20200423Comments.pdf

STAFF COMMENTS 1 APRIL 23, 2020
JOHN R. HAMMOND, JR.
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5470

Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983

Attorney for the Commission Staff

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

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

COMMENTS OF THE
COMMISSION STAFF

The Staff of the Idaho Public Utilities Commission submits the following comments
regarding the above referenced case.

BACKGROUND
On October 18, 2019, Intermountain Gas Company (“Intermountain” or “Company”) filed
its Integrated Resource Plan (“IRP”) for the years 2019-2023. Intermountain files an IRP every
two years to describe the Company’s plans to meet its customers’ future natural gas needs. The
IRP must discuss the subjects required by several Commission Orders1 and Section 303(b)(3) of
the Public Utility Regulatory Policies Act (“PURPA”), 15 U.S.C. § 3202. The Idaho Public
Utilities Commission (“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.

1 See Order Nos. 25342, 27024, 27098, 32855, 33314 and 33997.
RECEIVED
2020 April 23,PM4:09
IDAHO PUBLIC
UTILITIES COMMISSION

STAFF COMMENTS 2 APRIL 23, 2020
IRP Requirements
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 years
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 the Company’s 2013 IRP case, the Commission 1) directed the Company to continue to
work 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. See 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.
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

STAFF COMMENTS 3 APRIL 23, 2020
meet current and future needs at the lowest cost to the Company and its
ratepayers;
5. A short-term (e.g., two-year) plan outlining the specific actions to be taken
by the Company in implementing the IRP;
6. A progress report that relates the new plan to the previously filed plan; and
7. Public participation.

The 2019-2023 IRP
Intermountain’s IRP explains that the Company 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’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.
Intermountain 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
and of that amount, roughly 330,000 are residential customers. Id.at 1.
Intermountain states that much of the demand for natural gas is strongly influenced by the
agricultural economy and the price of alternative fuels. Id. at 2. The Company alleges that in
2018, industrial sales and transportation accounted for 50% of the throughput on Intermountain’s
system. Id.
The Company calculated peak-day delivery under each customer growth scenario 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 IRP to determine whether it meets the Commission
requirements and adequately plans for the capability to meet demand from 2019 through 2023. In
general, Staff believes that the Company’s IRP is reasonable and should be acknowledged. The
Company asserts it sees no peak-day delivery deficits over the next five years when it matches its

STAFF COMMENTS 4 APRIL 23, 2020
forecasted peak-day delivery against its existing resources.2 IRP at 98. However, during this IRP
period, the Company identified deficits on some of its laterals which are described in greater
detail in the Deficits and Regional Summaries sections below.
In addition, Staff is concerned that the Company’s IRP does not include a transparent
analysis of the least cost, least risk alternatives for meeting current or projected capacity deficits.
In future IRPs, Staff believes that the Company should provide a detailed analysis of how it
evaluated and compared alternatives to resolve deficits and make least cost, least risk selections.
These concerns are explained in more detail below.

Demand Forecast
The Company forecasted changes in its peak-day loads due to customer growth under its
base case, and high and low growth economic scenarios. Id. The Company’s base case growth
scenario forecasted total residential, commercial, and industrial peak-day loads to increase each
year for five years by an average of 2.08%. IRP at 95. Intermountain says this increase in peak-
day loads corresponds to expected growth in the Company’s markets for residential and small
commercial customers.
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 rate base. Staff believes the Company’s methodology for estimating
future demand is adequate, but offers the following suggestions for improvement in future IRPs.
The Company's demand forecast is based on three separate components: 1) a prediction of
the number of customers in each of the Company's Areas of Interest ("AOI"); 2) predictions of
extreme weather events for each AOI; and 3) models relating per-customer consumption to
extreme weather events within each AOI. Id. at 8. As Staff noted in its 2017 IRP comments, the
Company's methods for predicting customer counts and extreme weather events are sound;
however, Staff is concerned that the models relating per-customer consumption to extreme
weather events may not be sufficiently granular to accurately estimate per-customer consumption

2 The total Company perspective differs from the laterals in that it reflects the amount of gas that can be delivered to
Intermountain via the various resources on the interstate system. Hence, total system deliveries should provide at
least the net sum demand – or the total available distribution capacity where applicable – of all the laterals/AOIs on
the distribution system. IRP at 98.

