenario, the Company expects customers in the CCA to increase by
14,854 (a 5.75% annualized growth rate) over the IRP period. Id. at 91. The Company represented
three enhancement projects are needed to meet projected growth demands in the CCA. Id. at 127.
First, in 2020 the Company would complete the 5-inch Orchard Avenue Extension project that will
extend 4.5 miles into a significant growth area not currently supported by a nearby high-pressure
pipeline. Id. Second, in 2021 the Company would complete the second phase of the 12-inch
Ustick/Caldwell enhancement to extend the existing 2018 pipeline 2 more miles to the east. Id. at
127-128. Last, in 2022 the Company would build the 8-inch Happy Valley enhancement to extend
the high-pressure pipeline 2 miles further into south Nampa. Id. at 128.
The Company represented the State Street Lateral (“SSL”) in northwest Boise is 16.2
miles long. Id. at 125. It primarily serves residential and commercial customers. Id. In the base
case scenario, the Company expects SSL customers to increase by 7,055 customers (a 2.69%
annualized growth rate) for the IRP period. Id. at 91. The Company asserted this area is suited
for a pipeline retest to establish a higher maximum allowable operating pressure and allow the
Company to maximize its existing facilities’ potential before investing in new infrastructure. Id.
ORDER NO. 34742 5

at 125. The Company can retest the pipeline in phases over multiple years, which will increase
capacity as growth is experienced while minimizing the length of pipe that must be taken out of
service at one time. Id.
The Company asserted the Central Ada County area (“CAC”) in Boise consists of
multiple high-pressure and intermediate pressure pipeline systems. Id. at 126. In the base case
scenario, the Company expects CAC customers to increase by 6,622 (a 2.49% annualized growth
rate) during the IRP period. Id. at 91. The Company stated that, like the SSL, the existing, large-
diameter pipeline on Victory Road could be retested to increase its maximum allowable operating
pressure and resulting flow capacity. Id. at 126. The Company represented this increased
operating pressure is designed to match the Chinden and Cloverdale operating pressure, and the
retest is an initial step to create a consistent, connected system between the pipelines. Id. at 126.
The Company expects to complete phase one of the retest in 2021. Id. at 126-127. The retest
begins at the Meridian gate station and extends roughly 2.5 miles. Id. at 127.
In summary, 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 for Idaho’s economy. Id. at 3. The Company asserted
it measured peak-day delivery under each customer growth scenario against the available natural
gas delivery systems to project the magnitude and timing of delivery deficits on a total Company
and regional perspective. Id. The Company stated it analyzed the resources needed 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 for years to come. Id.
COMMENTS
1. Staff Comments.
Staff believed the Company’s IRP is reasonable and should be acknowledged, but also
identified areas for improvement for future IRPs. Staff Comments at 3.
Staff believed the Company’s methodology for estimating future demand is adequate
but could be improved in future IRPs. Id. Although Staff appreciated the Company’s detailed
explanation of its customer growth and peak weather forecasting methodologies it was concerned
that the models relating per-customer consumption to extreme weather events may not be
sufficiently granular to accurately estimate per-customer consumption for a peaking event. Id. at
ORDER NO. 34742 6

3-4. Staff also believed the use of individual models and weather data for each customer to be
appropriate; however, Staff still was concerned the aggregated monthly data used to create the
model did not match the daily or hourly estimates obtained from the model used to estimate peak
consumption. Id. at 5. The Company provided no evidence that the weather sensitive heat load
obtained using monthly aggregated data will provide an accurate estimate of consumption over a
short duration peaking event. Id. Staff believes that the Company should validate the accuracy of
peak estimates obtained from these models during the next IRP cycles. Id. Staff asserted that
validation could be performed by comparing the output of individual customer models to actual
data obtained from these customers’ Advanced Metering Infrastructure (“AMI”) meters. Id. Staff
believed the Company should also validate the peak consumption estimates obtained from DNV
GL’s Customer Management Module using actual peak information from the Company’s AMI
meters. Id. Staff also asserted that the Company should quantify the effects of new building codes
and the Company's energy efficiency (“EE”) programs and incorporate estimates into its per-
customer usage models. Id.
Staff noted that over the IRP planning period, the Company shows deficits are projected
in five key parts of its service territory 1) the IFL, 2) SVL, 3) CCA, 4) SSL, and 5) the CAC during
the 2019 – 2023 IRP period. Id. at 95 – 97. Staff recognized that in previous IRPs, the Company
included future enhancements as existing peak firm day delivery capability. Id. at 6. Staff believed
this method obscured the magnitude and timing of potential capacity deficits and did not provide
a transparent and robust method to evaluate deficit resolution. Id. In this IRP, the Company
provided capacity analysis, identified when deficits will occur, and described enhancements to
resolve identified deficits. Id. However, in some areas it was not clear what alternatives the
Company considered and why it selected the enhancement(s) it did to resolve deficits. Id. In the
future, Staff would like to see the alternatives considered by the Company to resolve all identified
deficits and an analysis that demonstrates selection of least cost, least risk solutions. Id. Staff
recommended that the Company conduct a robust analysis of supply and demand-side alternatives
to resolve the deficits in a least cost, least risk manner. Id. Staff stated without this analysis, Staff
cannot evaluate the reasonableness of the Company’s planned resources. Id. Staff asserted that
requiring this level of analysis from the Company would align it with the IRP standards for Avista
Corporation’s natural gas service territory, and all the Idaho-regulated electric utilities. Id.
Additionally, Staff recommended that the Company include documentation that shows all analysis
conducted to determine least cost, least risk alternatives. Id.
ORDER NO. 34742 7

