20221201Amen Direct with Exhibits.PDF

Preston N. Carter, ISB No. 8462
Morgan D. Goodin, ISB No. 11184
Blake W. Ringer, ISB No. 11223
Givens Pursley LLP
601 W. Bannock St.
Boise, Idaho 83702
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
[e-mail]

Attorneys for Intermountain Gas Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF INTERMOUNTAIN GAS COMPANY
FOR AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR NATURAL
GAS SERVICE IN THE STATE OF IDAHO
)
)
)
)
)
)
)
CASE NO. INT-G-22-07

DIRECT TESTIMONY OF RONALD J. AMEN
FOR INTERMOUNTAIN GAS COMPANY
DECEMBER 1, 2022

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I. INTRODUCTION
Q. Please state your name and business address. 1
A. My name is Ronald J. Amen and my business address is 10 Hospital Center Commons, Suite 2
400, Hilton Head Island, SC 29926. 3
Q. By whom are you employed and in what capacity? 4
A. I am employed by Atrium Economics, LLC (“Atrium”) as a Managing Partner. 5
Q. On whose behalf are you testifying? 6
A. I am testifying on behalf of Intermountain Gas Company (“Intermountain” or "Company”). 7
II. STATEMENT OF QUALIFICATIONS
Q. What has been the nature of your work in the energy utility consulting field? 8
A. I have over 40 years of experience in the utility industry, the last 24 years of which have 9
been in the field of utility management and economic consulting. I have advised and assisted 10
utility management, industry trade organizations, and large energy users in matters 11
pertaining to costing and pricing; competitive market analysis; regulatory planning and 12
policy development; resource planning and acquisition; strategic business planning; merger 13
and acquisition analysis; organizational restructuring; new product and service development; 14
and load research studies. I have prepared and presented expert testimony before utility 15
regulatory bodies across North America and have spoken on utility industry issues and 16
activities dealing with the pricing and marketing of gas utility services, gas and electric 17
resource planning and evaluation, and utility infrastructure replacement. Further background 18
information summarizing my work experience, presentation of expert testimony, and other 19
industry-related activities is included as Exhibit 1 to my testimony. 20

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Q. Have you previously testified before the Idaho Public Utilities Commission? 1
A. No. 2
III. PURPOSE OF TESTIMONY
Q. Please summarize your testimony. 3
A. First, I will present the load study analysis for purposes of determining each customer class’s 4
contribution to the system’s peak load. Next, I present the development of the Company’s 5
allocated Cost of Service Study (“COSS”) for the test year ended December 31, 2022, 6
including a comprehensive overview of the schedules created in support of them. Finally, I 7
present the Company’s proposed rates and the resulting customer bill impacts based on the 8
Company’s requested revenue increase. 9
My testimony consists of the following topics: 10
 Load Study and Analysis 11
 Theoretical Principles of Cost Allocation 12
 Intermountain’s COSS 13
 A Summary of the COSS Results by Rate Class 14
 Determination of Proposed Class Revenues 15
 Rate Design 16
 Customer Bill Impacts 17
Q. Are you sponsoring any exhibits to your direct testimony? 18
A. Yes. I am sponsoring the following 5 Exhibits, all of which were prepared by me or under 19
my supervision and direction.: 20
Exhibit 1 – Resume of Ronald J. Amen 21
Exhibit 2 – Cost of Service Study 22

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Exhibit 3 – Proposed Revenue Targets 1
Exhibit 4 – Proposed Rate Design and Proof of Revenue 2
Exhibit 5 – Customer Bill Impacts 3
I. LOAD STUDY AND ANALYSIS 4
Q. What is a load study? 5
A. A load study determines each customer class’s contribution to the natural gas utility’s 6
pipeline system peak load. This information is used to develop allocators for purposes of 7
allocating shared costs, or costs that cannot be directly assigned, such as plant and 8
equipment, operation, and maintenance expenses (“O&M”), and some administrative costs 9
to each customer class on the basis of peak day usage. Natural gas pipeline systems are 10
designed and constructed to satisfy peak day demand under design weather conditions and 11
a load study identifies each class’s relative contribution to the peak day demand. 12
Q. Did Intermountain develop a load study in its previous general rate case proceeding, 13
No. INT-G-16-02 (“2016 Case”)? 14
A. No. In its last case, the Company reported that it did not have adequate data to perform a 15
detailed load study. Instead, the Company estimated peak demand for each class by 16
deducting known daily metered industrial and transportation demand from its aggregate peak 17
to arrive at the peak demand for the non-daily metered residential and commercial classes. 18
The Company then allocated between residential and commercial classes on the basis of 19
peak month usage. A load study requires sufficient data for each class to determine the 20
response of load in a particular class to changes in heating degree days (“HDD”). In its last 21
general rate proceeding, the Commission found that the Company lacked sufficient data to 22

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definitively allocate the revenue requirement between its non-daily metered classes.1 As 1
such, the Commission determined that a gradual move of 50% towards cost-of-service was 2
reasonable and warranted for the affected customer classes.2 Lastly, the Commission 3
encouraged the Company to participate with Staff and other interested parties to determine 4
the best way forward as it relates to class cost-of-service and the acquisition of appropriate 5
cost causation and load data.3 6
Q. Has Intermountain acquired sufficient data to develop a load study in this filing? 7
A. Yes. The Company has dramatically expanded its daily metering capability through 8
Advanced Metering Infrastructure (“AMI”). Table 1 below shows the availability of daily 9
metered data for the residential and commercial classes for each of Intermountain’s seven 10
distinct weather zones. Intermountain also had AMI in place for many of its Large Volume 11
(“LV”) customers, (Large Volume, Transport, and Interruptible Transport), however those 12
classes yielded weak regression results due either to lack of weather sensitivity, lack of 13
available data or small number of customers, and as a result, daily metered data for those 14
classes was not relied upon for projecting peak load for the LV customers. 15
Table 1 Percent of Residential and Commercial Premises with Daily Meter Readings

350
Canyon
County
450
Boise
500
Sun
Valley
600
Twin
Falls
700
Rexburg
750
Idaho
Falls
800
Pocatello
Residential 93.2% 84.6% 35.3% 0.0% 45.2% 0.0% 0.0%
Commercial 95.2% 87.4% 48.2% 0.0% 58.3% 0.0% 0.0%
16
Q. Please describe the characteristics of Intermountain’s gas load. 17

1 Idaho PUC Order No. 33757, Case No. INT-G-16-02 (April 28, 2017) at 28.
2 Ibid.
3 Id., at 28-29.

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A. Intermountain serves customers throughout a geographically and economically diverse 1
service territory. There are seven primary rate classes (Residential (“RS”) Commercial 2
(“GS”), Large Volume (“LV-1”), Transport (“T-4”), Interruptible Transport (“T-3”), 3
Interruptible Snowmelt-Residential (“IS-R”), and Interruptible Snowmelt-Commercial (“IS-4
C”)). Intermountain’s customers are spread across seven diverse geographic areas with 5
differing weather patterns and elevations (Canyon County, Boise, Hailey (or Sun Valley), 6
Twin Falls, Rexburg, Idaho Falls, and Pocatello). Below is a chart showing total monthly 7
consumption for each rate class for the twelve months ended July 31, 2022. 8
Figure 1 Intermountain Monthly Consumption by Rate Class
9
Intermountain’s Residential and Commercial customers are weather sensitive and are spread 10
across all seven weather zones. The Company’s Large Volume customers are made of a mix 11
of industrial and commercial loads and use in excess of 200,000 therms per year. These 12
customers may be subject to one of three rate classes: a bundled sales tariff (LV-1), a 13
distribution system only transportation tariff (T-4), and an interruptible transportation tariff 14
(T-3). The LV customers, on average, account for roughly 50% of Intermountain’s annual 15

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throughput and approximately 25% of the projected design peak day. The vast majority of 1
the LV throughput reflects distribution system-only transportation and as a whole the LV 2
gas usage pattern is not weather sensitive. The Company has Residential Interruptible Snow 3
Melt Customers, which are separately metered from the premises and are fully interruptible 4
with at least two hours of notice. Similarly, there are Small Commercial Interruptible 5
Snowmelt Service customers that are also interruptible with two hours of notice. Lastly, the 6
Company has Irrigation Customers, which do not contribute to the winter peak and do not 7
factor into the load study. 8
Table 2 below provides a summary of premises and annual consumption projected 9
for the test year ended 2022 as a percentage of Intermountain’s whole system throughput. 10
Table 2 Test Year Premises and Consumption Data for Intermountain’s Gas
System4
Premises %
Premises
Test Year
Consumption
(Therms)
% Consumption
Residential 368,350 91.23% 282,067,442 35.03%
Commercial 34,966 8.66% 137,726,944 17.11%
Large Volume 34 0.01% 13,566,644 1.69%
Transport 102 0.03% 41,523,144 5.16%
Interruptible Transport 7 0.00% 329,449,906 40.92%
Residential Snowmelt 220 0.05% 455,543 0.06%
Commercial Snowmelt 53 0.01% 269,444 0.03%
Irrigation 9 0.00% 71,505 0.01%
TOTAL 403,742 100.00% 805,130,573 100.00%

Q. How does the Company define its design day? 11
A. The Company’s design day represents the coldest temperatures that can be expected to occur 12
during an extreme cold or peak weather event. Intermountain used a statistical model to 13

4 Based on average monthly customers and total therms projected for the test year (January 2022 – December 2022)
with actuals through September 2022 and projected thereafter.

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develop probability-derived peak HDD values to characterize its design day, corresponding 1
to an exceedance probability that Intermountain considers appropriate for its intended use. 2
Intermountain used exceedance probability results to review data associated with both a 50-3
year and 100-year probability event, as shown below in Table 3. The Company’s practice 4
has been to rely on a 50-year probability event, which results in a 78 heating-degree-day 5
(“HDD”), for use in the design weather model. 6
Table 3 Peak Day HDD65 Event by Region

350
Canyon
County
450
Boise
500
Sun
Valley
600
Twin
Falls
700
Rexburg
750
Idaho
Falls
800
Pocatello
Total
Company
50-Year Event 78 75 82 77 88 87 82 78.43
100-Year Event 81 79 85 80 91 89 85 81.75
Max Degree
Days5 83 81 88 80 92 88 83 82.88
7
Q. Please describe the methodology and approach for developing the Peak Load Study. 8
A. The development of the Peak Load Study began by performing regression analyses to 9
identify weather sensitive loads, measuring the historical linear relationship between 10
metered daily volumes and HDD for each customer class and weather zone. Regressions 11
were performed on all available daily AMI data, and on monthly billing data, for the period 12
from January 1, 2019, to July 31, 2022, regressing heating degree days (using 65 degrees as 13
the baseline) against average daily use per customer for each customer class and weather 14
zone combination. The daily AMI reads were in CCF, so it was necessary to apply a monthly 15
billing adjustment factor for each rate class, month, and weather zone to account for the 16
heating value and pressure to arrive at delivered therms. The goal is to project the design day 17

5 Max Degree Days reflect the coldest day on record.

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peak, i.e., the 50-year event using the results of the linear regression equations or another 1
reasonable estimate of peak load by rate class. The regression results were relied upon to 2
project design day load for the residential and commercial classes, or “Core”6 customer 3
classes. For the large volume classes, either due to lack of weather sensitivity (LV-1), lack 4
of consistent and strong regression results (T-4), or due to lack of data (T-3), other means of 5
estimating peak day results were used. 6
Q. Please describe the regression analyses using daily AMI metered data for the 7
residential and commercial customer classes and the development of the “Blended” 8
peak load sendout model. 9
A. As indicated in Table 1 above, there is significant penetration of daily AMI meters for the 10
residential and commercial classes for two primary weather zones, 350 Canyon County 11
(93.2% residential (“RS”) and 95.2% commercial (“GS”)); and 450 Boise (84.6% RS and 12
87.4% GS). There was moderate penetration of daily AMI meters for two additional weather 13
zones 500 Sun Valley (or Hailey) (35.3% RS and 48.2% GS); and 700 Rexburg (45.2% RS 14
and 58.3% GS). There were no daily AMI data for residential or commercial classes for 15
Twin Falls (600), Idaho Falls (750); or Pocatello (800)7. The results of the daily regressions 16
are listed below in Table 4 17

6 Core customers is defined in Intermountain’s 2021-2026 IRP as, “All residential and commercial customers of
Intermountain Gas Company. Includes all customers receiving service under the RS and GS tariffs.”
7 Pocatello did reflect data for one daily metered residential customer with intermittent usage in December 2019, but
that customer did not bring the percentage of daily metered customers above zero.

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Table 4 Daily Regression Results (January 2019 – July 2022)
Regression
Results
350 450 500 600 700 750 800
Residential Class
Adjusted R2 0.937 0.952 0.952 No data 0.562 No data 0.009
x coefficient 0.110 0.121 0.105 No data 0.056 No data 0.009
x t-stat 139.897 161.085 160.277 No data 40.964 No data 3.591
x std. error 0.001 0.001 0.001 No data 0.001 No data 0.002
y coefficient 0.271 0.404 0.346 No data 0.411 No data (0.033)
y t-stat 17.666 28.024 19.449 No data 10.764 No data (0.560)
y std. error 0.015 0.014 0.018 No data 0.038 No data 0.059
Commercial Class
Adjusted R2 0.906 0.936 0.906 No data 0.583 No data No data
x coefficient 0.451 0.468 0.243 No data 0.283 No data No data
x t-stat 112.345 138.829 112.087 No data 42.799 No data No data
x std. error 0.004 0.003 0.002 No data 0.007 No data No data
y coefficient 1.517 1.947 0.419 No data 1.424 No data No data
y t-stat 19.321 29.996 7.083 No data 7.751 No data No data
y std. error 0.079 0.065 0.059 No data 0.184 No data No data
1
Typically, the average usage of customers in the same geographical location and in the same 2
customer rate class can be used to substitute data for a customer which lacks sufficient 3
information, providing that customers are of relatively similar size. Where daily results were 4
determined to be sufficiently robust, (i.e., Adjusted R2 in excess of 0.90, and where the t-5
statistic on both the x- and y-coefficients were in excess of 10.0), the results were brought 6
forward into the peak load model. Where daily results were not sufficiently strong, or where 7
data was lacking, monthly regression results were substituted for the daily data. This dataset 8
is referred to as the “Blended Model” since it includes regressions performed on both daily 9
and monthly data. The Blended Model includes daily regression results for the Residential 10
class in weather zones 350, 450, and 500; and the Commercial class in weather zones 350 11
and 450. The remaining data used in the Blended Model was based on monthly regressions. 12

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Q. Please describe the regression analyses using monthly billing data for the residential 1
and commercial customer classes and the development of the “Monthly” peak load 2
sendout model. 3
A. The monthly data regressions were performed on Intermountain’s monthly billing data. This 4
data had the advantage of covering all customers within the class and weather zone, and was 5
already in therms so no adjustments to the data were necessary. In the monthly data 6
regressions, average daily HDD was regressed against average daily use per customer by 7
month, for each class and weather zone. The results of the monthly data regressions for the 8
residential and commercial classes are reported in Table 5. These results are referred to as 9
the “Monthly Model.” 10
Table 5 Monthly Regression Results (January 2019 – July 2022)
Regression
Results
350 450 500 600 700 750 800
Residential Class
Adjusted R2 0.979 0.990 0.967 0.982 0.993 0.990 0.983
x coefficient 0.115 0.126 0.162 0.101 0.071 0.085 0.093
x t-stat 44.098 64.639 35.372 48.431 75.560 65.060 48.621
x std. error 0.003 0.002 0.005 0.002 0.001 0.001 0.002
y coefficient 0.210 0.353 0.289 0.162 0.396 0.327 0.168
y t-stat 4.104 9.528 2.349 3.511 14.722 8.859 3.590
y std. error 0.051 0.037 0.123 0.046 0.027 0.037 0.047
Commercial Class
Adjusted R2 0.881 0.982 0.920 0.970 0.988 0.982 0.972
x coefficient 0.522 0.582 0.320 0.507 0.412 0.447 0.463
x t-stat 17.682 47.353 22.044 36.669 58.217 47.918 37.897
x std. error 0.030 0.012 0.015 0.014 0.007 0.009 0.012
y coefficient 3.427 2.365 1.437 2.093 2.150 1.139 1.140
y t-stat 5.956 10.153 3.681 6.897 10.820 4.330 3.823
y std. error 0.575 0.233 0.390 0.303 0.199 0.263 0.298
Q. Was there a validation step performed to check the accuracy of the “Blended” or the 11
“Monthly” peak load sendout models in predicting the winter peak load? 12

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A. Yes. To check the appropriateness of the modeling results, “Blended” and “Monthly” peak 1
load sendout models were validated by comparing each to actual historical sendout, using 2
actual historical HDD by weather zone and the class/weather zone regressions for the period 3
November 1, 2021, to March 31, 2022. The results of that comparison are illustrated below. 4
Figure 2 Blended and Monthly Models versus IGC Core Sendout
5
As illustrated in Figure 2 above, the peak use during the illustrated period occurred on 6
January 2, 2022, with an average HDD across all weather zones of 53.47, and core market 7
load of 355,565 MMBtu. This HDD was slightly lower than the coldest day of the period, 8
January 1, 2022, at 57.02 HDD, but since January 1st was a holiday, the sendout was lower 9
than on January 2nd, even though the HDD was higher. As Figure 2 shows, the Monthly data 10
does a slightly better job of predicting the peak than the Blended data. This disparity could 11
be explained by the fact that daily data tends to be less stable and more volatile than monthly 12

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data and that some of the HDD sensitivity may be lost in the “noise” in the daily data. In 1
addition, it is likely that there may be large, highly weather-sensitive customers that are not 2
yet daily metered and therefore not reflected in the daily regressions. For these reasons, it 3
has been determined that the Monthly peak load sendout model will be the best predictor of 4
Intermountain’s design day peak. 5
Q. What were the results of the Monthly Peak Load Sendout Model for Intermountain’s 6
Core Residential and Commercial Customers? 7
A. The regression results were extrapolated from the Monthly peak load sendout model to the 8
average test year number of customers for each weather zone for each of the Core classes, 9
RS and GS. The results are shown in Table 6 below. 10
Table 6 Peak Load Sendout for Core Customers
Core Rate Class Customers8 Peak Load
(Therms)
Residential 368,350 3,360,303
Commercial 34,966 1,483,938
Total Core Customers 403,316 4,844,241
11

8 Based on average monthly customers projected for the test year (January 2022 – December 2022) with actuals
through September 2022 and projected thereafter. Totals exclude interruptible snowmelt classes, CNG, and
Irrigation.