STAFF COMMENTS 5 APRIL 23, 2020
for a peaking event. Because distribution plant must be sized to meet maximum demand, an
inaccurate estimate of per-customer peak consumption could result in incorrectly sized
distribution plant equipment.
The Company’s per-customer models are created using third party software (Customer
Management Module) provided by Intermountain’s parent company, DNV GL. Id. at 30 - 32.
This module produces a least squares model for each customer using local weather information
and monthly meter read data. For each customer, the model provides a weather independent base
load, as well as a weather sensitive heat load that can be multiplied by a weather variable in order
to determine consumption. Staff believes the use of individual models and weather data for each
customer to be appropriate; however, Staff is concerned that there is a mismatch between the
aggregated monthly data used to create the model and the daily or hourly estimates obtained from
the model and used to estimate peak consumption. 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. Staff believes that the Company
should validate the accuracy of peak estimates obtained from these models during the next IRP
cycles. Validation could be performed by comparing the output of individual customer models to
actual data obtained from these customers’ Advanced Metering Infrastructure (“AMI”) meters.
Staff believes the Company should validate the peak consumption estimates obtained from DNV
GL’s Customer Management Module using actual peak information from the Company’s AMI
meters.
Staff notes that the Company has installed approximately 50% of the AMI meters it
intends to install. Id. at 71. When deployed, these meters will allow the Company to collect
consumption data over much shorter time periods, and thus be able to develop models capable of
accurately estimating peak consumption. Until these meters are fully deployed, Staff believes that
data obtained from a sample of these meters can, and should be, compared to the models obtained
from the DNV GL Customer Management Module.
Staff also notes that the Company's per-customer consumption model is obtained using the
consumption of existing customers, and may not properly account for decreased consumption that
may be attributable to either updated efficiency standards in new building codes, or to the
Company's own energy efficiency programs. As noted by the Company, there is substantial
downward pressure on actual per-customer consumption due to changes in building codes and to

STAFF COMMENTS 6 APRIL 23, 2020
the Company's energy efficiency programs. Id. at 31. In the future, Staff believes 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.

Deficits and Regional Summaries
Over the IRP planning period, the Company shows that deficits are projected in five key
parts of its service territory 1) the Idaho Falls Lateral, 2) Sun Valley Lateral, 3) Canyon County
Area, 4) State Street Lateral, and 5) the Central Ada County area during the 2019 – 2023 IRP
period. Id. at 95 – 97.
In previous IRPs, the Company included future enhancements as existing peak firm day
delivery capability. Staff believes this practice obscured the magnitude and timing of potential
capacity deficits and did not provide a transparent and robust method to evaluate deficit
resolution. In this IRP the Company provided capacity analysis, identified when deficits will
occur, and described enhancements to resolve identified deficits.
In some cases, such as the State Street Lateral and Central Ada County Area, the
Company provided a discussion of alternatives considered to resolve deficits. However, in areas
such as the Sun Valley Lateral and Canyon County Area, it was not clear what alternatives the
Company considered and why it selected the enhancement(s) it did to resolve deficits. 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.
Staff recommends that the Company conduct a robust analysis of supply and demand side
alternatives to resolve the deficits in a least cost, least risk manner. Without this type of analysis,
Staff is unable to evaluate the reasonableness of the Company’s planned resources. Requiring
this level of analysis from Intermountain would align it with the IRP standards currently in place
for Avista’s natural gas service territory, as well as all of the Idaho-regulated electric utilities.
Additionally, Staff recommends that the Company include documentation that shows all analysis
conducted to determine least cost, least risk alternatives.

Idaho Falls Lateral
The Idaho Falls Lateral (“IFL”) located in eastern Idaho serves cities between Pocatello on
the south to St. Anthony on the north. The IFL utilizes a Liquefied Natural Gas (“LNG”) facility

STAFF COMMENTS 7 APRIL 23, 2020
located in Rexburg to supplement the lateral’s capacity during a peak demand day. The Company
trucks LNG to the Rexburg facility from its Nampa, Idaho LNG facility. Comparing peak firm
day delivery capability on the IFL to peak day demand, the Company shows a deficit in 2023
under the base case scenario.
The Company plans to install a second LNG tank at the Rexburg facility in 2022. IRP at
129. Addition of a second storage tank should provide enough capacity to meet peak demand
through 2023. IRP at 128. The Rexburg facility was constructed to accommodate three LNG
storage tanks, one of which was built and is operational. The Company estimates that installation
of an additional storage tank in the summer of 2022 will cost $3M. The Company plans to order
the additional tank in 2021.