In certain AOIs Staff raised concerns about proposed enhancements. In the SVL,
although Staff believes that the proposed compressor station and associated improvements can
meet the predicted load growth along it, Staff has not conducted a prudency review to determine
if these improvements are the least costly way to meet demand in this AOI. Id. at 8. In the CCA
although the Orchard Avenue Extension and Happy Valley pipeline installations should meet
projected demand, the Company did not conduct a robust analysis of other supply and demand-
side options that may have met these needs at lesser cost and risk. Id.
Staff noted that the Company has acted on Staff’s recommendations to strengthen its
DSM analysis and contracted with Dunsky Energy Consulting to perform a Conservation Potential
Assessment (“CPA”). Exhibit 4. Id. at 11. Staff believed that the Company in cooperation with
its EE stakeholder group is addressing concerns Staff detailed in previous IRPs and is actively
pursuing compliance with Commission orders. Id.
Staff also pointed out improvements the Company has made in this IRP. Upon initial
analysis of EE and avoided cost content in the 2019 IRP, Staff believes that the Company
considered DSM/EE in its IRP modeling, specifically in its optimization model. However, Staff
is concerned the Company’s avoided cost methodology inappropriately includes base rate
embedded distribution costs in avoided cost computations. Staff also believed the Company’s
forecast of avoided commodity costs is unreasonably high.
Staff noted that the Company established the IGRAC to foster public participation in
the IRP’s development. Id. at 11. Staff members attended each IGRAC meeting in 2020. Staff
recognized the Company’s efforts to enhance public participation, appreciates the opportunity to
participate in the IGRAC, and looks forward to increased public involvement in future IRPs. Id.
at 11-12.
Last, Staff recognized the Company’s improvement with LAUF Gas and believes the
Commission requirements were satisfied in this filing. Id. at 12. Staff scrutinizes LAUF Gas in
the Company’s annual Purchased Gas Adjustment filings. Id.
Staff believed the Company’s IRP has met the Commission requirements and
recommended the Commission acknowledge the Company’s 2019-2023 IRP. Id. at 13. To
improve future IRPs, Staff also recommended that the Company:
1) Include an analysis of all options the Company considered to resolve identified
deficits and achieve the most cost-effective least risk solutions; and
ORDER NO. 34742 8

2) Validate the peak consumption estimates obtained from DNV GL’s Customer
Management Module using actual peak information from the Company’s AMI meters.
2. ICL Comments.
ICL commended the Company for forming IGRAC but claimed Intermountain failed
to inform and involve a representative group of stakeholders. Id. at 1-2. ICL asserted that for the
IGRAC to be more beneficial, the group should be more diverse. Id.
ICL also asserted that the Company’s IRP should evaluate the costs and risks to
customers associated with greenhouse gas emissions and related policy issues, and claimed other
public utilities have recognized and evaluated these matters in their IRPs. Id. ICL requested that
the Company provide the public with a discussion of these economic and policy considerations in
its IRP. Id. at 3. ICL asserted that without this discussion the IRP is not a full evaluation of the
least cost and risk plans to meet customer needs. Id. ICL also contended these matters should
require the Company to revise its forecasts to a longer period because these issues are increasing
the uncertainty of the economics of fossil fuel-dependent industries. Id. at 2-3. ICL also claimed
customers are concerned about the impacts of fossil fuels on climate change and their health. Id.
at 3-4.
ICL also claimed the Company’s analysis of gas price forecasts is not public and
requested that the Commission direct Intermountain to model gas price forecasts in this IRP and
future IRPs using only publicly available models and information. Id. at 4.
In conclusion, ICL recommended that the Commission not acknowledge the
Company’s IRP and direct the Company to supplement it with the recommendations it has made.
Id. at 5.
3. Company Reply Comments.
The Company agreed with Staff’s recommendations to include additional matters in
the IRP. Id. at 2. The Company also represented that it considers alternatives to resolve deficits
and determine the most cost-effective, least risk solutions, but that the Company did not include
all that analysis in the filed IRP document. Id. The Company stated it will provide that analysis
in future IRPs. Id. As Staff noted, Intermountain is installing a fixed network that will allow for
daily reads of its meters. Through the end of 2019, Intermountain has installed 60% of this fixed
network. Unfortunately, this project stalled in 2020 due to staffing changes. Id. The Company
hopes to ramp the project back up throughout the rest of 2020. Id. The Company also agreed that
ORDER NO. 34742 9