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Q. How did you estimate the peak day sendout for the LV rate classes? 1
A. Because the LV customers are not as weather sensitive as the residential and commercial 2
customers, forecasting their volumes using standard regression techniques based on 3
projected weather may not provide statistically significant results. Also, the LV customer 4
counts are so few that they may fall below the number required to provide an adequate 5
statistical population/sample size. As such, the maximum contract demand was used for 6
these large volume customers to project loads at peak. For the LV-1 class and the T-4 class, 7
the maximum daily firm quantity (MDFQ) was used as of September 2022. The MDFQ 8
reflects the maximum amount of daily gas and/or capacity Intermountain must be prepared 9
to provide to its firm LV customers on any given day, including the projected system peak 10
day. These amounts represent a contracted daily requirement and reflects the known peak 11
day obligation for each customer. The September 2022 MDFQ amounts were 1,485,410 12
therms for the T-4 class, and 74,405 therms for the LV-1 class. It is reasonable to expect that 13
on a peak day these customers will be using their full contracted MDFQ. I note that this 14
treatment is consistent with how the Peak Day Sendout was developed in the 2021 IRP.9 15
The daily peak sendout for the Interruptible Transport Class, T-3, was determined 16
based on the test year average daily load for the twelve months ending December 2022. T-3 17
customers are interruptible and as such there are no assurances of the amount of capacity 18
that they may be granted on any given day. However, given that Intermountain has rarely 19
interrupted these customers, it is reasonable to provide a peak day allocation for their 20
contribution to the system peak. Peak day sendout results have been provided with and 21

9 Intermountain Gas Company, Integrated Resource Plan 2021- 2026, at p. 126.

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without the interruptible customers; and note that interruptible customers have previously 1
been excluded from Intermountain’s peak load analyses. The average daily usage for the T-2
3 customers was 113,762 therms for the test year twelve-month period ending December 31, 3
2022. 4
Q. Was the peak day sendout estimated for the Interruptible Snowmelt Classes? 5
A. Yes. The peak day sendout for the Interruptible snowmelt classes (IS-R and IS-C) were 6
estimated based on their average daily use for the month of January 2022. These classes are 7
also fully interruptible with two hours of notice and could not be assured of capacity during 8
any given peak day. However, as the Company has rarely interrupted these customers, they 9
have been included in the Peak Load Study for reference. 10
Q. Please provide the results for Intermountain’s total peak day sendout. 11
A. The results of the peak load study and the resulting allocations with and without the inclusion 12
of interruptible customers were prepared and summarized in Table 7 below. 13
Table 7 Peak Day Sendout with and without Interruptible Classes – Monthly Model
50-Year Peak Day Event – Monthly Model
Firm & Interruptible Firm Only
Rate Class: Therms % Therms %
Residential (RS) 3,360,303 51.5% 3,360,303 52.5%
General Service (GS) 1,483,938 22.8% 1,483,938 23.2%
Large Volume (LV-1) 74,405 1.1% 74,405 1.2%
Transportation (Interruptible) (T-3) 113,762 1.7% - 0.0%
Transportation (Firm) (T-4) 1,485,410 22.8% 1,485,410 23.2%
Snowmelt - Residential (IS-R) 2,404 0.0% - 0%
Snowmelt - Commercial (IS-C) 1,421 0.0% - 0%
TOTAL

6,521,643 6,404,055
For comparative purposes, the results of the Blended peak load model have been included, 14
which incorporated the daily meter readings, where appropriate. As shown below, the 15

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Blended model provides a very similar class allocation relative to the peak compared to the 1
Monthly model. 2
Table 8 Peak Day Sendout with and without Interruptible Classes – Blended Model
50-Year Peak Day Event – Blended Model
Firm & Interruptible Firm Only
Rate Class: Therms % Therms %
Residential (RS) 3,222,662 51.8% 3,222,662 52.8%
General Service (GS) 1,324,700 21.3% 1,324,700 21.7%
Large Volume (LV-1) 74,405 1.2% 74,405 1.2%
Transportation (Interruptible) (T-3) 113,762 1.8% - 0.0%
Transportation (Firm) (T-4) 1,485,410 23.9% 1,485,410 24.3%
Snowmelt - Residential (IS-R) 2,404 0.0% - 0.0%
Snowmelt - Commercial (IS-C) 1,421 0.0% - 0.0%
TOTAL

6,224,765

6,107,177

For purposes of this allocated class cost of service study, the results shown in Table 7 were 3
selected, which use the Monthly peak load sendout model to determine the Core peak day 4
sendout since I believe it provides superior results in predicting peak day sendout as 5
illustrated above in Figure 2. These results are aligned with Intermountain’s projections of 6
peak day sendout in their 2021-2026 IRP, which projected 613,523 MMBtu for 2022 and 7
626,676 MMBtu for 2023 for firm demand (RS, GS, LV-1, and T-4). This corresponds to 8
the Monthly model result of 6,404,055 therms (640,406 MMBtu), which exceeds the IRP’s 9
estimated peak day sendout for 2023 by 13,730 MMBtu. This variance is largely attributable 10
to increases in MDFQ’s for LV-1 and T-4 since the IRP was published in 2021. The IRP 11
estimated MDFQ’s for LV-1 and T-4 classes of 140,779 MMBtu, compared to the MDFQ’s 12
of 155,982 MMBtu used in the Monthly model, a difference of 15,203 MMBtu. 13
IV. THEORETICAL PRINCIPLES OF COST ALLOCATION
Q. Why do utilities conduct cost allocation studies as part of the regulatory process? 14

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A. There are many purposes for utilities conducting cost allocation studies, ranging from 1
designing appropriate price signals in rates to determining the share of costs or revenue 2
requirements borne by the utility’s various rate or customer classes. In this case, an 3
embedded COSS is a useful tool for determining the allocation of Intermountain’s revenue 4
requirement among its customer classes. It is also a useful tool for rate design because it can 5
identify the important cost drivers associated with serving customers and satisfying their 6
design day demands. 7
Embedded cost studies analyze the costs for a test period based on either the book 8
value of accounting costs (a historical period) or the estimated book value of costs for a 9
forecasted test year or some combination of historical and future costs. Typically, embedded 10
cost studies are used to allocate the revenue requirement between jurisdictions, classes, and 11
between customers within a class. 12
Q. Please discuss the reasons that cost of service studies are utilized in regulatory 13
proceedings. 14
A. Cost of service studies represent an attempt to analyze which customer or group of customers 15
cause the utility to incur the costs to provide service. The requirement to develop cost studies 16
results from the nature of utility costs. Utility costs are characterized by the existence of 17
common costs. Common costs occur when the fixed costs of providing service to one or 18
more classes, or the cost of providing multiple products to the same class, use the same 19
facilities and the use by one class precludes the use by another class. 20
In addition, utility costs may be fixed or variable in nature. Fixed costs do not change 21
with the level of throughput, while variable costs change directly with changes in throughput. 22
Most non-fuel related utility costs are fixed in the short run and do not vary with changes in 23

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customers’ loads. This includes the cost of distribution mains and service lines, meters, and 1
regulators. The distribution assets of a gas utility do not vary with the level of throughput in 2
the short run. In the long run, main costs vary with either growing design day demand or a 3
growing number of customers. 4
Finally, utility costs exhibit significant economies of scale. Scale economies result 5
in declining average cost as gas throughput increases and marginal costs must be below 6
average costs. These characteristics have implications for both cost analysis and rate design 7
from a theoretical and practical perspective. The development of cost studies requires an 8
understanding of the operating characteristics of the utility system. Further, as discussed 9
below, different cost studies provide different contributions to the development of 10
economically efficient rates and the cost responsibility by customer class. 11
Q. Please discuss the application of economic theory to cost allocation. 12
A. The allocation of costs using cost of service studies is not a theoretical economic exercise. 13
It is rather a practical requirement of regulation since rates must be set based on the cost of 14
service for the utility under cost-based regulatory models. As a general matter, utilities must 15
be allowed a reasonable opportunity to earn a return of and on the assets used to serve their 16
customers. This is the cost of service standard and equates to the revenue requirements for 17
utility service. The opportunity for the utility to earn its allowed rate of return depends on 18
the rates applied to customers producing that revenue requirement. Using the cost 19
information per unit of demand, customer, and energy developed in the cost of service study 20
to understand and quantify the allocated costs in each customer class is a useful step in the 21
rate design process to guide the development of rates. 22

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However, the existence of common costs makes any allocation of costs problematic 1
from a strict economic perspective. This is theoretically true for any of the various utility 2
costing methods that may be used to allocate costs. Theoretical economists have developed 3
the theory of subsidy-free prices to evaluate traditional regulatory cost allocations. Prices 4
are said to be subsidy-free so long as the price exceeds the incremental cost of providing 5
service but is less than stand-alone costs (“SAC”). The logic for this concept is that if 6
customers’ prices exceed incremental cost, those customers contribute to the fixed costs of 7
the utility. All other customers benefit from this contribution to fixed costs because it reduces 8
the cost they are required to bear. Prices must be below the SAC because the customer would 9
not be willing to participate in the service offering if prices exceed SAC. 10
SAC is an important concept for Intermountain because certain customers have 11
competitive options for the end uses supplied by natural gas through the use of alternative 12
fuels. As a result, subsidy-free prices permit all customers to benefit from the system’s scale 13
and common costs, and all customers are better off because the system is sustainable. If strict 14
application of the cost allocation study suggests rates that exceed SAC for some customers, 15
prices must nevertheless be set below the SAC, but above marginal cost, to ensure that those 16
customers make the maximum practical contribution to the common costs of the utility. 17
Q. If any allocation of common cost is problematic from a theoretical perspective, how is 18
it possible to meet the practical requirements of cost allocation? 19
A. As noted above, the practical reality of regulation often requires that common costs be 20
allocated among jurisdictions, classes of service, rate schedules, and customers within rate 21
schedules. The key to a reasonable cost allocation is an understanding of cost causation. 22
Cost causation, as alluded to earlier, addresses the need to identify which customer or group 23

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of customers causes the utility to incur particular types of costs. To answer this question, it 1
is necessary to establish a linkage between a Local Distribution Company’s (“LDC's”) 2
customers and the particular costs incurred by the utility in serving those customers. 3
An important element in the selection and development of a reasonable COSS 4
allocation methodology is the establishment of relationships between customer 5
requirements, load profiles and usage characteristics on the one hand and the costs incurred 6
by the Company in serving those requirements on the other hand. For example, providing a 7
customer with gas service during peak periods can have much different cost implications for 8
the utility than service to a customer who requires off-peak gas service. 9
Q. Why are the relationships between customer requirements, load profiles, and usage 10
characteristics significant to cost causation? 11
A. The Company's distribution system is designed to meet three primary objectives: (1) to 12
extend distribution services to all customers entitled to be attached to the system; (2) to meet 13
the aggregate design day peak capacity requirements of all customers entitled to service on 14
the peak day; and (3) to deliver volumes of natural gas to those customers either on a sales 15
or transportation basis. There are certain costs associated with each of these objectives. Also, 16
there is generally a direct link between the manner in which such costs are defined and their 17
subsequent allocation. 18
Customer related costs are incurred to attach a customer to the distribution system, 19
meter any gas usage and maintain the customer's account. Customer costs are a function of 20
the number of customers served and continue to be incurred whether or not the customer 21
uses any gas. They generally include capital costs associated with minimum size distribution 22
mains, services, meters, regulators and customer service and accounting expenses. 23

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Demand or capacity related costs are associated with plant that is designed, installed, 1
and operated to meet maximum hourly or daily gas flow requirements, such as the 2
transmission and distribution mains, or more localized distribution facilities that are 3
designed to satisfy individual customer maximum demands. Gas supply contracts also have 4
a capacity related component of cost relative to the Company's requirements for serving 5
daily peak demands and the winter peaking season. 6
Commodity related costs are those costs that vary with the throughput sold to, or 7
transported for, customers. Costs related to gas supply are classified as commodity related 8
to the extent, they vary with the amount of gas volumes purchased by the Company for its 9
sales service customers. 10
From a cost of service perspective, the best approach is a direct assignment of costs 11
where costs are incurred for a customer or class of customers and can be so identified. Where 12
costs cannot be directly assigned, the development of allocation factors by customer class 13
uses principles of both economics and engineering. This results in appropriate allocation 14
factors for different elements of costs based on cost causation. For example, we know from 15
the manner in which customers are billed that each customer requires a meter. Meters differ 16
in size and type depending on the customer’s load characteristics. These meters have 17
different costs based on size and type. Therefore, meter costs are customer-related, but 18
differences in the cost of meters are reflected by using a different meter cost for each class 19
of service. For some classes such as the largest customers, the meter cost may be unique for 20
each customer. 21
Q. How does one establish the cost and utility service relationships you previously 22
discussed? 23

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A. To establish these relationships, the Company must analyze its gas system design and 1
operations, its accounting records as well as its system and customer load data (e.g., annual, 2
and peak period gas consumption levels). From the results of those analyses, methods of 3
direct assignment and common cost allocation methodologies can be chosen for all of the 4
utility's plant and expense elements. 5
Q. Please explain what you mean by the term “direct assignment.” 6
A. The term direct assignment relates to a specific identification and isolation of plant and/or 7
expense incurred exclusively to serve a specific customer or group of customers. Direct 8
assignments best reflect the cost causation characteristics of serving individual customers or 9
groups of customers. Therefore, in performing a COSS, the cost analyst seeks to maximize 10
the amount of plant and expense directly assigned to particular customer groups to avoid the 11
need to rely upon other more generalized allocation methods. An alternative to direct 12
assignment is an allocation methodology supported by a special study as is done with costs 13
associated with meters and services. 14
Q. What prompts the analyst to elect to perform a special study? 15
A. When direct assignment is not readily apparent from the description of the costs recorded in 16
the various utility plant and expense accounts, then further analysis may be conducted to 17
derive an appropriate basis for cost allocation. For example, in evaluating the costs charged 18
to certain operating or administrative expense accounts, it is customary to assess the 19
underlying activities, the related services provided, and for whose benefit the services were 20
performed. 21
Q. How do you determine whether to directly assign costs to a particular customer or 22
customer class? 23

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A. Direct assignments of plant and expenses to particular customers or classes of customers are 1
made on the basis of special studies wherever the necessary data are available. These 2
assignments are developed by detailed analyses of the utility's maps and records, work order 3
descriptions, property records and customer accounting records. Within time and budgetary 4
constraints, the greater the magnitude of cost responsibility based upon direct assignments, 5
the less reliance need be placed on common plant allocation methodologies associated with 6
joint use plant. 7
Q. Is it realistic to assume that a large portion of the plant and expenses of a utility can 8
be directly assigned? 9
A. No. The nature of utility operations is characterized by the existence of common or joint use 10
facilities, as mentioned earlier. Out of necessity, then, to the extent a utility's plant and 11
expense cannot be directly assigned to customer groups, common allocation methods must 12
be derived to assign or allocate the remaining costs to the customer classes. The analyses 13
discussed above facilitate the derivation of reasonable allocation factors for cost allocation 14
purposes. 15
V. INTERMOUNTAIN’S COST OF SERVICE STUDY
Q. Please describe the process of performing Intermountain’s COSS analysis. 16
A. Three broad steps were followed to perform the Company's COSS: (1) functionalization, (2) 17
classification, and (3) allocation. The first step, functionalization, identifies and separates 18
plant and expenses into specific categories based on the various characteristics of utility 19
operation. The Company's functional cost categories associated with gas service include 20
storage, transmission, distribution, and general (customer). The general function includes 21
costs that cannot be directly assigned to the primary operating functions of storage, 22

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transmission, and distribution. These costs are functionalized in accordance with the Federal 1
Energy Regulatory Commission (FERC) Uniform System of Accounts (USOA). 2
Classification of costs, the second step, further separates the functionalized plant and 3
expenses into the three cost-defining characteristics previously discussed: (1) customer, (2) 4
demand or capacity, and (3) commodity, along with an additional revenue classification 5
consisting of working capital items and revenue. The final step is the allocation of each 6
functionalized and classified cost element to the individual customer class. Costs typically 7
are allocated on customer, demand, commodity, or revenue allocation factors. 8
Q. Are there factors that can influence the overall cost allocation framework utilized by 9
a gas utility when performing a COSS? 10
A. Yes. The factors which can influence the cost allocation used to perform a COSS include: 11
(1) the physical configuration of the utility’s gas system; (2) the availability of data within 12
the utility; and (3) the state legislative and regulatory policies and evidentiary requirements 13
applicable to the utility. 14
Q. Why are these considerations relevant to conducting Intermountain’s COSS? 15
A. It is important to understand these considerations because they influence the overall context 16
within which a utility's cost study was conducted. In particular, they provide an indication 17
of where efforts should be focused for purposes of conducting a more detailed analysis of 18
the utility's gas system design and operations and understanding the regulatory environment 19
in the State of Idaho as it pertains to cost of service studies and gas ratemaking issues. 20
Q. Please explain why the physical configuration of the system is an important 21
consideration. 22

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A. The particulars of the physical configuration of the transmission and distribution system are 1
important. The specific characteristics of the system configuration, such as, whether the 2
distribution system is a centralized or a dispersed one, should be identified. Other such 3
characteristics are whether the utility has a single city-gate or a multiple city-gate 4
configuration, whether the utility has an integrated transmission and distribution system or 5
a distribution-only operation, and whether the system is a multiple pressure based or a single 6
pressure-based operation. 7
Q. What are the specific physical characteristics of Intermountain’s system? 8
A. The physical configuration of Intermountain’s system is a dispersed / multiple city-gate, 9
storage, transmission, distribution, and multi pressure-based system. 10
Q. What was the source of the cost data analyzed in the Company's COSS? 11
A. All cost of service data has been extracted from the Company's total cost of service (i.e., 12
total revenue requirement) and subsidiary schedules contained in this filing. 13
Q. How does the availability of data influence a COSS? 14
A. The structure of the utility’s books and records can influence the cost study framework. This 15
structure relates to attributes such as the level of detail, segregation of data by operating unit 16
or geographic region, and the types of load data available. Intermountain maintains many 17
detailed plant accounting records for its distribution-related facilities. 18
Q. How are Intermountain’s classes structured for purposes of the COSS? 19
A. The COSS evaluated five customer classes: Residential (RS, IS-R), General (GS, IS-C), 20
Large Volume (LV-1), Interruptible Transport (T-3), and Firm Transport (T-4). 21
Q. Do you propose any modifications to the current classes? 22
A. No. 23

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Q. Please describe the process of performing Intermountain’s COSS analysis. 1
A. The detailed process description of Intermountain’s COSS analysis is presented in Exhibit 2
2 - Cost of Service Study. Exhibit 2 provides a full scope of the COSS development 3
process and the results. 4
Q. Please discuss the content of Exhibit 2. 5
A. Exhibit 2 – Cost of Service Study consists of three sections detailing the process of 6
developing the COSS. The first section includes an introduction, the general purpose, and 7
an overview of the excel-based fully functional COSS model presented in this proceeding. 8
The second section presents the COSS development process specific to the Company 9
including Functionalization, Classification, and Allocation. The Allocation section 10
specifically describes all internal and external allocation factors and development bases 11
and processes used in the COSS. The last section depicts the results of the cost of service 12
study, including revenue requirement apportionment, comparison of cost of service with 13
revenues under present and proposed rates, and development of rate of return by customer 14
class under present and proposed rates. 15
Q. Please describe the schedules included in Exhibit 2. 16
A. The following is the list of Schedules included in Exhibit 2: 17
 Schedule 1 - Account Balances, Functionalization, Classification and Allocation 18
 Schedule 2 - External Allocation Factors 19
 Schedule 3 - Internal Allocation Factors 20
 Schedule 4 - Cost of Service and Rate of Return under Present and Proposed Rates 21
 Schedule 5 - Cost of Service Allocation Study Detail by Account 22

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 Schedule 6 - Functionalized and Classified Rate Base and Revenue Requirement, 1
and Unit Costs by Customer Class 2
 Schedule 7 – Alternative Cost of Service and Rate of Return Under Present and 3
Proposed Rates 4
Q. Please explain the COSS information contained in Schedules 1 through 7. 5
A. Schedule 1 displays revenue requirements presented by FERC accounts with corresponding 6
selections of functions, classifications, and allocations methods applied to the accounts. 7
Schedule 2 and Schedule 3 depict the derivation of external and internal allocation factors 8
that are explained in detail in Exhibit 2. Schedule 4 is a summary of the cost to serve as 9
compared to revenues under present and proposed rates. Schedule 5 is a detailed cost of 10
service study presented by the FERC accounts for the individual rate classes. Schedule 6 11
presents a summary of functionalized and classified rate base and revenue requirements 12
along with derived unit cost by customer class. Lastly, Schedule 7 presents a summary of 13
the cost of service similar to Schedule 4, based on the peak load study with interruptible 14
customers included, which is discussed below in this testimony. 15
Q. How did the COSS classify and allocate underground storage plant? 16
A. The storage plant accounts contain the costs related to the Company's LNG facilities. These 17
facilities are needed to provide deliverability and reliability during peak periods. Because of 18
the cost and cycle characteristics, LNG withdrawals are typically reserved for needle peaking 19
during very cold weather events or for system integrity events. Therefore, the storage plant 20
accounts are classified as demand and allocated on a peak day basis. 21
Q. How did the COSS classify and allocate transmission plant? 22

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A. The transmission plant accounts contain the costs related to the Company's high pressure 1
transmission facilities. These facilities were designed and sized to provide deliverability 2
during peak periods. Therefore, the transmission plant accounts are classified as demand and 3
allocated on a peak day basis. 4
Q. How did the Company’s COSS classify and allocate investment in Distribution 5
Mains? 6
A. The Company classified 55.3% of its investment in distribution mains as customer-related 7
and 44.7% of the investment as demand-related. The customer related portion of the 8
distribution mains investment was then allocated based on the number of customers on 9
Intermountain’s distribution system. The demand related investment was allocated to the 10
customer classes based on the respective contributions to peak day demand. 11
Q. Please explain the basis for the Company’s choice of classification and allocation 12
methods? 13
A. It is widely accepted that distribution mains are installed to meet both system peak period 14
load requirements and to connect customers to the LDC's gas system. Therefore, to ensure 15
that the rate classes that cause the Company to incur this plant investment or expense are 16
charged with its cost, distribution mains should be allocated to the rate classes in proportion 17
to their peak period load requirements and number of customers. 18
There are two cost factors that influence the level of distribution mains facilities 19
installed by an LDC in expanding its gas distribution system. First, the size of the distribution 20
main (i.e., the diameter of the main) is directly influenced by the sum of the peak period gas 21
demands placed on the LDC's gas system by its customers. Secondly, the total installed 22
footage of distribution mains is influenced by the need to expand the distribution system grid 23