Sun Valley Lateral
The Sun Valley Lateral (“SVL”) located in central Idaho serves residential, commercial,
and industrial customers. The SVL is a 68-mile long, 8-inch-high pressure pipeline, with a
compressor station located near Jerome, which has most of its demand furthest from its source.
Id. at 129. Comparing peak firm day delivery capability on the SVL to peak day demand, the
Company shows deficits in 2021 -2023 under the base case scenario. Id. at 96. The Company
plans to add a second compressor station in 2021 to provide enough capacity to meet peak
demand through 2023. Id. at 129.
Staff was concerned that the proposed compressor station would be inadequate to meet the
long term needs of customers along the SVL. As described in the Application, the proposed
compressor station would increase capacity from 198,780 Therms/Day to 220,000 Therms/Day,
or an increase of 20,122 Therms per day. Using the Company's peak load growth estimate for the
SVL (2.26%/year), Staff estimated that the Company would outgrow the new compressor station
by the year 2030, and require additional infrastructure investment. Company responses to Staff's
Production Request Nos. 27 and 30.
In its discussions with the Company, Staff learned that the IRP substantially understates
the capacity increases that would be realized by the proposed compressor station and other
planned improvements to the SVL. In fact, these improvements would boost capacity to between
260,000 and 300,000 therms per day. Using the Company’s 2.26% growth rate to extrapolate

STAFF COMMENTS 8 APRIL 23, 2020
beyond the current 5-year IRP planning horizon, Staff believes that this will be sufficient to meet
any anticipated growth along the SVL until the year 2040 and beyond.
Although Staff believes that the proposed compressor station and associated
improvements will be able to meet forecast load growth along the SVL, Staff has not conducted a
prudency review to determine if these improvements represent the least costly way of meeting
demand in this AOI (“Area of Impact”).

Canyon County AOI
The Canyon County AOI located in southwest Idaho serves residential, commercial, and
industrial customers from Star Road west to Highway 95. Comparing peak firm day delivery
capability in the Canyon County AOI, the Company shows deficits in years 2022 through 2023
under the base case scenario. IRP at 96. With three enhancement projects, the Company expects
to achieve enough capacity to meet peak demand through 2023. IRP at 127.
One enhancement project known as the Orchard Avenue Extension (“OAE”) scheduled
for 2020 is a six-inch steel pipeline installation project 4.5 miles in length. The project will
deliver high pressure gas to a rapidly growing area on the Company’s system at an estimated cost
of $2.3M.
An additional project known as the Ustick Caldwell Phase Two enhancement involves
replacing two miles of six-inch steel high pressure pipeline with twelve-inch steel high pressure
pipeline. The Company determined that installation of a twelve inch pipeline is the more cost-
effective alternative on a per therm basis. The Company estimates project costs to be $2.7M to
$3.1M and will complete a final design and cost estimate this year with construction completion
targeted for 2021.
The final Canyon County project is known as the Happy Valley extension. This
enhancement includes an eight-inch steel pipeline installation project that is 2 miles in length.
The project is like the OAE in that it will deliver high pressure gas into a growth area. The
project is targeted to be completed in 2022 at an estimated cost of $1.8M.
Although the OAE 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.

STAFF COMMENTS 9 APRIL 23, 2020
State Street Lateral
The State Street Lateral (“SSL”) located in southwest Idaho serves primarily residential
and commercial customers in the Star, Eagle, Meridian, and northwest Boise areas. Comparing
peak firm day delivery capability in the SSL, the Company shows a deficit in 2023 under the base
case scenario. IRP at 97. With an enhancement, the Company expects to have enough capacity to
meet peak demand through 2023. IRP at 125.
An enhancement project known as the Phase II State Street pipeline retest is an
enhancement that will increase operating pressure on an additional three miles of twelve-inch
pipeline. The project is targeted for completion in 2022 at an estimated cost of $1.5M. As an
alternative to the retest, the Company considered installation of new pipeline and determined that
it would cost approximately three times more than the chosen course of action.