it could use a sample from the completed portion of the fixed network to validate the DNV GL
Customer Management Module results as Staff suggested. Id.
In response to ICL’s comments and Sierra Club’s public comments the Company
asserted that the five-year planning horizon pairs relatively accurate forecasts with adequate time
to act upon any capacity issues identified in the IRP. Id. The Company also claimed that a five-
year forecast is more accurate than a twenty-year one, particularly when forecasting issues related
to a natural gas IRP. Id. at 3. The Company also argued that twenty-year forecasts are more
expensive to conduct. Id. Last, the Company asserted that a twenty-year forecast would provide
little or no actionable information beyond that contained in a five-year forecast. Id.
The Company represented the IRP’s purpose is to ensure the Company can meet its
customers’ natural gas needs in a cost-effective manner. The Company asserted that the alternate
scenarios in the IRP address a wide variety of unknown risk factors and are adequate to encompass
the risk of a regulatory change alleged by ICL during the forecast period. Id. at 3-4.
Last the Company represented that the most appropriate place to evaluate conservation
resources that serve as an input to the IRP modeling is with its EE stakeholder group. Id. at 5-6.
Based on the foregoing, the Company believes that its IRP meets Commission
requirements, and that the IRP shows the Company has adequate plans to meet demand from 2019
through 2023. Id. at 6. Intermountain also submits that the current requirements for its IRP result
in a useful document that ensures the safe, reliable, affordable supply of natural gas to its current
and future customers. Id. The Company requested that the Commission acknowledge the
Company’s 2019-2023 IRP as filed and accept the recommendations to improve future IRPs made
by Staff. Id.
PUBLIC COMMENTS
1. Sierra Club.
The Sierra Club claimed the five-year forecast in the IRP is insufficient to show
whether the Company’s plans are consistent with the public’s interest. Sierra Club Public
Comments at 1. The Sierra Club also asserted that the IRP should consider the potential for a
carbon charge. Id. The Sierra Club is concerned that without this analysis the public interest is at
risk of incurring unnecessary costs in the form of wasteful future investments. Id.
The Sierra Club requested that the Commission advise the Company to make the
following changes in its next IRP:
ORDER NO. 34742 10

1. Separate wholesale and retail market projections.
2. Retain the 5-year term for analysis of wholesale market accessed supply adequacy but
analyze demand over a 20-year period.
3. Include demand analyses in the IRP that reflect the effects of carbon charges on the
demand of various customer classes.
4. Identify locations within its service territory where projected distribution system
upgrades are likely to be needed to serve peak winter natural gas loads.
COMMISSION FINDINGS AND DECISION
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, the comments
of the parties and the public comment. Based on our review, the Commission finds that
Intermountain’s 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 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 of 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. See Order
Nos. 24981 and 25342.
The Commission also acknowledges the Staff’s comments and recommendations. In
particular, we find it reasonable that the Company include an analysis of all options the Company
considered to resolve identified deficits and achieve the most cost-effective, least risk solutions;
and validate the peak consumption estimates obtained from DNV GL’s Customer Management
Module using actual peak information from the Company’s AMI meters. Finally, we commend
the Company on forming and operating the IGRAC and we recognize that this new group will
evolve. In that evolution, we encourage the Company to seek, inform, share scenario analyses,
and allow diverse stakeholders to participate in the IGRAC.
ORDER NO. 34742 11

O R D E R
IT IS HEREBY ORDERED that the filing of the Company’s 2019-2023 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 with regard to 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 31st
day of July 2020.

PAUL KJELLANDER, PRESIDENT

KRISTINE RAPER, COMMISSIONER

ERIC ANDERSON, COMMISSIONER

ATTEST:

Diane M. Hanian
Commission Secretary

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