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to connect new customers to the system. Therefore, to recognize that these two cost factors 1
influence the level of investment in distribution mains, it is appropriate to allocate such 2
investment based on both peak period demands and the number of customers served by the 3
LDC. 4
Q. Is the method used by the Company to determine a customer cost component of 5
distribution mains a generally accepted technique for determining customer costs? 6
A. Yes. The two most commonly used methods for determining the customer cost component 7
of distribution mains facilities consist of the following: (1) the zero-intercept approach and 8
2) the most commonly installed, minimum-sized unit of plant investment. Under the zero-9
intercept approach, a customer cost component is developed through regression analyses to 10
determine the unit cost associated with a zero-inch diameter distribution main. The method 11
regresses current unit costs associated with the various sized distribution mains installed on 12
the LDC's gas system against the size (diameter squared inches) of the weighted distribution 13
mains installed. The zero-intercept method seeks to identify that portion of plant 14
representing the smallest size pipe required merely to connect any customer to the LDC's 15
distribution system, regardless of the customer’s peak or annual gas consumption. 16
The most commonly installed, minimum-sized unit approach is intended to reflect 17
the engineering considerations associated with installing distribution mains to serve gas 18
customers. That is, the method utilizes actual current installed investment units to determine 19
the minimum distribution system rather than a statistical analysis based upon investment 20
characteristics of the entire distribution system. 21
Two of the more commonly accepted literary references relied upon when preparing 22
embedded cost of service studies, Electric Utility Cost Allocation Manual, by John J. Doran 23

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et al, National Association of Regulatory Utility Commissioners (“NARUC”), and Gas Rate 1
Fundamentals, American Gas Association, both describe minimum system concepts and 2
methods as an appropriate technique for determining the customer component of utility 3
distribution facilities. 4
Clearly, the existence and utilization of a customer component of distribution 5
facilities, specifically for distribution mains, is a fully supportable and commonly used 6
approach in the gas industry. 7
For purposes of determining the customer component of distribution mains to be used 8
in Intermountain’s COSS, the zero-intercept method was employed, the detailed 9
development process of which is presented in Exhibit 2. 10
Q. Was the same method to classify and allocate distribution mains utilized in the 2016 11
Case? 12
A. Yes. The Company used similar classification and allocation methods in its previous general 13
rate case proceeding. 14
Q. How did the COSS classify and allocate the remainder of the distribution plant? 15
A. Special studies were performed for the allocation of Accounts 380 (Services), 381 (Meters), 16
and 385 (Industrial Measuring and Regulating Station Equipment). The costs in account 383 17
(House Regulators) were classified and allocated based upon the results of the meters study. 18
The development steps of these are discussed in Exhibit 2. 19
The plant costs in Account 378 (Measuring and Regulating Station Equipment – 20
General) and Account 379 (Measuring and Regulating Station Equipment – City Gas 21
Stations) were classified as capacity or demand-related and allocated on a customer and peak 22
demand composite allocator. 23

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Account 374 (Land and Land Rights) are associated with distribution mains and 1
therefore, were allocated on the same factor as distribution mains. Account 375 (Structures 2
and Improvements) was allocated based on the allocation of the distribution plant accounts. 3
Q. How did the COSS classify and allocate general plant? 4
A. General Plant was classified and allocated to the rate schedules based upon the allocation of 5
storage, transmission, and distribution plant. Mathematically, this is the sum of storage, 6
transmission, and distribution plant accounts that were allocated by rate class. That total by 7
rate class is then divided by the total company amount to find each rate class’s percentage 8
allocation. Account 391 (Office Furniture and Equipment) was allocated based on the factor 9
derived based on the Company’s labor cost records. 10
Q. How are other rate base components classified and allocated in the COSS? 11
A. Accumulated Provision for Depreciation and Amortization is presented by FERC accounts 12
and allocated based on the same allocation factor as the related plant in service accounts. 13
This treatment ensures that the net plant for each FERC account is allocated consistently to 14
each customer class. Accumulated Deferred Income Taxes are presented on the functional 15
level and allocated based on the relevant internal plant allocator as shown in Exhibit 2. 16
Account 154 (Material and Supplies) was allocated based on the allocation of 17
storage, transmission, and distribution plant. Account 164 (LNG Inventory) balance was 18
allocated based on the peak day factor as the inventory exists to ensure reliability during 19
peak periods. Customer Account 252 (Advances for Construction) was allocated based on 20
the mains and service plant balances. 21

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Q. How are operation and maintenance (“O&M”), customer accounts, customer services 1
and information (“Customer”), and administrative and general (“A&G”) expenses 2
classified and allocated in COSS? 3
A. A utility’s O&M expenses generally are thought to support the corresponding plant in 4
service accounts. In general, O&M expenses are allocated based on the cost allocation 5
methods used for the Company’s corresponding plant accounts. The majority of Customer 6
expenses were classified as customer-related costs and allocated based on the average 7
number of distribution customers by class, except for Account No. 904 (Uncollectible 8
Accounts Expense), which is allocated based upon the three-year average of uncollectible 9
write-offs. A&G expenses were allocated on an account-by-account basis. Items related to 10
labor costs, such as employee pensions and benefits, were allocated based on O&M labor 11
costs. Items related to the plant in service, such as maintenance of the general plant and 12
property taxes, were allocated based on the plant allocator. The detailed classification and 13
allocation methods applied to these expense categories can be found on Schedule 1 of 14
Exhibit 2. 15
Q. Were any additional studies performed in Intermountain’s COSS? 16
A. Yes. Certain categories of gas supply and gas system control related O&M expenses include 17
salaries and benefits of personnel in the following responsibility centers: Gas Supply 18
Resource Planning, Gas Supply, and Gas Control. The corresponding labor expenses were 19
distributed among the three categories of Gas Planning, Gas Supply, and Gas Control based 20
on the time allocations reported by the personnel in these responsibility centers. These 21
expenses were first segregated between sales and transportation classes and then allocated 22
to customer classes as discussed in Exhibit 2. 23

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Q. Please discuss the classification and allocation of the remaining expenses. 1
A. Depreciation and amortization expense is presented on the functional level and allocated 2
based on the relevant internal plant allocator, as demonstrated in Exhibit 2. Taxes other 3
than income are allocated in a manner that reflected the specific cost associated with each 4
tax expense category. Generally, taxes can be cost classified on the basis of the tax 5
assessment method established for each tax category and can be grouped into the following 6
categories: (1) labor; (2) plant; and (3) revenue. In the Intermountain’s COSS, all non-7
income taxes were assigned to one of the above stated categories and relevant allocation 8
factors. 9
Current income taxes were allocated based on each class’s net income before taxes. 10
Income taxes for the total revenue requirement were allocated to each class based on the 11
allocation of the required net income by rate class. Income taxes at proposed revenues by 12
class were allocated to each class based on the proposed income prior to taxes for each 13
class. 14
Q. Please summarize the results of Intermountain’s COSS. 15
A. Table 9 below presents a summary of the results of the Company’s COSS that can be 16
reviewed in detail in Schedule 4 of Exhibit 2. The COSS shows an overall revenue deficiency 17
to the Company of $11.3 million. 18

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Table 9 Summary Results of the COSS

Table 9 presents the revenue deficiency/excess for each rate class, the class rate of return 1
on net rate base at current rates, the revenue to cost ratio, and the associated parity ratio. 2
Regarding rate class revenue levels, the results show that all classes except Residential, are 3
being charged rates that recover more than their indicated costs of service. 4
Q. Please discuss the COSS results prepared based on the peak load study inclusive of the 5
interruptible customer classes. 6
A. An additional COSS analysis was prepared based on the peak load study results inclusive of 7
the interruptible customers, as discussed earlier in the testimony and presented in Table 7. 8
The summary of the COSS results under the alternative peak load allocation study 9
(“Alternative COSS”) is presented in Schedule 7 of Exhibit 2. Table 10 below depicts the 10
results of the Alternative COSS. 11
Customer Classes Current
Revenues Cost to Serve Current Rate
of Return
Deficiency/
(Surplus)
Current
Revenue
to Cost
Ratio
Current
Parity
Ratio
Residential Service 70,391,038$ 88,420,214$ 2.4%18,029,176$ 0.80 0.88
General Service 26,030,361 22,043,765 11.5%(3,986,596) 1.18 1.30
Large Volume 677,926 520,638 13.9%(157,288) 1.30 1.43
Transport Service
(Interruptible)537,118 84,154 236.9%(452,964) 6.27 6.92
Transport Service
(Firm)9,713,387 7,619,006 12.9%(2,094,381) 1.27 1.40
Subtotal 107,349,830$ 118,687,777$ 11,337,947$
Other Revenues 2,450,925 2,450,925 -
Total System 109,800,755$ 121,138,702$ 5.2%11,337,947$ 0.91 1.00

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Table 10 Summary Results of the Alternative COSS

Q. Why are you presenting an Alternative COSS in this proceeding? 1
A. The Transportation Service Interruptible class has a limited presence in the Company’s 2
design day peak for purposes of the IRP. For peak event modeling purposes, the IRP assumes 3
T-3 customers are reduced to minimal emergency plant-heat only.10 As noted earlier in 4
Section IV. Load Study and Analysis, T-3 customers are interruptible, and therefore, have 5
no assurance of the amount of capacity that they may be granted on any given peak day. 6
However, given that Intermountain has rarely interrupted these customers, it is reasonable 7
to provide a level of demand as their contribution to the system peak for purposes of the 8
COSS. The alternative COSS is intended to demonstrate the impact particularly on the 9
Transportation Interruptible class by their inclusion at a 100% load factor demand level in 10
the allocation of system demand related costs. 11
Q. How do the COSS results compare to the alternative method that is based on the peak 12
load study inclusive of the interruptible customer classes? 13
A. Table 11 below provides a comparison between the two options. As expected under the 14
Alternative COSS method Transportation Service Interruptible Class shows an increase in 15

10 Ibid, at pg. 39.
Customer Classes Current
Revenues Cost to Serve Current Rate
of Return
Deficiency/
(Surplus)
Current
Revenue
to Cost
Ratio
Current
Parity
Ratio
Residential Service 70,391,038$ 88,171,773$ 2.5%17,780,735$ 0.80 0.89
General Service 26,030,361 21,935,558 11.6%(4,094,803) 1.18 1.31
Large Volume 677,926 514,914 14.3%(163,012) 1.31 1.45
Transport Service
(Interruptible)537,118 560,802 6.7%23,684 0.96 1.06
Transport Service
(Firm)9,713,387 7,504,730 13.3%(2,208,657) 1.29 1.42
Subtotal 107,349,830$ 118,687,777$ 11,337,947$
Other Revenues 2,450,925 2,450,925 -
Total System 109,800,755$ 121,138,702$ 5.2%11,337,947$ 0.91 1.00

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cost to serve. However, the resulting class revenue to cost ratio (“R:C”) of .96 remains above 1
the system R:C ratio of .91, compared to the 6.27 R:C level when no system demand 2
contribution is attributable to the class. 3
Table 11 Comparison of COSS Results under Proposed and Alternative Methods

VI. PRINCIPLES OF SOUND RATE DESIGN
Q. Please identify the principles of rate design utilized in development of the Company’s 4
rate design proposals. 5
A. Several rate design principles find broad acceptance in the recognized literature on utility 6
ratemaking and regulatory policy. These principles include: 7
(1) Cost of Service; 8
(2) Efficiency; 9
(3) Value of Service; 10
(4) Stability/Gradualism; 11
(5) Non-Discrimination; 12
(6) Administrative Simplicity; and 13
(7) Balanced Budget. 14
Customer Classes Cost to Serve Cost to Serve
(Alternative)Difference Revenue to
Cost Ratio
Revenue to
Cost Ratio
(Alternative)
Residential Service 88,420,214$ 88,171,773$ 248,441$ 0.80 0.80
General Service 22,043,765 21,935,558 108,207 1.18 1.18
Large Volume 520,638 514,914 5,724 1.30 1.31
Transport Service
(Interruptible)84,154 560,802 (476,648) 6.27 0.96
Transport Service
(Firm)7,619,006 7,504,730 114,276 1.27 1.29
Subtotal 118,687,777$ 118,687,777$ -$
Other Revenues 2,450,925 2,450,925 -
Total System 121,138,702$ 121,138,702$ -$ 0.91 0.91

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These rate design principles draw heavily upon the “Attributes of a Sound Rate Structure” 1
developed by James Bonbright in Principles of Public Utility Rates.11 2
Q. Can the objectives inherent in these principles compete with each other at times? 3
A. Yes. These principles can compete with each other, and this tension requires further 4
judgment to strike the right balance between the principles. Detailed evaluation of rate 5
design recommendations must recognize the potential and actual tension between these 6
principles. Indeed, Bonbright discusses this tension in detail. Rate design recommendations 7
must deal effectively with such tension. There are tensions between cost and value of 8
service principles as well as efficiency and simplicity. There are potential conflicts between 9
simplicity and non-discrimination and between value of service and non-discrimination. 10
Other potential conflicts arise where utilities face unique circumstances that must be 11
considered as part of the rate design process. 12
Q. How are these principles translated into the design of rates? 13
A. The overall rate design process, which includes both the apportionment of the revenues to 14
be recovered among rate classes and the determination of rate structures within rate 15
classes, consists of finding a reasonable balance between the above-described criteria or 16
guidelines that relate to the design of utility rates. Economic, regulatory, historical, and 17
social factors all enter the process. In other words, both quantitative and qualitative 18

11 Principles of Public Utility Rates, Second Edition, Page 111-113 James C. Bonbright, Albert L. Danielson, David
R. Kamerschen, Public Utility Reports, Inc., 1988.

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R. AMEN, DI
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information is evaluated before reaching a final rate design determination. Out of necessity 1
then, the rate design process must be, in part, influenced by judgmental evaluations. 2
VII. DETERMINATION OF PROPOSED CLASS REVENUES
Q. Please describe the approach generally followed to allocate Intermountain’s proposed 3
revenue increase of $11.3 million to its rate schedules. 4
A. The apportionment of revenues among rate schedules consists of deriving a reasonable 5
balance between various criteria or guidelines that relate to the design of utility rates. The 6
various criteria that were considered in the process included: (1) cost of service; (2) rate 7
schedule contribution to present revenue levels; and (3) customer impact considerations. These 8
criteria were evaluated for Intermountain’s rate schedules. 9
Q. Have various rate schedule revenue options been considered in conjunction with your 10
evaluation and determination of Intermountain’s interclass revenue proposal? 11
A. Yes. Using Intermountain’s proposed revenue increase, and the results of its COSS, a few 12
options were evaluated for the assignment of that increase among its rate schedules and, in 13
conjunction with Intermountain personnel and management, ultimately decided upon one of 14
those options as the preferred resolution of the interclass revenue issue. The benchmark 15
option that was evaluated under Intermountain’s proposed total revenue level was to adjust 16
the revenue level for each rate schedule so that the R:C ratio for each class was equal to 17
parity or 1.00 (Unity), as shown in Exhibit 3, under Scenario A: Revenues at Equalized Rates 18
of Return. Rate schedules above parity would suggest the need for revenue decreases in order 19
to move them closer to cost (i.e., a convergence of the resulting revenue-to-cost ratios 20
towards unity or 1.00). 21

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The resulting customer impact implications for the Residential Service class have led 1
to the conclusion, in consultation with the Company, to refrain from revenue reductions for 2
the remaining customer classes. From a policy perspective, Intermountain believed that 3
every rate schedule should participate in the proposed overall revenue increase. Therefore, 4
as a matter of judgment, it was decided that this fully cost-based option was not the preferred 5
solution to the interclass revenue question. It should be pointed out, however, that those class 6
revenue results represented an important guide for purposes of evaluating subsequent rate 7
design options from a cost of service perspective. 8
A second option considered was assigning the increase in revenues to 9
Intermountain’s rate schedules based on an equal percentage basis of its current margin 10
revenues (see Scenario B, Equal Percentage Increase), in Exhibit 3. By definition, this 11
option resulted in each rate schedule receiving an increase in revenues equal to the system 12
average. However, when this option was evaluated against the COSS Study results (as 13
measured by changes in the revenue-to-cost ratio for each customer class); there was no 14
movement towards cost for most of Intermountain’s rate schedules (i.e., there was no 15
convergence of the resulting revenue-to-cost ratios towards unity or 1.00). While this option 16
was not the preferred solution to the interclass revenue issue, together with the fully cost-17
based option, it defined a range of results that provides further guidance to develop 18
Intermountain’s class revenue proposal. 19
A third option considered was moderately assigning the increase in revenues to all 20
Intermountain’s rate schedules (Scenario C: Moderated based on Current Parity Ratio), 21
which is the proposed revenue allocation method in this proceeding. 22
Q. What was the result of this process? 23

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A. The various criteria that were considered in the process included: (1) cost of service; (2) 1
class contribution to present revenue levels; and (3) customer impact considerations. After 2
further discussions with Intermountain, the conclusion reached was the appropriate 3
interclass revenue proposal would consist of adjustments, in varying proportions, to the 4
present revenue levels in all of Intermountain’s rate schedules. 5
The Residential margin revenue increase was limited to 13.20% or 1.25 of the 6
relative system increase (10.56%). The minimum increase was applied to the Interruptible 7
Transport of 0.25 of the relative system increase, which resulted in 2.64% of margin revenue 8
increase. The remainder of the margin revenue increase was allocated among General 9
Service, Large Volume, and Firm Transport rate schedules, which resulted in an 5.58% 10
margin revenue increase or 0.53 of the relative system increase. This revenue apportion is 11
shown in Direct Exhibit 3 as Proposed Scenario C: Moderated based on the Current Parity 12
Ratio. 13
Q. What is the recommended increase for each rate class? 14
A. In summary, this preferred revenue allocation approach resulted in reasonable movement of 15
the customer classes’ revenue-to-cost ratio toward unity as shown on Table 12 below, while 16
providing moderation of the revenue impact by requiring some level of revenue increase 17
responsibility from all rate schedules for the Company’s total proposed revenue requirement. 18

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Table 12 Current and Proposed Parity Ratios

From a class cost of service standpoint, this type of rate schedule movement, and modest 1
reduction in the existing class rate subsidies, is desirable. 2
The following Table 13 summarizes the proposed distribution margin revenue 3
change for each rate class and the percent change in distribution margin revenues resulting 4
from the above-described process. 5
Table 13 Proposed Class Revenue Apportionment

6
Customer Classes Current Parity
Ratio
Proposed Parity
Ratio
Residential Service 0.88 0.90
General Service 1.30 1.24
Large Volume 1.43 1.37
Transport Service
(Interruptible)6.92 6.44
Transport Service
(Firm)1.40 1.34
Total System 1.00 1.00
Customer Classes
Margin
Revenues at
Current Rates
Margin
Revenues at
Proposed Rates
Proposed
Revenue
Change
Percent
Change
Increase
Relative to
System
Increase
Proposed
Parity
Ratio
Residential Service 70,391,038$ 79,684,135$ 9,293,097$ 13.20%1.25 0.90
General Service 26,030,361 27,481,668 1,451,307 5.58%0.53 1.24
Large Volume 677,926 715,723 37,797 5.58%0.53 1.37
Transport Service
(Interruptible)537,118 551,300 14,182 2.64%0.25 6.44
Transport Service
(Firm)9,713,387 10,254,951 541,564 5.58%0.53 1.34
Subtotal 107,349,830$ 118,687,777$ 11,337,947$ 10.56%1.00
Other Revenues 2,450,925 2,450,925 - -
Total System 109,800,755$ 121,138,702$ 11,337,947$ 10.33%1.00

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VIII. INTERMOUNTAIN’S RATE DESIGN
Q. Please summarize the rate design changes Intermountain has proposed in this rate 1
proceeding. 2
A. The proposed rate design includes (1) increases in the fixed monthly customer charges for 3
Residential and General Service classes, (2) increases in demand rates to Large Volume 4
and Firm Transport classes, (3) introduction of fixed monthly customer charges to Large 5
Volume, Interruptible Transport, and Firm Transport classes, and (4) modification of the 6
declining block rates for the Large Volume class. Once the fixed monthly customer charge 7
targets and demand rates were set for each rate class, the remaining proposed revenues for 8
each rate class were recovered through the volumetric charges. 9
Q. Please describe the changes to the monthly customer charge levels. 10
A. Table 14 provides a summary of current and proposed customer charges by rate schedule 11
as compared to the COSS results: 12
Table 14 Current and Proposed Customer Charge

Overall, the proposed customer charges are within reasonable range of increases 13
considering the customer unit costs per rate class supported by the COSS results, as indicated 14
on Schedule 6 of Exhibit 2. These increases to the basic customer charges will provide 15
significant improvement in the recovery of the fixed customer-related costs via fixed 16
Rate Classes
Current
Customer
Charge
COSS Unit Cost
Proposed
Customer
Charge
Change Percent
Change
Residential Service 5.50$ 12.60$ 9.00$ 3.50$ 63.64%
Residential Service (Interruptible)5.50$ 12.60$ 8.00$ 2.50$ 45.45%
General Service 9.50$ 33.65$ 15.00$ 5.50$ 57.89%
General Service (Interruptible)9.50$ 33.65$ 12.50$ 3.00$ 31.58%
Large Volume -$ 500.03$ 150.00$ 150.00$ -
Transport Service
(Firm)-$ 1,063.73$ 150.00$ 150.00$ -
Transport Service
(Interruptible)-$ 1,018.02$ 300.00$ 300.00$ -