Central Ada County AOI
The Central Ada County AOI located in southwest Idaho serves primarily the Boise area.
Comparing peak firm-day delivery capability in the Central Ada County AOI, the Company
shows deficits in 2022 through 2023 under the base case scenario. IRP at 97. With an
enhancement, the Company expects to have enough capacity to meet peak demand through 2023.
IRP at 126. An enhancement project known as the “Central Ada County 10” Victory retest is a
project that will increase operating pressure on an additional 2.5 miles of ten-inch pipeline. The
project is targeted for completion in 2021 at an estimated cost of $2M. As an alternative to the
retest, the Company considered installation of new twelve-inch pipeline and determined that it
would not be cost- effective being approximately $1.75 to $3M more expensive than the chosen
course of action.

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. IRP at 44.

STAFF COMMENTS 10 APRIL 23, 2020
The Company utilizes storage as a capacity resource. Currently, the Company has storage
capacity in four facilities. Two of the facilities are operated by Northwest Pipeline in Jackson
Prairie and Plymouth Washington. A third facility is the Dominion Energy storage field located
near the Utah and Wyoming border. The fourth storage facility is the Company-owned Nampa
LNG facility, which is described in greater detail below.

Nampa LNG Facility
In addition to reviewing planned enhancement projects, Staff also examined the operation
of the Company’s Nampa LNG facility. In its IRP, the Company states that “… the plant has the
added benefit of supplying natural gas directly into the connected Canyon County and Ada
County distribution systems without use of interstate pipeline distribution.” Id. at 56.
Using information provided by the Company, Staff found that liquified natural gas stored
at the Nampa LNG facility could be used to augment flow from the Williams Pipeline in order to
meet a needle peaking event on the Canyon County Lateral; however, Staff also believes that in
the event of a Force Majeure event curtailing flow from the Williams Pipeline, the Nampa LNG
facility would probably be unable to maintain adequate system pressure in the Canyon County
lateral by itself. Staff notes that there are no connections to other portions of the Company's
system that would allow gas produced by the Nampa LNG facility to augment flow to any portion
of the Company’s distribution system except for the Canyon County Lateral.
In past IRP cycles, the Company has stated that liquefaction is an efficient method for
storing peak requirements, that the Nampa LNG facility could be used to meet needle peaking
events, and that it could be used as an emergency source of supply during a force majeure
situation. Intermountain Gas 2017 IRP at 56 and 107. However, the Company declined to
provide Staff with the information necessary to evaluate these claims in those cases. INT-G-17-
04 Company Response to Staff's Production Request Nos. 22 and 23 and Staff's Comments at 7
and 8. In the current IRP cycle, the Company provided all information requested by Staff, and
Staff was able to evaluate claims made by the Company in this and previous IRP cycles. Staff
notes that in its current IRP, the Company states that LNG is a costly method for meeting peak
demand.
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

STAFF COMMENTS 11 APRIL 23, 2020
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. Staff notes that natural gas liquification is an energy intensive process,
and that using liquified natural gas to meet demand during ordinary needle peaking events would
be very costly. According to the Company, the compressors used in the liquification process
consume one unit of natural gas for every three to four units that are liquefied. Id. at 54.
According to the Company, except for gas consumed during periodic maintenance and training
events, no gas has ever been supplied by the Nampa LNG facility to the Canyon County lateral to
meet normal demand, needle peak demand, or emergency needs (Response to Staff's PR Nos. 25
and 31). Staff notes, however, that gas trucked from the Nampa LNG facility to the Company's
degasification facilities along the Idaho Falls lateral is essential for meeting that lateral’s needle
peak demand. Additionally, the Nampa LNG facility had supplied liquefied natural gas to the
needs of a small Wyoming gas utility that had lost its supply in January, 2013 Intermountain Gas
2017 IRP at 107.
The Company’s non-utility LNG sales continue to grow and could possibly reach a point
where annual liquefaction levels are maximized. The Company’s LNG sales or margins could be
at risk if new commercial LNG facilities with lower operating costs are built in the region. The
Company mentions that additional LNG storage is not likely needed but liquefaction capabilities
may require expansion to increase daily production of LNG if sales increase. Id. at 140.

Demand Side Management (“DSM”)
Although it is not required by Commission Order, Staff previously recommended that this
IRP should include a more robust analysis of DSM resources, including a modeling process by
which DSM measures are selected based on cost-effectiveness, an explanation and update of
avoided costs, and the impact of DSM on supply and capacity needs. The Company 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. Importantly,
this CPA included an analysis of residential and commercial measures, which should lend itself to
a more robust DSM portfolio in the future. Additionally, the Company modeled DSM as a supply
resource starting in 2020. Staff believes that the Company in cooperation with its Energy

STAFF COMMENTS 12 APRIL 23, 2020
Efficiency (“EE”) stakeholder group is addressing concerns Staff detailed in previous IRPs and is
actively pursuing compliance with Commission orders.