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charges. To offset the foregoing increases to the basic customer charges, all blocks of the 1
volumetric rates in the respective tariff schedules were reduced ratably based on the margin 2
revenue in each block, with one exception. The block structure of the Large Volume Firm 3
Sales Service tariff was changed, which is discussed later in this section. 4
Q. Why is the Company proposing to increase the fixed monthly customer charges? 5
A. The primary goal of rate design was to move towards recovery of fixed costs by increasing 6
all customer charges. This resulted in better alignment between the fixed costs incurred by 7
Intermountain and the charges incurred by customers. 8
Q. Please describe the changes proposed to the demand rate. 9
A. The current demand charge in Large Volume and Firm Transportation classes of $0.30 per 10
therms per month is proposed to be raised to $0.32, which will recover approximately 90% 11
of the unit demand-related costs for these customer classes. 12
Q. What changes do you propose to the Large Volume block rate structure? 13
A. Under Intermountain’s current tariff, any new customer under Large Volume Firm Sales 14
Service (Tariff Sheet No. 7) is required not to exceed usage of 500,000 therms annually, 15
while the current block rate is structured as follows: 16
 Block 1 - First 250,000 therms per bill 17
 Block 2 - Next 500,000 therms per bill 18
 Block 3 - Over 750,000 therms per bill 19
Under this scenario, customers are unable to benefit from the declining block rates. By 20
reviewing historical usage patterns, a new block structure was developed as follows: 21
 Block 1 - First 35,000 therms per bill 22
 Block 2 - Next 35,000 therms per bill 23

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 Block 3 - Over 70,000 therms per bill 1
Q. Have you provided an exhibit detailing the proposed rates and corresponding 2
revenues? 3
A. Yes. Exhibit 4 shows the derivation of each rate component for each of Intermountain’s 4
tariff schedules and the corresponding revenues generated from those proposed rates. 5
Q. Have you prepared bill impacts? 6
A. Yes. Exhibit 5 provides monthly bill impacts for Residential, General, and Interruptible 7
Transportation rate classes presented as a range of monthly usage (therms) and 8
corresponding bills under current and proposed rates. The bill impacts for Large Volume and 9
Firm Transportation customers are presented as various scenarios of monthly usage and 10
MDFQ with corresponding bills under current and proposed rates. 11
IX. CONCLUDING REMARKS
Q. Please summarize your recommendations. 12
For purposes of Intermountain’s allocated class cost of service study, the Load Study results 13
which use the Monthly peak load sendout model to determine the Core peak day sendout are 14
recommended. It provides superior results in predicting peak day sendout. These results are 15
aligned with Intermountain’s projections of peak day sendout in its 2021-2026 IRP. 16
I recommend the Commission accept the COSS presented in Section VI of this 17
testimony, including the proposed class revenue apportionment. The COSS represents a fair 18
and reasonable allocation of cost responsibility for each rate class, based on the Company’s 19
proposed total system revenue increase. The Company’s proposed COSS allocation method 20
for distribution mains best reflects the cost causative characteristics of extending service to 21

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new customers and sized to meet peak demand requirements. As such, the Commission 1
should rely on the Company’s proposed COSS to guide revenue targets for each rate class. 2
The revenue targets proposed by Intermountain reasonably balance the concepts of 3
cost of service, current revenue contributions, and gradualism, while moving all classes 4
closer to parity. Lastly, the COSS model demonstrates that fixed costs, both customer-related 5
and demand-related are materially higher than the current level of customer charges; 6
therefore, the proposed increases to customer charges should be approved by the 7
Commission to better align fixed cost occurrence with fixed cost recovery and price signals 8
received by customers. 9
Q. Does this conclude your testimony? 10
A. Yes, although I reserve the right to supplement or amend my testimony before or during the 11
Commission’s hearing in this proceeding. 12
Preston N. Carter ISB No. 8462
Morgan D. Goodin ISB No. 11184
Blake W. Ringer ISB No. 11223
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
[e-mail]
Attorneys for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF INTERMOUNTAIN GAS COMPANY.
FOR AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR NATURAL
GAS SERVICE IN THE STATE OF IDAHO
CASE NO. INT-G-22-07
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
EXHIBIT 1 TO ACCOMPANY THE
DIRECT TESTIMONY OF RONALD J. AMEN

Page | 1
Ronald J. Amen
Managing Partner
Mr. Amen has over 40 years of combined experience in utility management and consulting in the areas of regulatory support, resource planning, organizational development, distribution
operations and customer service, marketing, and systems
administration.
He has advised gas, electric and water utility clients in the following areas: regulatory policy, strategy and analysis; cost of service studies (embedded and marginal cost analyses); rate
design and pricing issues including time- of-use rates, revenue
decoupling, weather normalization and other cost tracking mechanisms; resource strategy, planning and financial analysis; and business process design, evaluation and organizational structures. Mr. Amen has provided expert testimony in numerous
state and provincial regulatory agencies, and the Federal Energy
Regulatory Commission. Prior to establishing Atrium Economics in 2020, Mr. Amen’s consulting experience included Director Advisory & Planning at Black & Veatch Management Consulting, LLC, Vice President of Concentric Energy Advisors,
Inc. and Director with Navigant Consulting, Inc. His prior utility
experience includes leadership of State and Federal Regulatory Affairs at two electric and gas utilities, and management positions in Regulatory Affairs, Information Systems and Distribution Operations.

REPRESENTATIVE PROJECT EXPERIENCE
Regulatory Policy, Strategy and Analysis
Western Export Group (2019)
In a Nova Gas Transmission, LTD. (NGTL) Rate Design and Service Application before the
Canada Energy Regulator (CER), Mr. Amen led a consulting team supporting the interests of the
Western Export Group, a group of nine utility companies located in the Western U.S. and British
Columbia who are export shippers on the NGTL system. The case resulted in a settlement with all
parties.
Regulatory Commission of Alaska (2019 – 2020)
Part of a multi-functional team that assisted the Regulatory Commission of Alaska (RCA) in its
evaluation of the Chugach Electric Association, Inc’s acquisition of the Municipal of Anchorage
EDUCATION
University of Nebraska,
Bachelor of Science with
Distinction, Business
Administration, Finance
and Economics
YEARS EXPERIENCE
42
PROFESSIONAL ASSOCIATIONS
American Gas Association
Southern Gas Association
RELEVANT EXPERTISE
Financial Analysis; Litigation
Support; Regulatory Support;
Strategy; Utility Operations
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d/b/a Municipal Light & Power Department. Assisted the RCA with its evaluation of the long-
term benefits of the transaction to ML&P and Chugach customers, the implication of terms and
assumptions in various agreements, and the careful balance of the fiscal and regulatory
implications for the customers of the combined entity.
CPS Energy (2017 – 2018)
Provided an overall review of the client’s Strategic Roadmap to prioritize its multi-year regulatory
initiatives. (e.g., changes in product and service offerings, restructuring of current rate classes,
introduction of new rate structures, rate levels, and tariff provisions). Current pricing processes
and platforms assessed to identify recommended enhancements to enable the development and
implementation of dynamic pricing concepts. Assisted client with preparation of next rate case
(e.g., costing and pricing analyses, load forecasting, internal communications, and stakeholder
engagement).
FortisBC Energy, Inc. (2016 – 2018, 2021)
Performed an overall review of the client’s Transportation Service Model. Analyzed the client’s
various midstream transportation and storage capacity resources used in providing balancing of
transportation customers’ loads. Review included the physical diversity, functionality and
flexibility provided by the various capacity resources, and the cost impact caused by transportation
customers’ imbalance levels. Conducted an industry-wide benchmarking study of current industry-
wide best practices, by regulatory jurisdiction, related to transportation balancing tariff provisions.
Participated in stakeholder workshops and testified before the BCUC. Retained in 2021 to update
quantitative analysis of the operation of the transportation balancing rules for reporting
requirements of the BCUC in 2022.
McDowell Rackner & Gibson Law Firm (2015 – 2016)
Provided due diligence services to the law firm in connection with a state utility commission
investigation into the law firm client’s gas storage and optimization activities. Provided an
independent opinion as to the likely outcome of the Commission’s ongoing investigation.
Gulfport Energy Corporation (2016)
Provided regulatory analysis and support to Gulfport Energy Corporation in the ANR Pipeline
Company Natural Gas Act §4 rate proceeding before the Federal Energy Regulatory Commission
(FERC). Analyzed as-filed cost of service and rate design to identify key cost of service, cost
allocation, rate design and service related/tariff issues. Developed an integrated cost of service and
rate design model to prepare studies on client issues. Prepared best/worst case litigation outcomes,
discovery and evaluations of discovery of other parties. Analyzed FERC staff top sheets and
settlement offers; and assisted in the preparation of settlement positions.
Confidential Financial / Energy Partners (2015)
Provided regulatory due diligence support for client related to a proposed merger with a
multijurisdictional gas/electric company including an evaluation of the regulatory landscape in the
various applicable state jurisdictions, recent regulatory decisions, and current regulatory issues.

Case No. INT-G-22-07
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Confidential International Energy Company (2014)
Provided regulatory due diligence support for client related to a proposed merger with a
multijurisdictional gas company including an evaluation of the regulatory landscape in the various
applicable state jurisdictions, recent regulatory decisions, and current regulatory issues.
Pacific Gas & Electric Company (2014)
Developed an extensive industrywide benchmarking study to determine the cost allocation and
ratemaking treatment utilized by Local Distribution Companies (LDCs) in the United States for
recovery of gas transmission costs. Benchmarked cost allocation and rate design utilized by
Interstate/Intrastate Pipelines. Benchmarked how Industrial & Electric Generation customers are
served with natural gas.
Public Service Company of New Mexico (2009-2010)
Provided case management, revenue requirement, cost of service and rate design support for
general rate cases in the utility’s two state regulatory jurisdictions. Issue management and policy
development included an electric fuel and purchased power cost mechanism, recovery of
environmental remediation costs for a coal fired power plant, and the valuation of renewable
energy credits related to a wind power facility.
Confidential International Energy Company (2009)
Provided due diligence on behalf of client related to the purchase of a gas/electric utility, including
a review of the regulatory and market-related assumptions underlying the client’s valuation model,
resulting in the validation of the model and identification of key business risks and opportunities.
Resource Planning, Strategy and Financial Analysis
Confidential Multi-Jurisdiction Gas Utility (2021-2022)
Retained by the multi-jurisdiction interstate transmission pipeline and local distribution utility
(“client”) to assist it in identifying and supporting a natural gas supply solution to satisfy additional
deliverability requirements with the goals of minimizing costs, enhancing system resiliency, and
introducing renewable fuels into its system. Reviewed the process and analyses that had been
conducted to-date (including all underlying assumptions) and provided insight on the best path
forward. The goal of the effort was to help prepare client for internal approval of the process and
recommended path forward, and ultimately the development and approval of the necessary
regulatory filings at the federal, state, and local levels. Atrium evaluated a broad spectrum of
regulatory, economic, market-related, and logistical considerations in order to advise the client on
the best path forward in utilizing LNG to meet its future deliverability requirements. Specific
components of Atrium’s analysis included regulatory approvability, rate design and cost recovery
risk, site location (including siting LNG in multiple locations in multiple states), ownership
structure, and ability to incorporate RNG and hydrogen into Utility’s system to decarbonize the
pipeline system.
Case No. INT-G-22-07
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Exhibit No. 1
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Great Plains Natural Gas (2021-2022)
Retained to review the gas supply procurement practices and objectives of Great Plains, the
interstate pipeline, storage and supply contracts, and other information available to Great Plains
leading up to and throughout the severe weather event that occurred from February 13-17, 2021,
and the actions by Great Plains personnel in response to the weather event, as part of a state-wide
investigation by the Minnesota Public Utilities Commission. Expert testimony filed on behalf of
Great Plains.
Fortis BC Energy, Inc. (2011, 2021)
Retained to help develop a gas supply incentive mechanism in cooperation with the British
Columbia Utilities Commission staff and the company’s other stakeholders. Provided an
independent analysis of the utility’s management of pipeline and storage capacity and supply. Part
of this work entailed a review of the major markets in which the utility transacted, reviewing the
size of trading activity at the major market hubs and reviewing the price indices for these markets.
In 2021, retained to refresh all quantitative analysis of the operation of the GSMIP for reporting
requirements of the BCUC in 2022.
Black Hills Colorado Electric Utility (2009)
Engaged as a member of a consultant team that served as the independent evaluator in a
competitive solicitation for non-intermittent generation resources. Jointly recommended by the
utility client, the staff of the utility commission and the state attorney general, the consulting team
acted as an agent of the public utility commission monitoring and overseeing the solicitation,
which included reviewing the request for proposals and solicitation process, including provisions
of the power purchase agreement, preliminary review (economic and contractual) of bids received
from the request for proposals, initial modeling of bids for screening, selection of bidders with
whom to conduct negotiations and oversight of the negotiation process, and the ultimate selection
of the winning bid. Provided due diligence review of all input data, preliminary and final model
output, and output summaries. The team produced biweekly confidential reports to the
commission regarding the process and its results.
NW Natural (2007-2008)
Assisted with the development of its long-term Integrated Resource Plan (IRP) for its Oregon and
Washington service territories. The IRP included the evaluation of incremental inter- and intra-
state pipeline capacity, underground storage, and two proposed LNG plants under development in
the region.
Puget Sound Energy (2007)
Engaged to assist the client with the development of a natural gas resource efficiency and direct
end-use strategy, an interdepartmental initiative focused on preparing a natural gas resource
efficiency plan that optimizes customers’ end-use energy consumption while furthering corporate
customer, financial, environmental, and social responsibilities.
Case No. INT-G-22-07
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Puget Sound Energy (2002 – 2003)
Provided resource planning strategy and analysis for the company’s Least Cost Plan, including a
review of the company’s underlying 20-year electric and gas demand forecasts. As a member of a
consulting team, served as the client’s financial advisor for the acquisition of new electric power
supply resources. Conducted a multitrack solicitation process for evaluation of generation assets
and purchase power agreements. Provided regulatory support for the acquisition.
Cost Allocation, Pricing Issues and Rate Design
Summit Natural Gas of Maine, Inc. (2022)
Mr. Amen provided revenue requirement, allocated cost of service, class revenue apportionment,
rate design, and expert witness support for the utility’s gas general rate case before the Maine
Public Utilities Commission. The case is currently pending before the Maine PUC.
Black Hills Energy Arkansas (2021-2022)
Mr. Amen provided allocated cost of service, class revenue apportionment, rate design for natural
gas infrastructure mechanisms, and expert witness support for the utility’s gas general rate case
before the Arkansas Public Service Commission. The case resulted in a settlement before the
Arkansas PSC.
Until Electric System and Northern Utilities, Inc. (2021)
Mr. Amen provided allocated cost of service, marginal cost of service, class revenue
apportionment, rate design, and expert witness support for the utility’s separate electric and gas
general rate cases before the New Hampshire Public Utilities Commission, including expert
witness testimony. The cases resulted in settlements before the NHPUC.
Manitoba Hydro – Centra Gas Manitoba (2021-2022)
Retained to provide an independent review of the cost of service methodologies employed for
Centra Gas Manitoba Inc.’s natural gas operations. Atrium prepared a report filed with the
Manitoba Public Utility Board documenting and supporting our assessment of Centra’s existing
COSS methods in conformance with the regulatory requirements of the MPUB. Focusing on the
trends of Canadian gas distribution utilities, the COSS method utilized in the current COSS was
reviewed against the: (1) cost causative factors identified for each plant and expense element of
Centra’s total cost of service; and (2) the current range of regulatory practices observed in the
North American gas utility market. Centra’s 2022 rate application based on the recommendations
in our report was approved by the MPUB.
Montana-Dakota Utilities and Great Plains Natural Gas (2020 – 2021, 2022)
Mr. Amen provided cost of service, class revenue apportionment, rate design, and expert witness
support for the gas utilities’ general rate cases before the Montana Public Service Commission and
North Dakota Public Service Commission. Testimony included theoretical principals and practical
application of cost allocation, and rate design principles or objectives that have broad acceptance
in utility regulatory and policy literature. Supported the Straight Fixed-Variable Rate Design
(SFV) in North Dakota with analysis showing low-income residential customers would experience
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lower annual bills under the SFV rate design than a volumetric weighted rate design. Provided a
presentation at a public input hearing and oral testimony at Commission hearings in both
jurisdictions. SFV rate design was approved by the North Dakota PSC. Mr. Amen provided
electric cost of service, class revenue apportionment, rate design, and expert witness support in
Montana-Dakota’s 2022 general rate case before the North Dakota PSC. The case is pending.
Chesapeake Utilities Corporation (2020 – 2021)
Reviewed and evaluated Chesapeake’s Swing Service Rider (SSR), which recovers intrastate
pipeline capacity costs directly from all transportation customers, and the application of the
current cost allocation methodology underlying the service for its Florida gas utilities, Central
Florida Gas and Florida Public Utilities. Supported Chesapeake through three primary tasks; (1)
Assessment of the factors influencing the current cost allocation method, its impact on various
customer groups, and data collection, (2) Assessment of the appropriateness of alternative cost
allocation methods and model the application to and impact on the SSR charges, and (3) Provided
a report of the evaluation, modelling results and recommendations in a report and conducted a
review session with Chesapeake management personnel.
Kansas City, KS Board of Public Utilities (2019 – 2020)
Provided expert witness testimony supporting the basis for a Green Energy Program, its objectives
and overall benefits. Provide an assessment of how the program is aligned with best practices in
design of Green Energy tariff programs nationally. Testimony also provided an assessment of
how the program mitigates potential risks the to the Board of Public Utilities and protects against
subsidization of other rate classes.
NW Natural (2018 – 2019)
Provided cost of service, class revenue apportionment, rate design, and expert witness support for
the gas utility’s general rate case before the Washington Utility and Transportation Commission
(WUTC), filed in December 2018. Testimony included theoretical principals and practical
application of cost allocation, and rate design principles or objectives that have broad acceptance
in utility regulatory and policy literature.
Chesapeake Utilities Corporation (2018 – 2019)
Developed a Weather Normalization Adjustment (WNA) mechanism applicable to the monthly
billings of Chesapeake’s residential and general service customers. Sponsored the WNA
mechanism through expert testimony filed with the Delaware Public Service Commission in
January 2019. The testimony included a description of the WNA calculations; back-casting
performance analyses, with bill impacts; a WNA tariff; and conceptual and evidentiary support for
this ratemaking mechanism.
Louisville Gas & Electric Company and Kentucky Utilities Company (2018)
Engaged by LG&E and KU to a conduct a study in support of a joint utility and stakeholder
collaborative concerning economical deployment of electric bus infrastructure by the transit
authorities in the Louisville and Lexington KY areas, as well as possible cost-based rate structures
related to charging stations and other infrastructure needed for electric buses.
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Summit Utilities – Colorado Natural Gas, Inc. (2018)
Engaged by Summit Utilities to develop and support with expert testimony an appropriate normal
weather period for the client’s five Colorado temperature zones, resulting normalized billing
determinants, and a Weather Normalization Adjustment (“WNA”) proposal in conjunction with
the filing of a general rate case for its Colorado Natural Gas , Inc. subsidiary.
Westar Energy (2018)
Provided cost of service and expert witness support for the electric utility’s general rate case filing
before the Kansas Corporation Commission (KCC). The cost of service study determined the cost
components for a new Residential Distributed Generation (DG) customer class that provided the
basis for recommendations for establishing components of a sound, modern three-part rate design
for this new Residential DG (roof-top solar) service, which was approved by the KCC.
Florida Public Utilities (Chesapeake Utilities) (2017 – 2018)
Provided a rate stratification study of the utility’s commercial and industrial customer classes to
facilitate the reconfiguration of the classes by size of service facilities, annual volume, and load
factor. Reviewed the cost allocation bases and recommended alternatives for recovery of capital
investments related to the utility’s Gas Reliability Investment Program (GRIP).
Tacoma Power (2016 – 2018, 2022)
Provided cost of service and rate design support for the electric utility’s general rate case filings,
including support for recovery of fixed costs through fixed charges and impacts on low income
customers. Provided recommendations as to specifications in the client’s cost of service analysis
(COSA) model for deriving Open Access Transmission Tariff rates, using FERC approved
standards to guide the evaluation. Conducted an electric utility costing and pricing workshop for
the PUB in October 2017; and participated with Tacoma Utilities staff in a comprehensive electric
and water Rates and Financial Planning workshop in February 2018. Engagement was extended
for the 2019 – 2020 rate filing, which incorporated the Black & Veatch municipal COSA model
for costing and ratemaking purposes. Currently providing cost of service and rate design for the
2023 – 2024 rate filing. Future project work involves innovative rate programs.
Tacoma Power (2017)
Engaged to review and assess current rates for 3rd Party Pole Attachments (PA), and more
specifically, to determine and recommend if any rate adjustments were needed. Performed several
tasks:
• Performed a market survey of rates charged by comparable utilities
• Reviewed current regulations on rate setting and practice for 3rd Party Pole
Attachments as set forth by the Federal Communications Commission (FCC) and
the State of Washington (WA), and the interpretation of such regulations in court
decisions
• Reviewed industry best practices under the FCC, WA, and the American Public
Power Association (APPA)
• Collected and reviewed data for cost-based fees including:
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• Application Fees
• Non-Compliance Fees
• Reviewed cost data supplied by the City of Tacoma as relates to determining pole
costs, and
• Performed modeling of rates under the FCC Model, the APPA model and the State
of Washington shared model (50 % FCC Rate/ 50% APPA Rate).
BC Hydro (2016)
Provided research and analysis of the line extension policies of a select group of peer utilities in
Canada with similar regulatory regimes as well as U.S. utilities based on their geographic
relationship to the client. Conducted interviews with peer utilities to gather comparative
information regarding their line extension policies and related internal procedures. Performed a
comparative analysis of the various line extension policies from the selected peer group.
Cascade Natural Gas Corporation (2015 – 2019)
Provided cost of service and rate design support for several of the company’s general rate case
filings in its two state jurisdictions, 3 in Oregon and 2 in Washington. Conducted Long-run
Incremental Cost Studies in the Oregon jurisdiction and embedded class allocated cost of service
studies in the Washington jurisdiction. Performed benchmark analyses to compare each of the
client’s administrative and general (A&G) and operations and management (O&M) expenses, on a
per-customer basis, to various peer groups. Analyses were performed for natural gas utilities and
combination utilities with both electric and gas operations. Various iterations of the analyses were
prepared to make the peer group of utilities more comparable to the characteristics of the client’s
utility operations. Represented the client’s interests in a Washington generic rulemaking
proceeding on the subject of electric and gas cost of service methodologies and minimum filing
requirements.
Chesapeake Utilities (2015 – 2016)
For its Delaware jurisdiction, provided cost of service and rate design support in the client’s
general rate case proceeding, including expert witness testimony in support of the utility’s
proposed gas revenue decoupling mechanism.
Homer Electric Association / Alaska Electric and Energy Cooperatives (2015)
Represented clients in an ENSTAR gas general rate proceeding. Testimony discussed accepted
industry principles of revenue allocation and rate design, including the applicability to and
alignment with ENSTAR’s revenue allocation and rate design proposals for large power and
industrial customers. Provided a critique of certain methodological aspects of ENSTAR’s Cost of
Service study, proposed revenue allocation, and rate design relating to the various large power and
industrial customers.
Arkansas Oklahoma Gas Corporation (2002, 2003, 2004, 2007, 2012, 2013)
Provided cost of service and rate design support for several of the company’s general rate case
filings in its two state jurisdictions and in support of Section 311 transportation filings (2007,
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2010) before the Federal Energy Regulatory Commission. Provided related research, design and
expert witness testimony in support of a Revenue Decoupling mechanism in one jurisdiction and a
Weather Normalization Adjustment mechanism in the other jurisdiction, along with a significant
increase in fixed charges and the introduction of demand charges for the company’s largest
customer classes. Conducted a pre-filing “decoupling” workshop for the utility commission staff.
Northern Indiana Public Service Company (NiSource) (2009 – 2010, 2013, 2017, 2021)
Conducted class allocated cost of service studies for the client’s natural gas (including two other
affiliate gas utilities) and electric operations. Work included reconfiguring the Company’s
commercial and industrial customer classes according to size of load and customer-related
facilities. Rate design was modernized to recover a greater portion of fixed costs via fixed monthly
customer and demand-based charges, a transition to a “Straight-Fixed Variable” form of rate
design. Industry research was provided on alternative rate designs for the electric service,
including Time-of-Use rates and Critical Peak Pricing. Served as an expert witness on behalf of
the client in five general rate cases before the Indiana Utility Regulatory Commission. The 2021
rate case is currently pending before the IURC.
Southwestern Public Service Company (Xcel) (2012)
Retained to conduct a study to estimate the conservation effect of replacing its existing electric
residential rate design with an alternative rate design such as an inverted block rate design.
Reviewed inclining block rate structures that have actively been employed in other jurisdictions
and also reviewed technical and academic literature to assess the elasticity of electricity demand
for residential customers in the southwestern U.S. Analyzed 2009-2011 residential data to
determine what sort of conservation effect the company may expect by implementing an inclining
block rate structure. Provided an overview of alternative rate structures which may also promote
conservation effects, such as seasonal rates, three-part rates and time-of-use (TOU) rates, and
considered the competing incentives of promoting conservation and cost recovery, without
specific rate mechanisms to address this conflict.
Atlantic Wallboard LP and Flakeboard Company Limited (JD Irving) (2012)
Represented clients in an Enbridge Gas New Brunswick Limited Partnership (“EGNB”) general
rate proceeding. Testimony responded to the 2012 allocated cost of service study and rate design
that was submitted to the New Brunswick Energy and Utilities Board by EGNB. Testimony also
provided benchmark information regarding EGNB’s distribution pipeline infrastructure in New
Brunswick. CA.
Western Massachusetts Electric Company (Northeast Utilities) (2010 – 2011)
Supported utility in its decoupling proposal for the company’s general rate case. Work included:
1) research on the financial implications of decoupling; 2) identification of decoupling mechanism
details to address company and regulatory requirements and objectives; 3) identification of rate
adjustment mechanisms that would work together with the company’s proposed decoupling
mechanism; and 4) preparing pre-filed testimony and testifying at hearings in support of the
company’s decoupling and rate adjustment proposals. The proposed rate adjustment mechanisms
included an inflation adjustment mechanism based on a statistical analysis, and a capital spending
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mechanism to recover the costs associated with capital plant investment targeted to improving
service reliability.
Interstate Power & Light (Alliant Energy) (2010 – 2011)
Conducted class allocated cost of service studies for a Midwestern electric utility’s Minnesota
electric system. Work included reconfiguring the company’s customer classes for cost of service
purposes to collapse end-use based classes with the classes to which they would be eligible. Cost
of service studies were performed on a before-and-after basis for the existing and proposed
classes. The cost of service studies included a fixed/variable study for production costs, and a
primary/secondary study for poles, transformers and conductors. Performed a TOU analysis to
determine the appropriate rate differentials for its peak and off-peak rates. Served as an expert
witness on behalf of the client in a general rate case before the Minnesota Public Service
Commission.
National Grid (2010)
Conducted class allocated cost of service studies for the client’s Massachusetts natural gas
operations. This task included combined gas cost of service studies for the consolidation of four
gas service territories into two gas utility subsidiaries. During interrogatories, performed four
separate allocated cost of service studies for each gas service territory. Work included
reconfiguring the company’s commercial and industrial customer classes according to size of load
and customer-related facilities. Served as an expert witness on behalf of the client in consolidated
general rate cases before the Massachusetts Department of Public Utilities.
Puget Sound Energy (2001 – 2002, 2006 – 2007, 2019 – 2020)
In three Washington general rate proceedings, provided cost of service and rate design support,
including expert witness testimony in support of the utility’s proposed revenue decoupling
mechanism. Conducted research on accelerated cost recovery mechanisms for infrastructure
replacement, and electric power cost adjustment mechanisms. In the latest general rate case, Mr.
Amen sponsored expert testimony on a proposed revenue attrition adjustment to the client’s
revenue requirement in the 2020 general rate case.
Utility System Operations and Organizational Development
Philadelphia Gas Works (2017, 2020)
Engaged to provide an independent consulting engineer’s report to be included as an appendix to
the official statement prepared in connection with the issuance of the City of Philadelphia,
Pennsylvania Gas Works Revenue Bonds. The evaluation of the PGW system included a
discussion of organization, management, and staffing; system service area; supply facilities;
distribution facilities; and the utility’s Capital Improvement Plan (CIP). Our report also
contained: (a) financial feasibility information, including analyses of gas rates and rate
methodology; (b) projection of future operation and maintenance expenses; (c) CIP financing
plans; (d) projection of revenue requirements as a determinant of future revenues; (e) an
assessment of PGW’s ability to satisfy the covenants in the General Gas Works Revenue Bond
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Exhibit No. 1
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Resume of Ronald J. Amen
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Ordinance of 1998 authorizing the issuance of the Bonds; and (f) information regarding potential
liquefied natural gas (“LNG”) expansion opportunities.
Puget Sound Energy (2013 – 2014)
Engaged to perform a review of its project management and capital spending authorization
processes (CSA). The overall project objectives were to educate project management (PM) staff as
to the importance and relevance of regulatory prudence standards, evaluate existing PM processes
along with newly introduced corporate CSA processes, and propose PM and corporate process and
documentation efficiencies. This task was accomplished through 1) a situational assessment and
risk review; 2) analysis of project management practices; and 3) development of common
documentation for the CSA and PM processes.
Puget Sound Energy (2012 – 2013)
Engaged to perform a review of how the company compares to similarly-situated utilities in the
areas of the underlying capitalized costs related to new customer additions (“new business
investment”) and the management policies and practices that influence the new business capital
investment. Examined the interrelationships of our client’s management policies and practices in
the functional areas related to new business investment and developed an understanding of the
nature of the costs captured by the new business investment process. Benchmarked those costs
relative to peers’ cost factors and management capital expenditure practices and performed
targeted peer group interviews on our client’s behalf. The review identified certain trends and/or
interrelationships between management policies and practices, as well as other exogenous factors,
and the resulting impact on new business investment.
Puget Sound Energy (2011 – 2012)
Engaged to perform a review of its electric transmission planning and project prioritization
process. The emphasis of the review was to determine if the process implemented by the client
could be expected to meet the regulatory standard of prudence, as adopted by the state regulatory
commission. Reviewed the prudence standard adopted by the commission in several recent
regulatory proceedings, supplemented by our knowledge of the prudence standard adopted at a
national level and in other states. The engagement included two phases: 1) an initial situation
assessment of the existing process employed by the client, and 2) a review of the historic
implementation of that process by reviewing a sampling of transmission projects. Compiled and
provided examples of capital planning documents and procedures, viewed as “best practices,”
from other electric utilities and other relevant transmission entities.
Alliant Energy (2011 – 2012)
Provided audit support for one of the company’s gas and electric utilities, Interstate Power &
Light, during a management audit ordered by one of its two regulatory jurisdictions. Conducted a
pre-audit of distribution operations and resource planning processes to provide the client with
potential audit issues. Assisted the client throughout the audit process in responding to information
requests, preparing company executives and management personnel for audit interviews, and
management of preliminary audit issues and findings by the independent audit firm.
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Ameren Illinois Utilities (2009 – 2010)
Performed a number of benchmark analyses to compare each of the client’s A&G and O&M
expenses, on a per-customer basis, to various peer groups conducted for the client’s natural gas
and electric operations. Analyses were performed for natural gas, electric and combination utilities
with both electric and gas operations. Various iterations of the analyses were prepared to make the
peer group of utilities more comparable to the characteristics of the client’s utility operations.
Served as an expert witness on behalf of the client in a consolidated general rate case proceeding
of its three utility subsidiaries before the Illinois Commerce Commission.

EXPERT WITNESS TESTIMONY PRESENTATION
• Alaska Regulatory Commission
• Arkansas Public Service Commission
• British Columbia Utility Commission (Canada)
• Colorado Public Utility Commission
• Connecticut Department of Public Utility Control
• Delaware Public Service Commission
• Illinois Commerce Commission
• Indiana Utility Regulatory Commission
• Kansas Corporation Commission
• Maine Public Utilities Commission
• Manitoba Public Utilities Board (Canada)
• Massachusetts Department of Utilities
• Minnesota Public Utilities Commission
• Missouri Public Service Commission
• Montana Public Service Commission
• New Brunswick Energy and Utilities Board (Canada)
• New Hampshire Public Utilities Commission
• North Dakota Public Service Commission
• Oklahoma Corporation Commission
• Oregon Public Utility Commission
• Pennsylvania Public Utility Commission
• Washington Utilities and Transportation Commission
• Federal Energy Regulatory Commission

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Exhibit No. 1
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Resume of Ronald J. Amen
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SELECTED PUBLICATIONS / PRESENTATIONS
“Enhancing the Profitability of Growth,” American Gas Association, Rate and Regulatory
Issues Seminar, April 4 - 7, 2004
“Regulatory Treatment of New Generation Resource Acquisition: Key Aspects of Resource
Policy, Procurement and New Resource Acquisition,” Law Seminars International, Managing
the Modern Utility Rate Case, February 17 - 18, 2005
“Managing Regulatory Risk – The Risk Associated with Uncertain Regulatory Outcomes,”
Western Energy Institute, Spring Energy Management Meeting, May 18 - 20, 2005
“Capital Asset Optimization – An Integrated Approach to Optimizing Utilization and Return on
Utility Assets,” Southern Gas Association, July 18 - 20, 2005
“Resource Planning as a Cost Recovery Tool,” Law Seminars International, Utility Rate Case
Issues & Strategies, February 22 - 23, 2007
“Natural Gas Infrastructure Development and Regulatory Challenges,” Southeastern
Association of Regulatory Utility Commissioners, Annual Conference, June 4 – 6, 2007
“Resource Planning in a Changing Regulatory Environment,” Law Seminars International,
Utility Rate Cases – Current Issues & Strategies, February 7 - 8, 2008
“Natural Gas Distribution Infrastructure Replacement,” American Gas Association, Rate
Committee Meeting and Regulatory Issues Seminar, April 11 – 13, 2010
“Building a T&D Investment Program to Satisfy Customers, Regulators and Shareholders,”
SNL Webinar, March 27, 2014
“Utility Infrastructure Replacement; Trends in Aging Infrastructure, Replacement Programs
and Rate Treatment,” Large Public Power Council, Rates Committee Meeting, August 14, 2014
“Natural Gas in the Decarbonization Era, Gas Resource Planning for Electric Generation,”
EUCI, January 22-23, 2020
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Exhibit No. 1
Page 13 of 13
Preston N. Carter ISB No. 8462
Morgan D. Goodin ISB No. 11184
Blake W. Ringer ISB No. 11223
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
[e-mail]
Attorneys for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF INTERMOUNTAIN GAS COMPANY.
FOR AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR NATURAL
GAS SERVICE IN THE STATE OF IDAHO
CASE NO. INT-G-22-07
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
EXHIBIT 2 TO ACCOMPANY THE
DIRECT TESTIMONY OF RONALD J. AMEN

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

Case No. INT-G-22-07
INTERMOUNTAIN GAS COMPANY
EXHIBIT 2

COST OF SERVICE ALLOCATION STUDY
TEST YEAR DECEMBER 31, 2022

Witness: Ronald J. Amen
Case No. INT-G-22-07
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Exhibit No. 2
Page 1 of 36

Contents
I. INTRODUCTION ................................................................................................................................ 3
1. Atrium Economics Cost of Service Study Model Overview ............................................................ 3
II. INTERMOUNTAIN’S COST OF SERVICE PROCEDURES ............................................................ 4
1. Functionalization ............................................................................................................................... 4
2. Classification ..................................................................................................................................... 4
3. Allocation .......................................................................................................................................... 5
3.1. Customer Classes and Tariff Schedules .................................................................................... 5
3.2. External Allocation Factors ...................................................................................................... 5
3.3. Internal Allocation Factors ........................................................................................................ 8
III. INTERMOUNTAIN’S COST OF SERVICE RESULTS .................................................................. 10
1. Schedule 1 - Account Balances and Allocation Methods ............................................................... 10
2. Schedule 2 - External Allocation Factors ........................................................................................ 10
3. Schedule 3 - Internal Allocation Factors ......................................................................................... 10
4. Schedule 4 - Cost of Service and Rate of Return Under Present and Proposed Rates .................... 10
5. Schedule 5 - Cost of Service Allocation Study Detail by Account ................................................. 10
6. Schedule 6 - Functionalized and Classified Rate Base and Revenue Requirement, and Unit Costs
by Customer Class .......................................................................................................................... 10
7. Schedule 7 – Alternative Cost of Service and Rate of Return Under Present and Proposed Rates 10

Case No. INT-G-22-07
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Exhibit No. 2
Page 2 of 36

I. INTRODUCTION
The purpose of this document is to discuss the development and results of the Cost of Service
Study (“COSS”) model and related schedules prepared for Intermountain Gas Company (“Intermountain” or the “Company”) based on the Test Year ended December 31, 2022 (“Test Year”).
The document is organized into three sections. The first section includes an overview of Atrium’s
COSS model used to develop the cost allocation study. The second section includes details of the
methodologies adopted in the development of the study. The last section exhibits the results of
the COSS study.
1. Atrium Economics Cost of Service Study Model Overview
The Cost of Service Study is submitted in support of the direct testimony of Ronald J. Amen in Exhibit 2. The COSS model presented in this proceeding is an excel based model that allows the user to modify various inputs and assumptions.
COSS Model Capabilities
The Atrium Economics’ COSS model provides a large range of analytical capabilities including:
• Unbundling of operations into functions: (i.e., production/supply, storage, transmission,
distribution, metering, and billing services.)
• Classification and allocation of costs into customer classes.
• Reports on Rate of Return, Revenue Requirement, and Revenue-to-Cost ratio for each
function and rate class.
• Development of unit costs of each functional classification for each rate class.
• Specification of the individual rate of return targets for each function or customer class.
• Provides detailed analyses of costs of gas, income taxes, working capital, depreciation
reserve, and depreciation expenses.
• Use of detailed analysis of labor expenses by account to facilitate the analyses of
administrative and general expenses and overhead costs.
• Facilitation of direct assignment of plant investment, expenses, and revenue dollars to
individual functions, classifications, or customer classes.
Follows Traditional 3-Step Analysis Process
The Atrium COSS Model follows the standard three-step analysis process:1) functionalization of
rate base and expenses into various functional categories; 2) classification of functionalized
components into demand, energy/commodity, and customer cost categories; and 3) allocation of
each component among the customer classes.
As part of the functionalization process, accounts for common costs that are not specifically related
to the primary functions, such as general plant and administrative and general expenses, are
automatically allocated to the proper function based on internally defined allocation factors. All
components of the utility’s total cost of service are grouped into one of the functions.
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Exhibit No. 2
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The Atrium COSS Model provides unbundled functionalized and classified cost information by
customer class; develops unbundled revenue requirements by functional classification for each
customer class; and calculates unit costs by function for customer, commodity, and demand
categories. Accounting costs are reported by FERC account level, and the allocation of A&G
expenses, general taxes, and income taxes are clearly reported.
Revenue requirements are calculated from the allocated rate base and expenses and are adjusted
to reflect the user-determined target rate of return and statutory tax adjustments. The actual
revenues collected are compared to the calculated cost-based revenue requirements to determine
class-specific, revenue-to-cost ratios to assist in revenue allocation and pricing activities.
Unit Cost Output Functionality
The COSS model calculates the unit cost of each functional classification separately for each rate
class based on the user-specified billing determinants. These unit cost data are among the most
important outputs from an embedded cost of service analysis. They are defined as the average cost
of providing service to customers per measure of service (i.e., per therm, per dekatherm of daily
demand, and per customer). Unit costs are a key consideration in developing prices for bundled,
unbundled, and re-bundled services.
Acceptance by Utility Regulatory Commissions
The format and presentation of the model’s outputs have been used in many rate case proceedings
and conform to standard utility commission requirements. Where necessary, the COSS model
outputs can be easily modified to meet specific jurisdictional filing requirements.
II. INTERMOUNTAIN’S COST OF SERVICE PROCEDURES
1. Functionalization
The following functional cost categories were identified for purposes of Intermountain’s cost allocation:
• Storage
• Transmission
• Distribution
• General (Customer)
Intermountain’s assigned functional categories are presented on Schedule 1.
2. Classification
The following classification categories were identified for purposes of Intermountain’s cost allocation:
• Demand
• Customer

Intermountain’s assigned classification categories are presented on Schedule 1.
Case No. INT-G-22-07
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Exhibit No. 2
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3. Allocation
The allocation step involves assigning classified costs to the customer classes based on cost
causation. Therefore, the allocation of costs is usually based on some measure of class loads or class service characteristics. The External (Schedule 2) and Internal (Schedule 3) Allocation Factors are utilized to allocate costs among various customer classes. Intermountain’s assigned Allocation Factors are presented on Schedule 1.
3.1.Customer Classes and Tariff Schedules
The following customer classes were identified for purposes of cost allocation:
• Residential Service
• General Service
• Large Volume
• Transport Service (Interruptible)
• Transport Service (Firm)

3.2.External Allocation Factors
Intermountain’s External Allocation Factors are presented on Schedule 2. The External Allocation
Factors are developed based on the special studies conducted using various detailed data as discussed below.
Commodity and Revenue Allocation Factors
Costs classified as “Commodity” are allocated among customer classes based on the weather-
normalized volumes for the test year.
REV – Factor developed to directly assign associated current base rate revenues to the specific
class in the Test Year.
COM – Factor developed to directly assign Weather Normalized Volumes/Throughput to the
specific class in the Test Year.
Customer Allocation Factors
Customer-related costs are generally allocated based on the number of customers within each class
of service, with appropriate weighting to recognize specific service characteristics.
CUST – Customer Count factor is based on the average number of customers per customer class
in the Test Year.
CUST_SALES_TRANS - The costs associated with planning, gas supply, and control activities
were specifically identified and allocated to the sales and transportation customer classes based on
the time reported by the personnel in these responsibility centers. First, the expenses were
segregated between sales and transport classes according to the assigned labor hours and then
allocated among the customer classes. A portion of control activities was allocated to customer
classes based on the number of alarms for the specifically identified customer classes and the
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Exhibit No. 2
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remaining costs were allocated based on the peak demand factor. The planning and supply related
costs were allocated based on the test year weather normalized volumes. Based on these various
components a composite allocator was created to incorporate this study into COSS.
MTRS – Meter Allocation factor is based on the weighted customer class cost of meters used to
serve gas customers in different rate classes. The analysis relies upon the Company’s records,
which provide an inventory of each type and size of meter for a specific customer class, and related
meter replacement costs. First, the meter records were grouped into three categories – Group 1,
Group 2, and Group 3 based on the meter size. Next, the average unit cost per group for each
customer class was derived. Then the relative weighting factor was derived by prorating to
Residential Class unit cost. To derive the allocation basis, the weighted factor was multiplied by
the test year customer bill counts for each customer class prorated by the groups.
M&R – The factor was derived to allocate FERC Account 385 Industrial measuring and regulating
station equipment. The analysis was performed based on the same set of data used to derive the
Meters allocation factor. Similar steps were taken to develop an allocation basis, but only relying
on Group 3 data and excluding the Residential Class.
SERV – The analysis relies upon the data contained in the Company’s property records which
provide an inventory and original cost of the service lines and service lines by diameter. The
original cost data was restated in terms of current cost using Handy-Whitman indices for services
to determine current unit cost. The interruptible snowmelt customer counts were removed for the
purpose of this analysis, due to their shared service lines with the customer premise. The records
were grouped into three groups: the Small Service group included service diameters of up to one
inch, the next group of Medium Services included service diameters between one and two inches,
and service lines with over two-inch diameters were identified as Large Services. Then, the unit
cost per group was derived. Using meter data records, customers were grouped into similar groups
(small meters, medium meters, and industrial meters). Applying service unit cost to relative
customer group counts determined total estimated service costs by customer class and service cost
per customer. Then the relative customer class unit cost was developed based on the Residential
Class and multiplied by the test year customer count for each customer class.
ACT_904 – The factor is based on the three-year (2019-2021) average of Bad Debt write-offs.
Demand Allocation Factors
PDAY_F&I – The factor is based on Peak Day capacity demand throughput for each customer
class including Firm and Interruptible customer classes.
PDAY_F – The factor is based on Peak Day capacity demand throughput for each customer class
including Firm customer classes only.
CUST_DEM_F&I – The composite factor is based on the CUST and PDAY_F&I factors prorated
to the customer and demand components determined in the Mains Analysis.