Improvements from Previous IRPs
Avoided Cost
In Intermountain’s 2015 IRP case, 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 or are not cost-effective. See Order
No. 33314. In Intermountain’s 2017 IRP case, the Commission directed the Company to describe
how avoided costs change because of the IRP. See Order No. 33997.
Upon initial analysis of energy efficiency 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 has concerns with the Company’s avoided cost methodology
and believes that base rate embedded distribution costs are inappropriately included in its avoided
cost computations. Additionally, Staff believes the Company’s forecast of avoided commodity
costs is unreasonably high. Staff looks forward to working with the Company’s EE stakeholder
group in refining the avoided cost calculation as ordered in Commission Order No. 34536.

Public Participation
In Intermountain’s 2017 IRP case, the Commission directed the Company to 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.
The Company established the Intermountain Gas Resource Advisory Committee
(“IGRAC”). Id. at 3. The intent of IGRAC is to provide a forum through which public
participation can occur as the IRP is developed. Id. Advisory committee members were solicited
from across Intermountain's service territory as representatives of the communities served by the
Company. Id. Intermountain states it held meetings across its service territory. The Company
held three IGRAC meetings in multiple locations to facilitate committee member and public
participation. 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

STAFF COMMENTS 13 APRIL 23, 2020
the meetings. Staff recognizes the Company’s efforts to enhance public participation, appreciates
the opportunity to participate in the IGRAC, and looks forward increased public involvement in
future IRPs.

Lost and Unaccounted for Gas (“LAUF”)
In Order No. 32855, the Commission directed the Company to describe how LAUF is
managed and explain how those results were achieved. The Commission permits the Company to
recover a maximum of 0.85% of its total throughput as LAUF.3 The Company’s IRP reports that
its three-year average LAUF rate of 0.1176% is one of the best in the industry and details how
those results were achieved. Id. at 67. Staff recognizes the Company’s improvement in this area
and believes the Commission requirements were satisfied in this filing.4 Staff scrutinizes LAUF
in the Company’s annual PGA filings.

Conclusion
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 no peak day delivery deficits when forecasted peak day send-out is matched against existing
and planned resources for the 2019 through 2023 IRP period. However, as previously mentioned,
deficits exist if the planned resource enhancements are not included.

STAFF RECOMMENDATIONS
Staff believes the Company’s IRP has met the Commission requirements and recommends
the Commission acknowledge the Company’s 2019-2023 IRP. To improve future IRPs, Staff also
recommends 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

3 Order No. 30649
4 Order No. 32855 (“IT IS FURTHER ORDERED that the Company shall discontinue its semi-annual LAUF gas
reports. The Company shall include an exhibit in its PGA summarizing the statistics that have historically been
reported in its LAUF semi-annual reports. Further, in future IRPs, the Company shall include a LAUF gas section
that contains the information referenced above.”)

STAFF COMMENTS 14 APRIL 23, 2020
2) Validate the peak consumption estimates obtained from DNV GL’s Customer
Management Module using actual peak information from the Company’s AMI
meters.

Respectfully submitted this 23rd day of April 2020.

__________________________________
John R. Hammond, Jr.
Deputy Attorney General

Technical Staff: Kevin Keyt
Michael Morrison
Johan Kalala-Kasanda

i:umisc:comments/intg19.7jhkskjkmm comments
CERTIFICATE OF SERVICE
CERTIFICATE OF SERVICE

I HEREBY CERTIFY THAT I HAVE THIS 23rd DAY OF APRIL 2020,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,
IN CASE NO. INT-G-19-07, BY E-MAILING A COPY THEREOF, TO THE
FOLLOWING:

LORI BLATTNER
DIR – REGULATORY AFFAIRS
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE ID 83707
E-MAIL: [e-mail]

PRESTON N CARTER
GIVENS PURSLEY LLP
601 W BANNOCK ST
BOISE ID 83702
E-MAIL: [e-mail]
[e-mail]

BENJAMIN J OTTO
MATT NYKIEL
ID CONSERVATION LEAGUE
710 N 6TH ST
BOISE ID 83702
E-MAIL: [e-mail]
[e-mail]

/s/ Reyna Quintero __
SECRETARY