CUST_DEM_F – The composite factor is based on the CUST and PDAY_F factors prorated to
the customer and demand components determined in the Mains Analysis.
Case No. INT-G-22-07
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Exhibit No. 2
Page 6 of 36

Mains Analysis
The allocation of investment in facilities serving a distribution function should recognize that the
cost of these facilities is driven by two principal factors. First is the cost of extending the system
to connect individual customers. Second is the cost associated with the capacity requirements of
the customers connected.
There are two widely accepted methods for the classification of mains between customer-related
costs and demand-related costs. The two methods are the Minimum System Method and the Zero-
Intercept Method, both relying on the Company’s property record data to determine the cost of
pipe by size and type. Diameter groups that did not contain enough sample data were removed.
The unit cost for pipe in any year is determined by dividing the booked costs by the amount of
pipe installed in a standard unit of measurement. A variety of factors, such as the length of pipe
installed, location, installation conditions, etc., cause the annual unit cost of pipe by size and type
to vary significantly. Thus, a simple average of the yearly costs is not adequate for a determination
of the cost for each size of the pipe as it will not reflect a consistent set of data. Therefore, the
original cost data was restated in terms of current cost using the Handy-Whitman index.
Zero-Intercept Study:
The zero-intercept study was performed using a Weighted Linear Regression (WLR) on the cost
per foot by pipe diameter. Based on this relationship, the study estimates the cost of installing a
hypothetical pipe with zero capacity, which is where the estimated diameter is zero (i.e., the zero-
intercept). The zero-intercept determined value is then multiplied by all quantities of distribution
mains currently installed by the utility to arrive at a total minimum system cost. Total minimum
system cost divided by total system cost derives the portion of the system that is considered a fixed
investment and is classified as customer-related.

The distribution main investment is functionalized to distribution, classified based on the results
of the zero-intercept study to demand (44.7%) and customer (55.3%). The demand component of
the mains investment is allocated based on each class’s allocation of peak day. The customer
component of the mains investment is allocated based on each class’s number of customers.
Other Mains Studies:
In addition to the zero-intercept study discussed above, for comparison purposes two other mains
studies were conducted: one using the minimum system method adjusted to the load-carrying
capacity, and a different zero-intercept study using ordinary least squares regression. The
minimum system study used 2” as the minimum-sized steel mains and 2” as the minimum-sized
Zero-Intercept (Weighted Linear Regression)
Material Quantity Cost 2022 Zero-Intercept
Cost (2022) Customer Component Customer Component
Percentage
Plastic 23,707,720 $257,506,229 5.65$ 133,850,942$ 52.0%
Steel 7,718,299 $520,929,589 38.38$ 296,243,752$ 56.9%
Total 31,426,019 778,435,819$ 430,094,694$ 55.3%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 7 of 36

plastic mains. The minimum system study yielded a customer component of 68.7% for distribution
mains as depicted below.

The zero-intercept study using ordinary least squares is simple linear regression performed for
each material type with unit costs as the dependent variable and the squared pipe diameter as the
independent variable. This study produced very similar results (i.e. customer component of
54.6%) as the zero-intercept WLR.

3.3.Internal Allocation Factors
Internal Allocation Factors are developed within the COSS model based on the cost ratios of allocated cost based the external allocation factors, representing various forms of the composite external and internal factors as mathematical sums.
INT_RATEBASE – The factor is based on the derived rate base by customer class.
INT_REV_REQ – The factor is based on the derived revenue requirement by customer class.
INT_REQ_INCOME – The factor is based on the derived customer class required return on the
rate base.
INT_TOTPLT – The factor is based on the total plant in service balance allocated to the
customer classes.
INT_STORPT – The factor is based on the total Storage plant in service balance allocated to the
customer classes.
INT_INTGPLT – The factor is based on the total Intangible plant in service balance allocated to
the customer classes.
INT_STOR_TRANSM_DIST_SUBTOTAL – The factor is based on the Storage, Transmission,
and Distribution plant in service balances allocated to the customer classes.
Minimum System
Material Quantity Cost 2022
Minimum Size
Cost (2022)Customer Component
Customer Component
Percentage
Plastic 23,707,720 $257,506,229 $9.03 $214,082,249 83.1%
Steel 7,718,299 $520,929,589 $46.81 $361,275,904 69.4%
Total 31,426,019 $778,435,819 $575,358,154 73.9%
Minimum System Adjusted for Load Carrying Capacity 68.9%
Zero-Intercept (Ordinary Least Squares)
Material Quantity Cost 2022
Zero-Intercept
Cost (2022) Customer Component
Customer Component
Percentage
Plastic 23,707,720 $257,506,229 8.01$ 189,853,388$ 73.7%
Steel 7,718,299 $520,929,589 30.46$ 235,123,466$ 45.1%
Total 31,426,019 778,435,819$ 424,976,854$ 54.6%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 8 of 36

INT_DIST_SUBTOTAL – The factor is based on the Distribution plant in service balance by
customer class excluding FERC Account 375 -Structures and Improvements.
INT_DISTPT –The factor is based on the total Distribution plant in service balance allocated to
the customer classes.
INT_DMAINS_SERV – The factor is based on the FERC Accounts 376 - Mains and 380 -
Services balances allocated to the customer classes.
INT_GENPLT – The factor is based on the General plant in service balance allocated to the
customer classes.
INT_TRANSPT – The factor is based on the Transmission plant in service balance allocated to
the customer classes.
INT_CUSTACC – The factor is based on the Customer Account expenses allocated to the
customer classes, excluding FERC Account 901- Supervision.
INT_OML – The factor is based on the total customer class allocated labor-related Operation and
Maintenance Expenses.
INT_DIST_OL - The factor is based on the customer class allocated Distribution labor-related
Operation Expenses.
INT_DIST_ML - The factor is based on the customer class allocated Distribution labor-related
Maintenance Expenses.

Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 9 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
1 RATE BASE
2 Plant in Service
3 Intangible Plant
4 Organization 301.0 2,506$ INT_STOR_TRANSM_DIST_SUBTOTAL
5 Franchises & Consents 302.0 429,487 INT_STOR_TRANSM_DIST_SUBTOTAL
6 Misc. Intangible Plant - Plant Related 303.0 11,659,883 INT_STOR_TRANSM_DIST_SUBTOTAL
7 Misc. Intangible Plant - Customer Related 303.0 0
8 Misc. Intangible Plant - Labor Related 303.0 46,595,509 INT_OML
9 Subtotal - Intangible Plant 58,687,385$
10 Natural Gas Other Storage Plant
11 Land & Land Rights 360.0 292,588$ STORAGE DEMAND PDAY
12 Structures & improvement 361.0 10,211,065 STORAGE DEMAND PDAY
13 Gas Holders 362.0 10,871,165 STORAGE DEMAND PDAY
14 Purification Equipment 363.0 19,205,253 STORAGE DEMAND PDAY
15 Subtotal - Natural Gas Other Storage Plant 40,580,071$
16 Transmission plant
17 Land and Land Rights 365.1 782,865$ TRANSMISSION DEMAND PDAY
18 Rights-of-Way 365.2 0
19 Structures and improvements 366.0 77,152 TRANSMISSION DEMAND PDAY
20 Mains 367.0 69,918,045 TRANSMISSION DEMAND PDAY
21 Compressor station equipment 368.0 2,167,366 TRANSMISSION DEMAND PDAY
22 Measuring and regulating station equipment 369.0 0
23 Communication equipment 370.0 714,440 TRANSMISSION DEMAND PDAY
24 Other equipment 371.0 0
25 ARO for Transmission Plant 372.0 0
26 Subtotal - Transmission plant 73,659,868$
27 Distribution Plant
28 Land and land rights 374.0 2,120,601$ DISTRIBUTION DEMAND CUST_DEM
29 Structures and improvements 375.0 86,895 INT_DIST_SUBTOTAL
30 Mains 376.0 260,788,927 DISTRIBUTION DEMAND CUST_DEM
31 Compressor station equipment 377.0 0
32 Measuring and regulating station equipment—general 378.0 13,262,760 DISTRIBUTION DEMAND CUST_DEM
33 Measuring and regulating station equipment—city gate check stations 379.0 97,219 DISTRIBUTION DEMAND CUST_DEM
34 Services 380.0 214,568,497 CUSTOMER CUSTOMER SERV
35 Meters 381.0 80,601,889 CUSTOMER CUSTOMER MTRS
36 Meter installations 382.0 0
37 House regulators 383.0 19,011,355 CUSTOMER CUSTOMER MTRS
38 House regulatory installations 384.0 0
39 Industrial measuring and regulating station equipment 385.0 13,277,094 CUSTOMER CUSTOMER M&R
40 Other property on customers' premises 386.0 0
41 Other equipment 387.0 0
42 Asset retirement costs for distribution plant 388.0 0
43 Subtotal - Distribution Plant 603,815,237$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 10 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
44 General Plant
45 Land and Land Rights 389.0 3,598,925$ INT_STOR_TRANSM_DIST_SUBTOTAL
46 Structures and Improvements 390.0 26,123,545 INT_STOR_TRANSM_DIST_SUBTOTAL
47 Office Furniture and Equipment 391.0 6,475,232 INT_OML
48 Transportation Equipment 392.0 13,285,846 INT_STOR_TRANSM_DIST_SUBTOTAL
49 Stores Equipment 393.0 45,565 INT_STOR_TRANSM_DIST_SUBTOTAL
50 Tools, Shop, and Garage Equipment 394.0 8,470,948 INT_STOR_TRANSM_DIST_SUBTOTAL
51 Laboratory Equipment 395.0 0
52 Power Operated Equipment 396.0 1,847,313 INT_STOR_TRANSM_DIST_SUBTOTAL
53 Communication Equipment 397.0 3,377,789 INT_STOR_TRANSM_DIST_SUBTOTAL
54 Misc. Equipment 398.0 21,290 INT_STOR_TRANSM_DIST_SUBTOTAL
55 Other Intangible Property 399.0 0
56 ARO for General Plant 399.1 0
57 Subtotal - General Plant 63,246,453$
58 Total Plant in Service 839,989,014$
59 Accumulated Provision for Depreciation & Amortization
60 Intangible Plant
61 Organization 301.0 (2,506)$ INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
62 Franchises & Consents 302.0 (429,487)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
63 Misc. Intangible Plant - Plant Related 303.0 (5,432,750)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
64 Misc. Intangible Plant - Customer Related 303.0 0 - - - - - -
65 Misc. Intangible Plant - Labor Related 303.0 (21,710,489) INT_OML - - - - -
66 Subtotal - Intangible Plant (27,575,232)$
67 Natural Gas Other Storage Plant
68 Land & Land Rights 360.0 -$ 0 STORAGE DEMAND PDAY - -
69 Structures & improvement 361.0 (3,074,406) 0 STORAGE DEMAND PDAY - -
70 Gas Holders 362.0 (3,796,957) 0 STORAGE DEMAND PDAY - -
71 Purification Equipment 363.0 (9,401,006) 0 STORAGE DEMAND PDAY - -
72 Subtotal - Natural Gas Other Storage Plant (16,272,369)$
73 Transmission plant
74 Land and Land Rights 365.1 (458,901)$ 0 TRANSMISSION DEMAND PDAY - -
75 Rights-of-Way 365.2 0 0 0 0 0 - -
76 Structures and improvements 366.0 (59,206) 0 TRANSMISSION DEMAND PDAY - -
77 Mains 367.0 (49,147,989) 0 TRANSMISSION DEMAND PDAY - -
78 Compressor station equipment 368.0 (570,780) 0 TRANSMISSION DEMAND PDAY - -
79 Measuring and regulating station equipment 369.0 0 0 0 0 0 - -
80 Communication equipment 370.0 (751,405) 0 TRANSMISSION DEMAND PDAY - -
81 Other equipment 371.0 0 0 0 0 0 - -
82 ARO for Transmission Plant 372.0 0 0 0 0 0 - -
83 Subtotal - Transmission plant (50,988,281)$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 11 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
84 Distribution Plant
85 Land and land rights 374.0 (440,513)$ 0 DISTRIBUTION DEMAND CUST_DEM - -
86 Structures and improvements 375.0 (20,501)INT_DIST_SUBTOTAL0 0 0 - -
87 Mains 376.0 (118,437,511) 0 DISTRIBUTION DEMAND CUST_DEM - -
88 Compressor station equipment 377.0 0 0 0 0 0 - -
89 Measuring and regulating station equipment—general 378.0 (3,263,649) 0 DISTRIBUTION DEMAND CUST_DEM - -
90 Measuring and regulating station equipment—city gate check stations 379.0 559 0 DISTRIBUTION DEMAND CUST_DEM - -
91 Services 380.0 (116,439,054) 0 CUSTOMER CUSTOMER 0 - SERV
92 Meters 381.0 (30,579,658) 0 CUSTOMER CUSTOMER 0 - MTRS
93 Meter installations 382.0 0 0 0 0 0 - -
94 House regulators 383.0 (6,900,827) 0 CUSTOMER CUSTOMER 0 - MTRS
95 House regulatory installations 384.0 0 0 0 0 0 - -
96 Industrial measuring and regulating station equipment 385.0 (7,373,388) 0 CUSTOMER CUSTOMER 0 - M&R
97 Other property on customers' premises 386.0 0 0 0 0 0 - -
98 Other equipment 387.0 0 0 0 0 0 - -
99 Asset retirement costs for distribution plant 388.0 0 0 0 0 0 - -
100 Subtotal - Distribution Plant (283,454,542)$
101 General Plant
102 Land and Land Rights 389.0 -$ INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
103 Structures and Improvements 390.0 (9,732,176)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
104 Office Furniture and Equipment 391.0 (3,415,517) INT_OML - - - - -
105 Transportation Equipment 392.0 (5,137,199)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
106 Stores Equipment 393.0 (9,895)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
107 Tools, Shop, and Garage Equipment 394.0 (3,560,197)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
108 Laboratory Equipment 395.0 0 - - - - - -
109 Power Operated Equipment 396.0 (612,161)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
110 Communication Equipment 397.0 (1,750,656)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
111 Misc. Equipment 398.0 (12,536)INT_STOR_TRANSM_DIST_SUBTOTAL- - - - -
112 Other Intangible Property 399.0 0 - - - - - -
113 ARO for General Plant 399.1 0 - - - - - -
114 Subtotal - General Plant (24,230,337)$
115 Amortization
116 Intangible Plant 111.0 0
117 Production Plant 111.0 0
118 Natural gas storage and processing plant 111.0 0
119 Transmission plant 111.0 0
120 Distribution plant 111.0 0
121 General plant 111.0 0
122 Subtotal - Amortization -
123 Total Accumulated Provision for Depreciation & Amortization (402,520,761)$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 12 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
124 Other Rate Base Items
125 Natural gas plant acquisition adjustments 114.0 -$
126 Accumulated provision for asset acquisition adjustments 115.0 0
127 Materials And Supplies 154.0 6,477,488 INT_STOR_TRANSM_DIST_SUBTOTAL
128 Stores Expense Undistributed 163.0 0
129 Gas Stored Underground - PA 164.1 0
130 LNG Inventory 164.2 3,072,269 STORAGE DEMAND PDAY
131 Prepayments 165.0 0
132 Other regulatory assets 182.3 0
133 Miscellaneous deferred debits 186.0 0
134 Accumulated deferred income taxes 190.0 0
135 Accumulated provision for property insurance 228.1 0
136 Accumulated provision for injuries and damages 228.2 0
137 Accumulated provision for pensions and benefits 228.3 0
138 Accumulated miscellaneous operating provisions 228.4 0
139 Accumulated provision for rate refunds 229.0 0
140 Asset retirement obligations 230.0 0
141 Customer deposits 235.0 0
142 Other deferred credits 253.0 0
143 Accumulated deferred income taxes—accelerated amortization property 281.0 0
144 Accumulated deferred income taxes—Storage Plant 282.1 (2,499,689) INT_STORPT
145 Accumulated deferred income taxes—Transmission Plant 282.2 (4,537,370) INT_TRANSPT
146 Accumulated deferred income taxes—Distribution Plant 282.3 (37,194,379) INT_DISTPT
147 Accumulated deferred income taxes—General Plant 282.4 (3,895,915) INT_GENPLT
148 Accumulated deferred income taxes—other 283.0 0
149 Accumulated deferred investment tax credits 255.0 0
150 Customer advances for construction 252.0 (11,377,344) INT_DMAINS_SERV
151 Other regulatory liabilities 254.0 0
152 Working capital allowance N/A 0
153 Subtotal - Other Rate Base Items (49,954,940)$
154 TOTAL RATE BASE 387,513,313$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 13 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
155 OPERATION AND MAINTENANCE EXPENSE
156 Production, Storage, LNG, Transmission, and Distribution Expense
157 Other Gas Supply Expenses
158 Natural gas well head purchases 800.0 -$
159 Natural gas well head purchases, intracompany transfers 800.1 0
160 Natural gas field line purchases 801.0 0
161 Natural gas gasoline plant outlet purchases 802.0 0
162 Natural gas transmission line purchases 803.0 0
163 Natural gas city gate purchases 804.0 0
164 Liquefied natural gas purchases 804.1 0
165 Other gas purchases 805.0 0
166 Purchased gas cost adjustments 805.1 0
167 Exchange gas 806.0 0
168 Well expenses—Purchased gas. 807.1 0
169 Operation of purchased gas measuring stations. 807.2 0
170 Maintenance of purchased gas measuring stations. 807.3 0
171 Purchased gas calculations expenses. 807.4 0
172 Other purchased gas expenses. 807.5 0
173 Gas withdrawn from storage—debit 808.1 0
174 Gas delivered to storage—credit 808.2 0
175 Withdrawals of liquefied natural gas held for processing—debt 809.1 0
176 Deliveries of natural gas for processing—credit 809.2 0
177 Gas used for compressor station fuel—credit 810.0 0
178 Gas used for products extraction—credit 811.0 0
179 Other gas supply expenses - Gas Supply 813.1 301,989 DISTRIBUTION CUSTOMER CUST_SALES_TRANS
180 Other gas supply expenses 813.0 67,802 DISTRIBUTION CUSTOMER CUST
181 Subtotal - Other Gas Supply Expenses 369,791$
182 Other Storage Expenses - Operation
183 Operation supervision and engineering 840.0 960$ STORAGE DEMAND PDAY
184 Operation labor and expenses 841.0 647,172 STORAGE DEMAND PDAY
185 Rents 842.0 0
186 Fuel 842.1 124,132 STORAGE DEMAND PDAY
187 Power 842.2 109,214 STORAGE DEMAND PDAY
188 Gas losses 842.3 0
189 Subtotal - Other Storage Expenses - Operation 881,479$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 14 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
190 Other Storage Expenses - Maintenance
191 Maintenance supervision and engineering 843.1 -$
192 Maintenance of structures and improvements 843.2 1,525 STORAGE DEMAND PDAY
193 Maintenance of gas holders 843.3 299 STORAGE DEMAND PDAY
194 Maintenance of purification equipment 843.4 1,761 STORAGE DEMAND PDAY
195 Maintenance of liquefaction equipment 843.5 64,944 STORAGE DEMAND PDAY
196 Maintenance of vaporizing equipment 843.6 109,460 STORAGE DEMAND PDAY
197 Maintenance of compressor equipment 843.7 28,919 STORAGE DEMAND PDAY
198 Maintenance of measuring and regulating equipment 843.8 0
199 Maintenance of other equipment 843.9 30,000 STORAGE DEMAND PDAY
200 Subtotal - Other Storage Expenses - Maintenance 236,909$
201 Transmission Operation Expenses
202 Operation supervision and engineering 850.0 -$
203 System control and load dispatching 851.0 0
204 Communication system expenses 852.0 27,314 TRANSMISSION DEMAND PDAY
205 Compressor station labor and expenses 853.0 86,348 TRANSMISSION DEMAND PDAY
206 Gas for compressor station fuel 854.0 0
207 Other fuel and power for compressor stations 855.0 0
208 Mains expenses 856.0 1,885 TRANSMISSION DEMAND PDAY
209 Measuring and regulating station expenses 857.0 0
210 Transmission and compression of gas by others 858.0 0
211 Other expenses 859.0 0
212 Rents 860.0 0
213 Subtotal - Transmission Operation Expenses 115,547$
214 Transmission Maintenance Expenses
215 Maintenance supervision and engineering 861.0 -$
216 Maintenance of structures and improvements 862.0 0
217 Maintenance of mains 863.0 17,387 TRANSMISSION DEMAND PDAY
218 Transmission Mains - Pipeline Integrity 863.1 28,262 TRANSMISSION DEMAND PDAY
219 Maintenance of compressor station equipment 864.0 0
220 Maintenance of measuring and regulating station equipment 865.0 0
221 Maintenance of communication equipment 866.0 133,623 TRANSMISSION DEMAND PDAY
222 Maintenance of other equipment 867.0 0
223 Subtotal - Transmission Maintenance Expenses 179,272$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 15 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
224 Distribution Operation Expenses
225 Operation supervision and engineering 870.0 4,317,916$ INT_DIST_OL
226 Operation supervision and engineering- Gas Supply and Control 870.1 62,783 DISTRIBUTION CUSTOMER CUST_SALES_TRANS
227 Distribution load dispatching 871.0 253,255 DISTRIBUTION CUSTOMER CUST_SALES_TRANS
228 Compressor station fuel and power (major only) 873.0 0
229 Mains and services expenses 874.0 4,725,499 INT_DMAINS_SERV
230 Measuring and regulating station expenses—general 875.0 437,602 DISTRIBUTION DEMAND CUST_DEM
231 Measuring and regulating station expenses—industrial 876.0 330,316 DISTRIBUTION CUSTOMER M&R
232 Measuring and regulating station expenses—city gate check stations 877.0 0
233 Meter and house regulator expenses 878.0 1,633,964 CUSTOMER CUSTOMER MTRS
234 Meter and house regulator expenses - installation credits 878.3 (1,833,969) CUSTOMER CUSTOMER MTRS
235 Customer installations expenses 879.0 2,404,356 CUSTOMER CUSTOMER CUST
236 Other expenses 880.0 4,819,166 INT_DISTPT
237 Rents 881.0 241,488 INT_DIST_OL
238 Subtotal - Distribution Operation Expenses 17,392,377$
239 Distribution Maintenance Expenses
240 Maintenance supervision and engineering 885.0 252,408$ INT_DIST_ML
241 Maintenance of structures and improvements 886.0 0
242 Maintenance of mains 887.0 1,559,102 DISTRIBUTION DEMAND CUST_DEM
243 Distribution Mains - Pipeline Integrity 887.1 90,461 DISTRIBUTION DEMAND CUST_DEM
244 Maintenance of compressor station equipment 888.0 0
245 Maintenance of measuring and regulating station equipment—general 889.0 577,682 DISTRIBUTION DEMAND CUST_DEM
246 Maintenance of measuring and regulating station equipment—industrial 890.0 122,251 CUSTOMER CUSTOMER M&R
247 Maintenance of measuring and regulating station equipment—city gate 891.0 0
248 Maintenance of services 892.0 3,159,609 DISTRIBUTION CUSTOMER SERV
249 Maintenance of meters and house regulators 893.0 1,235,301 DISTRIBUTION CUSTOMER MTRS
250 Maintenance of other equipment 894.0 569,681 INT_DIST_ML
251 Subtotal - Distribution Maintenance Expenses 7,566,497$
252 Total Production, Storage, LNG, Transmission, and Distribution Expense 26,741,871$
253 Customer Accounts, Service, and Sales Expense
254 Customer Account
255 Supervision 901.0 177,085$ INT_CUSTACC
256 Meter reading expenses 902.0 1,078,574 CUSTOMER CUSTOMER CUST
257 Customer records and collection expenses 903.0 7,216,280 CUSTOMER CUSTOMER CUST
258 Uncollectible accounts 904.0 510,784 CUSTOMER CUSTOMER ACT_904
259 Miscellaneous customer accounts expenses 905.0 0
260 Subtotal - Customer Account 8,982,723$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 16 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
261 Customer Service & Information Expenses
262 Supervision 907.0 -$
263 Customer assistance expenses 908.0 835,629 CUSTOMER CUSTOMER CUST
264 Informational and instructional advertising expenses 909.0 126,903 CUSTOMER CUSTOMER CUST
265 Miscellaneous customer service and informational expenses 910.0 0
266 Subtotal - Customer Service & Information Expenses 962,532$
267 Sales Expenses
268 Supervision 911.0 231,731$ CUSTOMER CUSTOMER CUST
269 Demonstrating and selling expenses 912.0 1,241,710 CUSTOMER CUSTOMER CUST
270 Advertising expenses 913.0 40,610 CUSTOMER CUSTOMER CUST
271 Miscellaneous sales expenses 916.0 0
272 Subtotal - Sales Expenses 1,514,051$
273 Total Customer Accounts, Service, and Sales Expense 11,459,306$
274 Administrative and General Expenses
275 Administrative and general salaries 920.0 6,169,823$ INT_OML
276 Administrative and general salaries - Gas Supply and Control 920.1 164,929 CUSTOMER CUSTOMER CUST_SALES_TRANS
277 Office supplies and expenses 921.0 5,722,640 INT_OML
278 Outside services employed 923.0 596,622 INT_OML
279 Property insurance 924.0 122,539 INT_TOTPLT
280 Injuries and damages 925.0 1,221,147 INT_OML
281 Employee pensions and benefits 926.0 1,594,449 INT_OML
282 Franchise requirements 927.0 0
283 Regulatory commission expenses 928.0 118,537 CUSTOMER CUSTOMER REV
284 Duplicate charges—Credit 929.0 0
285 General advertising expenses 930.1 78,048 CUSTOMER CUSTOMER CUST
286 Miscellaneous general expenses 930.2 436,330 INT_DIST_SUBTOTAL
287 Rents 931.0 819,634 INT_OML
288 Maintenance of general plant 935.0 4 INT_GENPLT
289 Subtotal - Administrative and General Expenses 17,044,704$
290 TOTAL OPERATION AND MAINTENANCE EXPENSE 55,245,881$
291 Adjustments, Depreciation and Amortization Expense
292 Depreciation Expense
293 Depreciation expense intangible plant 403.1 4,703,175$ INT_INTGPLT
294 Depreciation expense storage and terminaling 403.2 1,112,919 INT_STORPT
295 Depreciation expense transmission 403.3 1,064,501 INT_TRANSPT
296 Depreciation expense distribution 403.4 13,524,126 INT_DISTPT
297 Depreciation expense general plant 403.5 1,725,030 INT_GENPLT
298 Subtotal - Depreciation Expense 22,129,750$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 17 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 1 - Account Balances and Allocation Methods
Line
No.Account Description
FERC
Account Account Balance
Internal
Allocation Factor
Functional
Allocation Factor
Classification
Allocation Factor
Demand
Allocation Factor
Commodity
Allocation Factor
Customer
Allocation Factor
299 Amortization Expense
300 Amortization and depletion of producing natural gas land and land 404.1 -$
301 Amortization of underground storage land and land rights 404.2 0
302 Amortization of other limited-term gas plant 404.3 0
303 Amortization of other gas plant 405.0 0
304 Amortization of gas plant acquisition adjustments 406.0 0
305 Amortization of property losses, unrecovered plant and regulatory 407.1 0
306 Amortization of conversion expense 407.2 0
307 Subtotal - Amortization Expense -
308 Total Adjustments, Depreciation and Amortization Expense 22,129,750$
309 Taxes
310 Taxes Other Than Income Taxes
311 Taxes Other Than Income Taxes - Payroll 408.1 2,282,838$ INT_OML
312 Taxes Other Than Income Taxes - Property 408.2 3,623,049 INT_TOTPLT
313 Taxes Other Than Income Taxes - Franchise 408.3 13,950 CUSTOMER CUSTOMER REV
314 Taxes Other Than Income Taxes - IPUC Fee 408.4 520,047 CUSTOMER CUSTOMER REV
315 Subtotal - Taxes Other Than Income Taxes 6,439,884$
316 Income Taxes
317 Income Taxes - federal taxes utility operating income 409.1 5,054,746$ INT_REQ_INCOME
318 Income Taxes - state taxes utility operating income 409.1 771,296 INT_REQ_INCOME
319 Income Taxes - other taxes utility operating income 410.1 0 INT_REQ_INCOME
320 Provision for deferred income taxes—credit, utility operating income 411.1 0
321 Investment Tax credit Adj. 411.4 0
322 Subtotal - Income Taxes 5,826,042$
323 Total Taxes 12,265,926$
324 REVENUE REQUIREMENT AT EQUAL RATES OF RETURN
325 Test Year Expenses at Current Rates 89,641,557$
326 Return on Rate Base 28,559,731$ INT_RATEBASE
327 Gross Up Items
328 Federal Income Tax 2,233,076$ INT_REQ_INCOME
329 State Income Tax 654,723 INT_REQ_INCOME
330 Uncollectible Account - Increase 26,996 CUSTOMER CUSTOMER ACT_904
331 Taxes Other Than Income Taxes - IPUC Fee 22,619 CUSTOMER CUSTOMER REV
332 TOTAL REVENUE REQUIREMENT AT EQUAL RATES OF RETURN 121,138,702$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 18 of 36
Intermountain Gas Company
Class Cost of Service Study - Development of External Allocators
Test Year Ended December 31, 2022
Schedule 2 - External Allocation Factors
Allocator Code Description Classifier Total Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
RS GS LV-1 T-3 T-4
CUSTOMER EXTERNAL ALLOCATORS
CUST Average Number Customers CUS 100.0%91.3%8.7%0.0%0.0%0.0%
403,743 368,571 35,029 34 7 102
CUST_SALES_TRANS Gas Supply and Control Cost Allocation CUS 100.0%34.9%16.1%2.9%2.4%43.7%
782,956 273,270 126,059 22,872 18,773 341,983
MTRS Customer Meters CUS 100.0%73.9%25.4%0.1%0.1%0.5%Weighted Customer Cost 5,986,091 4,422,848 1,519,086 7,226 6,346 30,585
M&R Industrial measuring and regulating station equipment CUS 100.0%0.0%91.1%3.0%0.4%5.5%
Weighted Customer Cost 9,362 8,532 279 36 515
SERV Services CUS 100.0%81.4%17.8%0.2%0.0%0.6%
Weighted Customer Cost 452,446 368,350 80,593 729 132 2,642
ACT_904 Uncollectible accounts CUS 100.0%85.4%14.2%0.1%0.0%0.3%
Uncollectible accounts - Residential 476,351 476,351
Uncollectible accounts - Commercial 79,180 79,180 Uncollectible accounts - Industrial 2,473 591 121 1,761 Uncollectible accounts 558,004 476,351 79,180 591 121 1,761
COMMODITY EXTERNAL ALLOCATORS
REV Total Sales and Transportation REV 100.0%65.6%24.2%0.6%0.5%9.0%
107,349,830 70,391,038 26,030,361 677,926 537,118 9,713,387
COM Weather Normalized Volumes COM 100.0%35.1%17.1%1.7%5.2%40.9%
805,130,573 282,522,986 138,067,893 13,566,644 41,523,144 329,449,906
DEMAND EXTERNAL ALLOCATORS
PDAY_F&I Peak Day (Design Day) Firm & Interruptible DEM 100.0%51.6%22.8%1.1%1.7%22.8%
6,521,643 3,362,707 1,485,359 74,405 113,762 1,485,410
PDAY_F Peak Day (Design Day) Firm DEM 100.0%52.5%23.2%1.2%0.0%23.2%
6,404,055 3,360,303 1,483,938 74,405 1,485,410
CUST_DEM_F&I Customer and Demand Composite Factor DEM 100.0%73.5%15.0%0.5%0.8%10.2%
CUST 1.0000 0.9129 0.0868 0.0001 0.0000 0.0003
CUST Customer Component - Zero-Intercept (WLR)55.3% 0.5525 0.5044 0.0479 0.0000 0.0000 0.0001 PDAY_F&I 1.0000 0.5156 0.2278 0.0114 0.0174 0.2278 PDAY Demand Components 44.7% 0.4475 0.2307 0.1019 0.0051 0.0078 0.1019
CUST_DEM_F Customer and Demand Composite Factor DEM 100.0%73.9%15.2%0.5%0.0%10.4%
CUST 1.0000 0.9129 0.0868 0.0001 0.0000 0.0003
CUST Customer Component - Zero-Intercept (WLR)55.3% 0.5525 0.5044 0.0479 0.0000 0.0000 0.0001
PDAY_F 1.0000 0.5247 0.2317 0.0116 - 0.2319
PDAY Demand Components 44.7% 0.4475 0.2348 0.1037 0.0052 - 0.1038
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 19 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 3 - Internal Allocation Factors
Allocator Code Total Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
ALLOCATION FACTOR BASIS
INT_INTGPLT 58,687,385$ 43,141,262$ 11,473,761$ 275,179$ 64,619$ 3,732,565$
INT_STORPT 40,580,071$ 21,292,963$ 9,403,152$ 471,476$ -$ 9,412,480$
INT_TRANSPT 73,659,868$ 38,650,421$ 17,068,351$ 855,811$ -$ 17,085,284$
INT_DISTPT 603,815,237$ 452,566,741$ 117,505,276$ 2,310,976$ 221,437$ 31,210,808$
INT_GENPLT 63,246,453$ 45,316,166$ 12,640,703$ 317,377$ 25,969$ 4,946,238$
INT_TOTPLT 839,989,014$ 600,967,553$ 168,091,243$ 4,230,819$ 312,025$ 66,387,375$
INT_RATEBASE 387,513,313$ 278,312,371$ 77,282,709$ 1,889,417$ 153,217$ 29,875,599$
INT_DMAINS_SERV 475,357,424$ 367,457,769$ 77,763,063$ 1,713,647$ 65,158$ 28,357,788$
INT_OML 19,453,208$ 14,407,914$ 3,777,971$ 89,306$ 25,421$ 1,152,595$
INT_DIST_OL 9,662,687$ 7,232,893$ 1,878,272$ 42,086$ 11,669$ 497,767$
INT_DIST_ML 4,801,667$ 3,704,475$ 916,093$ 13,527$ 1,846$ 165,726$
INT_CUSTACC 8,805,638$ 8,008,293$ 792,138$ 1,245$ 254$ 3,708$
INT_DIST_SUBTOTAL 14,758,214$ 11,265,162$ 2,674,581$ 60,271$ 12,033$ 746,167$
INT_STOR_TRANSM_DIST_SUBTOTAL 718,055,176$ 512,510,125$ 143,976,779$ 3,638,263$ 221,437$ 57,708,572$
INT_REQ_INCOME 28,559,731$ 20,511,622$ 5,695,736$ 139,250$ 11,292$ 2,201,832$
INT_REV REQ 121,138,702$ 90,246,109$ 22,498,973$ 531,389$ 85,891$ 7,776,340$
ALLOCATION FACTOR
INT_INTGPLT 100.00% 73.51% 19.55% 0.47% 0.11% 6.36%
INT_STORPT 100.00% 52.47% 23.17% 1.16% 0.00% 23.19%
INT_TRANSPT 100.00% 52.47% 23.17% 1.16% 0.00% 23.19%
INT_DISTPT 100.00% 74.95% 19.46% 0.38% 0.04% 5.17%
INT_GENPLT 100.00% 71.65% 19.99% 0.50% 0.04% 7.82%
INT_TOTPLT 100.00% 71.54% 20.01% 0.50% 0.04% 7.90%
INT_RATEBASE 100.00% 71.82% 19.94% 0.49% 0.04% 7.71%
INT_DMAINS_SERV 100.00% 77.30% 16.36% 0.36% 0.01% 5.97%
INT_OML 100.00% 74.06% 19.42% 0.46% 0.13% 5.92%
INT_DIST_OL 100.00% 74.85% 19.44% 0.44% 0.12% 5.15%
INT_DIST_ML 100.00% 77.15% 19.08% 0.28% 0.04% 3.45%
INT_CUSTACC 100.00% 90.95% 9.00% 0.01% 0.00% 0.04%
INT_DIST_SUBTOTAL 100.00% 76.33% 18.12% 0.41% 0.08% 5.06%
INT_STOR_TRANSM_DIST_SUBTOTAL 100.00% 71.37% 20.05% 0.51% 0.03% 8.04%
INT_REQ_INCOME 100.00% 71.82% 19.94% 0.49% 0.04% 7.71%
INT_REV REQ 100.00% 74.50% 18.57% 0.44% 0.07% 6.42%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 20 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 4 – Cost of Service and Rate of Return under Present and Proposed Rates
Line
No.Revenue Requirement Summary Total System Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
1 Rate Base
2 Plant in Service 839,989,014$ 600,967,553$ 168,091,243$ 4,230,819$ 312,025$ 66,387,375$
3 Accumulated Reserve (402,520,761) (285,734,187) (81,310,557) (2,125,239) (144,006) (33,206,772)
4 Other Rate Base Items (49,954,940) (36,920,995) (9,497,977) (216,163) (14,802) (3,305,004)
5 Total Rate Base 387,513,313$ 278,312,371$ 77,282,709$ 1,889,417$ 153,217$ 29,875,599$
6 Rate of Return Under Current ROR
7 Revenue at Current Rates
8 Gas Service Revenue 107,349,830$ 70,391,038$ 26,030,361$ 677,926$ 537,118$ 9,713,387$
9 Other Revenues 2,450,925 1,825,894 455,208 10,751 1,738 157,334
10 Total Revenue 109,800,755$ 72,216,932$ 26,485,569$ 688,677$ 538,856$ 9,870,721$
11 Expenses at Current Rates
12 O&M and A&G Expenses 55,245,881$ 42,832,979$ 9,357,577$ 209,613$ 53,188$ 2,792,524$
13 Depreciation and Amortization Expense 22,129,750 15,972,322 4,400,679 107,768 10,847 1,638,135
14 Taxes Other Than Income 6,439,884 4,633,021 1,297,843 32,101 7,001 469,918
15 Total Operating Expenses 83,815,515$ 63,438,322$ 15,056,099$ 349,481$ 71,035$ 4,900,577$
16 Earnings Before Interest and Taxes 25,985,240$ 8,778,610$ 11,429,470$ 339,196$ 467,821$ 4,970,144$
17 Current State/Federal Income Taxes 5,826,042$ 1,968,215$ 2,562,554$ 76,050$ 104,888$ 1,114,335$
18 Deferred Income Tax - - - - - -
19 Total Income Taxes 5,826,042$ 1,968,215$ 2,562,554$ 76,050$ 104,888$ 1,114,335$
20 Total Expenses at Current Rates 89,641,557$ 65,406,537$ 17,618,653$ 425,531$ 175,923$ 6,014,912$
21 Operating Income at Current Rates 20,159,198$ 6,810,395$ 8,866,916$ 263,146$ 362,933$ 3,855,809$
22 Current Rate of Return 5.20% 2.45% 11.47% 13.93% 236.88% 12.91%
23 Relative Rate of Return 1.00 0.47 2.21 2.68 45.53 2.48
24 Current Revenue to Cost Ratio 0.91 0.80 1.18 1.30 6.27 1.27
25 Current Parity Ratio 1.00 0.88 1.30 1.43 6.92 1.40
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 21 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 4 – Cost of Service and Rate of Return under Present and Proposed Rates
Line
No.Revenue Requirement Summary Total System Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
26 Rate of Return Under Equal ROR
27 Revenue Requirement Required Return at Equal Rates of Return
28 Required Return 7.37% 7.37% 7.37% 7.37% 7.37% 7.37%
29 Required Operating Income 28,559,731$ 20,511,622$ 5,695,736$ 139,250$ 11,292$ 2,201,832$
30 Expenses at Required Return
31 O&M and A&G Expenses 55,245,881$ 42,832,979$ 9,357,577$ 209,613$ 53,188$ 2,792,524$
32 Depreciation and Amortization Expense 22,129,750 15,972,322 4,400,679 107,768 10,847 1,638,135
33 Taxes Other Than Income 6,439,884 4,633,021 1,297,843 32,101 7,001 469,918
34 Total Operating Expenses 83,815,515$ 63,438,322$ 15,056,099$ 349,481$ 71,035$ 4,900,577$
35 Deferred Income Tax -$ -$ -$ -$ -$ -$
36 Current State/Federal Income Taxes 5,826,042 4,184,268 1,161,902 28,406 2,304 449,163
37 Income Taxes and Other 5,826,042$ 4,184,268$ 1,161,902$ 28,406$ 2,304$ 449,163$
38 Increase - Federal Income Tax 2,233,076$ 1,603,797$ 445,348$ 10,888$ 883$ 172,160$
39 Increase - State Utility Tax 654,723 470,223 130,573 3,192 259 50,476
40 Increase - Bad Debts 26,996 23,046 3,831 29 6 85
41 Increase - Annual Filing Fee 22,619 14,832 5,485 143 113 2,047
42 Revenue Increase Related Expenses 2,937,414$ 2,111,897$ 585,236$ 14,252$ 1,261$ 224,769$
43 Total Expenses at Required Return 92,578,971$ 69,734,487$ 16,803,237$ 392,139$ 74,599$ 5,574,508$
44 Total Revenue Requirement Required Return at Equal Rates of Return 121,138,702$ 90,246,109$ 22,498,973$ 531,389$ 85,891$ 7,776,340$
45 LESS
46 Current Miscellaneous Revenue Margin 2,450,925 1,825,894 455,208 10,751 1,738 157,334
47 Total Rate Margin at Equal Rates of Return 118,687,777$ 88,420,214$ 22,043,765$ 520,638$ 84,154$ 7,619,006$
48 Total Current Rate Margin 107,349,830$ 70,391,038$ 26,030,361$ 677,926$ 537,118$ 9,713,387$
49 Base Rate Margin (Deficiency)/Surplus (11,337,947)$ (18,029,176)$ 3,986,596$ 157,288$ 452,964$ 2,094,381$
50 Proposed Margin Increase 11,337,947$ 9,293,097$ 1,451,307$ 37,797$ 14,182$ 541,564$
51 Total Revenue Increase as Proposed 121,138,702$ 81,510,029$ 27,936,876$ 726,475$ 553,038$ 10,412,285$
52 Income Prior to Taxes 37,273,572$ 18,033,829$ 12,871,461$ 376,822$ 481,884$ 5,509,576$
53 Income Taxes and Other 8,713,841$ 6,258,288$ 1,737,822$ 42,486$ 3,445$ 671,799$
54 Proposed Operating Income 28,559,731$ 11,775,542$ 11,133,639$ 334,335$ 478,439$ 4,837,777$
55 Proposed Rate of Return 7.37% 4.23% 14.41% 17.70% 312.26% 16.19%
56 Relative Rate of Return 1.00 0.57 1.95 2.40 42.37 2.20
57 Proposed Revenue to Cost Ratio 1.00 0.90 1.24 1.37 6.44 1.34
58 Proposed Parity Ratio 1.00 0.90 1.24 1.37 6.44 1.34
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 22 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
1 RATE BASE
2 Plant in Service
3 Intangible Plant
4 Organization 301 2,506$ 1,789$ 502$ 13$ 1$ 201$
5 Franchises & Consents 302 429,487 306,545 86,116 2,176 132 34,517
6 Misc. Intangible Plant - Plant Related 303 11,659,883 8,322,213 2,337,916 59,079 3,596 937,080
7 Misc. Intangible Plant - Customer Related 303 - - - - - -
8 Misc. Intangible Plant - Labor Related 303 46,595,509 34,510,715 9,049,226 213,911 60,890 2,760,767
9 Subtotal - Intangible Plant 58,687,385$ 43,141,262$ 11,473,761$ 275,179$ 64,619$ 3,732,565$
10 Natural Gas Other Storage Plant
11 Land & Land Rights 360 292,588$ 153,525$ 67,798$ 3,399$ -$ 67,865$
12 Structures & improvement 361 10,211,065 5,357,897 2,366,092 118,636 - 2,368,440
13 Gas Holders 362 10,871,165 5,704,261 2,519,050 126,306 - 2,521,549
14 Purification Equipment 363 19,205,253 10,077,280 4,450,212 223,135 - 4,454,627
15 Subtotal - Natural Gas Other Storage Plant 40,580,071$ 21,292,963$ 9,403,152$ 471,476$ -$ 9,412,480$
16 Transmission plant
17 Land and Land Rights 365.1 782,865$ 410,781$ 181,404$ 9,096$ -$ 181,584$
18 Rights-of-Way 365.2 - - - - - -
19 Structures and improvements 366 77,152 40,483 17,878 896 - 17,895
20 Mains 367 69,918,045 36,687,032 16,201,302 812,337 - 16,217,374
21 Compressor station equipment 368 2,167,366 1,137,249 502,219 25,181 - 502,717
22 Measuring and regulating station equipment 369 - - - - - -
23 Communication equipment 370 714,440 374,877 165,549 8,301 - 165,713
24 Other equipment 371 - - - - - -
25 ARO for Transmission Plant 372 - - - - - -
26 Subtotal - Transmission plant 73,659,868$ 38,650,421$ 17,068,351$ 855,811$ -$ 17,085,284$
27 Distribution Plant
28 Land and land rights 374 2,120,601$ 1,567,513$ 321,541$ 11,125$ 20$ 220,402$
29 Structures and improvements 375 86,895 66,328 15,748 355 71 4,393
30 Mains 376 260,788,927 192,770,880 39,542,668 1,368,093 2,498 27,104,787
31 Compressor station equipment 377 - - - - - -
32 Measuring and regulating station equipment—general 378 13,262,760 9,803,614 2,010,994 69,576 127 1,378,449
33 Measuring and regulating station equipment—city gate check stations 379 97,219 71,863 14,741 510 1 10,104
34 Services 380 214,568,497 174,686,888 38,220,396 345,553 62,659 1,253,001
35 Meters 381 80,601,889 59,553,036 20,454,286 97,296 85,452 411,819
36 Meter installations 382 - - - - - -
37 House regulators 383 19,011,355 14,046,618 4,824,498 22,949 20,155 97,135
38 House regulatory installations 384 - - - - - -
39 Industrial measuring and regulating station equipment 385 13,277,094 - 12,100,406 395,518 50,452 730,717
40 Other property on customers' premises 386 - - - - - -
41 Other equipment 387 - - - - - -
42 Asset retirement costs for distribution plant 388 - - - - - -
43 Subtotal - Distribution Plant 603,815,237$ 452,566,741$ 117,505,276$ 2,310,976$ 221,437$ 31,210,808$ Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 23 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
44 General Plant
45 Land and Land Rights 389 3,598,925$ 2,568,724$ 721,618$ 18,235$ 1,110$ 289,238$
46 Structures and Improvements 390 26,123,545 18,645,616 5,238,015 132,364 8,056 2,099,494
47 Office Furniture and Equipment 391 6,475,232 4,795,846 1,257,543 29,727 8,462 383,655
48 Transportation Equipment 392 13,285,846 9,482,740 2,663,936 67,317 4,097 1,067,755
49 Stores Equipment 393 45,565 32,522 9,136 231 14 3,662
50 Tools, Shop, and Garage Equipment 394 8,470,948 6,046,118 1,698,504 42,921 2,612 680,792
51 Laboratory Equipment 395 - - - - - -
52 Power Operated Equipment 396 1,847,313 1,318,515 370,404 9,360 570 148,465
53 Communication Equipment 397 3,377,789 2,410,889 677,278 17,115 1,042 271,466
54 Misc. Equipment 398 21,290 15,196 4,269 108 7 1,711
55 Other Intangible Property 399 - - - - - -
56 ARO for General Plant 399.1 - - - - - -
57 Subtotal - General Plant 63,246,453$ 45,316,166$ 12,640,703$ 317,377$ 25,969$ 4,946,238$
58 Total Plant in Service 839,989,014$ 600,967,553$ 168,091,243$ 4,230,819$ 312,025$ 66,387,375$
59 Accumulated Provision for Depreciation & Amortization
60 Intangible Plant
61 Organization 301 (2,506)$ (1,789)$ (502)$ (13)$ (1)$ (201)$
62 Franchises & Consents 302 (429,487) (306,545) (86,116) (2,176) (132) (34,517)
63 Misc. Intangible Plant - Plant Related 303 (5,432,750) (3,877,612) (1,089,317) (27,527) (1,675) (436,619)
64 Misc. Intangible Plant - Customer Related 303 - - - - - -
65 Misc. Intangible Plant - Labor Related 303 (21,710,489) (16,079,758) (4,216,353) (99,669) (28,371) (1,286,339)
66 Subtotal - Intangible Plant (27,575,232)$ (20,265,704)$ (5,392,289)$ (129,385)$ (30,179)$ (1,757,675)$
67 Natural Gas Other Storage Plant
68 Land & Land Rights 360 -$ -$ -$ -$ -$ -$
69 Structures & improvement 361 (3,074,406) (1,613,186) (712,397) (35,720) - (713,103)
70 Gas Holders 362 (3,796,957) (1,992,319) (879,825) (44,115) - (880,698)
71 Purification Equipment 363 (9,401,006) (4,932,847) (2,178,387) (109,225) - (2,180,548)
72 Subtotal - Natural Gas Other Storage Plant (16,272,369)$ (8,538,353)$ (3,770,608)$ (189,059)$ -$ (3,774,349)$
73 Transmission plant
74 Land and Land Rights 365.1 (458,901)$ (240,792)$ (106,336)$ (5,332)$ -$ (106,441)$
75 Rights-of-Way 365.2 - - - - - -
76 Structures and improvements 366 (59,206) (31,066) (13,719) (688) - (13,733)
77 Mains 367 (49,147,989) (25,788,676) (11,388,496) (571,022) - (11,399,794)
78 Compressor station equipment 368 (570,780) (299,497) (132,260) (6,632) - (132,391)
79 Measuring and regulating station equipment 369 - - - - - -
80 Communication equipment 370 (751,405) (394,273) (174,114) (8,730) - (174,287)
81 Other equipment 371 - - - - - -
82 ARO for Transmission Plant 372 - - - - - -
83 Subtotal - Transmission plant (50,988,281)$ (26,754,305)$ (11,814,926)$ (592,403)$ -$ (11,826,647)$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 24 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
84 Distribution Plant
85 Land and land rights 374 (440,513)$ (325,620)$ (66,794)$ (2,311)$ (4)$ (45,784)$
86 Structures and improvements 375 (20,501) (15,649) (3,715) (84) (17) (1,037)
87 Mains 376 (118,437,511) (87,547,058) (17,958,336) (621,321) (1,135) (12,309,662)
88 Compressor station equipment 377 - - - - - -
89 Measuring and regulating station equipment—general 378 (3,263,649) (2,412,436) (494,858) (17,121) (31) (339,203)
90 Measuring and regulating station equipment—city gate check stations 379 559 413 85 3 0 58
91 Services 380 (116,439,054) (94,796,656) (20,740,914) (187,520) (34,003) (679,961)
92 Meters 381 (30,579,658) (22,593,906) (7,760,179) (36,913) (32,420) (156,240)
93 Meter installations 382 - - - - - -
94 House regulators 383 (6,900,827) (5,098,704) (1,751,218) (8,330) (7,316) (35,258)
95 House regulatory installations 384 - - - - - -
96 Industrial measuring and regulating station equipment 385 (7,373,388) - (6,719,918) (219,650) (28,019) (405,801)
97 Other property on customers' premises 386 - - - - - -
98 Other equipment 387 - - - - - -
99 Asset retirement costs for distribution plant 388 - - - - - -
100 Subtotal - Distribution Plant (283,454,542)$ (212,789,615)$ (55,495,847)$ (1,093,247)$ (102,945)$ (13,972,889)$
101 General Plant
102 Land and Land Rights 389 -$ -$ -$ -$ -$ -$
103 Structures and Improvements 390 (9,732,176) (6,946,317) (1,951,392) (49,311) (3,001) (782,154)
104 Office Furniture and Equipment 391 (3,415,517) (2,529,684) (663,321) (15,680) (4,463) (202,368)
105 Transportation Equipment 392 (5,137,199) (3,666,663) (1,030,056) (26,029) (1,584) (412,866)
106 Stores Equipment 393 (9,895) (7,063) (1,984) (50) (3) (795)
107 Tools, Shop, and Garage Equipment 394 (3,560,197) (2,541,082) (713,853) (18,039) (1,098) (286,125)
108 Laboratory Equipment 395 - - - - - -
109 Power Operated Equipment 396 (612,161) (436,928) (122,744) (3,102) (189) (49,198)
110 Communication Equipment 397 (1,750,656) (1,249,526) (351,023) (8,870) (540) (140,697)
111 Misc. Equipment 398 (12,536) (8,948) (2,514) (64) (4) (1,007)
112 Other Intangible Property 399 - - - - - -
113 ARO for General Plant 399.1 - - - - - -
114 Subtotal - General Plant (24,230,337)$ (17,386,211)$ (4,836,887)$ (121,145)$ (10,882)$ (1,875,211)$
115 Amortization
116 Intangible Plant 111 -$ -$ -$ -$ -$ -$
117 Production Plant 111 - - - - - -
118 Natural gas storage and processing plant 111 - - - - - -
119 Transmission plant 111 - - - - - -
120 Distribution plant 111 - - - - - -
121 General plant 111 - - - - - -
122 Subtotal - Amortization -$ -$ -$ -$ -$ -$
123 Total Accumulated Provision for Depreciation & Amortization (402,520,761)$ (285,734,187)$ (81,310,557)$ (2,125,239)$ (144,006)$ (33,206,772)$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 25 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
124 Other Rate Base Items
125 Natural gas plant acquisition adjustments 114 -$ -$ -$ -$ -$ -$
126 Accumulated provision for asset acquisition adjustments 115 - - - - - -
127 Materials And Supplies 154 6,477,488 4,623,291 1,298,797 32,820 1,998 520,582
128 Stores Expense Undistributed 163 - - - - - -
129 Gas Stored Underground - PA 164.1 - - - - - -
130 LNG Inventory 164.2 3,072,269 1,612,065 711,901 35,695 - 712,608
131 Prepayments 165 - - - - - -
132 Other regulatory assets 182.3 - - - - - -
133 Miscellaneous deferred debits 186 - - - - - -
134 Accumulated deferred income taxes 190 - - - - - -
135 Accumulated provision for property insurance 228.1 - - - - - -
136 Accumulated provision for injuries and damages 228.2 - - - - - -
137 Accumulated provision for pensions and benefits 228.3 - - - - - -
138 Accumulated miscellaneous operating provisions 228.4 - - - - - -
139 Accumulated provision for rate refunds 229 - - - - - -
140 Asset retirement obligations 230 - - - - - -
141 Customer deposits 235 - - - - - -
142 Other deferred credits 253 - - - - - -
143 Accumulated deferred income taxes—accelerated amortization property 281 - - - - - -
144 Accumulated deferred income taxes—Storage Plant 282.1 (2,499,689) (1,311,624) (579,224) (29,042) - (579,799)
145 Accumulated deferred income taxes—Transmission Plant 282.2 (4,537,370) (2,380,825) (1,051,392) (52,717) - (1,052,435)
146 Accumulated deferred income taxes—Distribution Plant 282.3 (37,194,379) (27,877,632) (7,238,201) (142,354) (13,640) (1,922,553)
147 Accumulated deferred income taxes—General Plant 282.4 (3,895,915) (2,791,428) (778,654) (19,550) (1,600) (304,683)
148 Accumulated deferred income taxes—other 283 - - - - - -
149 Accumulated deferred investment tax credits 255 - - - - - -
150 Customer advances for construction 252 (11,377,344) (8,794,842) (1,861,204) (41,015) (1,560) (678,724)
151 Other regulatory liabilities 254 - - - - - -
152 Working capital allowance N/A - - - - - -
153 Subtotal - Other Rate Base Items (49,954,940)$ (36,920,995)$ (9,497,977)$ (216,163)$ (14,802)$ (3,305,004)$
154 TOTAL RATE BASE 387,513,313$ 278,312,371$ 77,282,709$ 1,889,417$ 153,217$ 29,875,599$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 26 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
155 OPERATION AND MAINTENANCE EXPENSE
156 Production, Storage, LNG, Transmission, and Distribution Expense
157 Other Gas Supply Expenses
158 Natural gas well head purchases 800 -$ -$ -$ -$ -$ -$
159 Natural gas well head purchases, intracompany transfers 800.1 - - - - - -
160 Natural gas field line purchases 801 - - - - - -
161 Natural gas gasoline plant outlet purchases 802 - - - - - -
162 Natural gas transmission line purchases 803 - - - - - -
163 Natural gas city gate purchases 804 - - - - - -
164 Liquefied natural gas purchases 804.1 - - - - - -
165 Other gas purchases 805 - - - - - -
166 Purchased gas cost adjustments 805.1 - - - - - -
167 Exchange gas 806 - - - - - -
168 Well expenses—Purchased gas. 807.1 - - - - - -
169 Operation of purchased gas measuring stations. 807.2 - - - - - -
170 Maintenance of purchased gas measuring stations. 807.3 - - - - - -
171 Purchased gas calculations expenses. 807.4 - - - - - -
172 Other purchased gas expenses. 807.5 - - - - - -
173 Gas withdrawn from storage—debit 808.1 - - - - - -
174 Gas delivered to storage—credit 808.2 - - - - - -
175 Withdrawals of liquefied natural gas held for processing—debt 809.1 - - - - - -
176 Deliveries of natural gas for processing—credit 809.2 - - - - - -
177 Gas used for compressor station fuel—credit 810 - - - - - -
178 Gas used for products extraction—credit 811 - - - - - -
179 Other gas supply expenses - Gas Supply 813.1 301,989 105,401 48,621 8,822 7,241 131,904
180 Other gas supply expenses 813 67,802 61,896 5,882 6 1 17
181 Subtotal - Other Gas Supply Expenses 369,791$ 167,297$ 54,504$ 8,828$ 7,242$ 131,921$
182 Other Storage Expenses - Operation
183 Operation supervision and engineering 840 960$ 504$ 223$ 11$ -$ 223$
184 Operation labor and expenses 841 647,172 339,581 149,962 7,519 - 150,111
185 Rents 842 - - - - - -
186 Fuel 842.1 124,132 65,134 28,764 1,442 - 28,792
187 Power 842.2 109,214 57,306 25,307 1,269 - 25,332
188 Gas losses 842.3 - - - - - -
189 Subtotal - Other Storage Expenses - Operation 881,479$ 462,525$ 204,255$ 10,241$ -$ 204,458$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 27 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
190 Other Storage Expenses - Maintenance
191 Maintenance supervision and engineering 843.1 -$ -$ -$ -$ -$ -$
192 Maintenance of structures and improvements 843.2 1,525 800 353 18 - 354
193 Maintenance of gas holders 843.3 299 157 69 3 - 69
194 Maintenance of purification equipment 843.4 1,761 924 408 20 - 409
195 Maintenance of liquefaction equipment 843.5 64,944 34,077 15,049 755 - 15,064
196 Maintenance of vaporizing equipment 843.6 109,460 57,435 25,364 1,272 - 25,389
197 Maintenance of compressor equipment 843.7 28,919 15,174 6,701 336 - 6,708
198 Maintenance of measuring and regulating equipment 843.8 - - - - - -
199 Maintenance of other equipment 843.9 30,000 15,741 6,951 349 - 6,958
200 Subtotal - Other Storage Expenses - Maintenance 236,909$ 124,310$ 54,896$ 2,753$ -$ 54,951$
201 Transmission Operation Expenses
202 Operation supervision and engineering 850 -$ -$ -$ -$ -$ -$
203 System control and load dispatching 851 - - - - - -
204 Communication system expenses 852 27,314 14,332 6,329 317 - 6,335
205 Compressor station labor and expenses 853 86,348 45,308 20,008 1,003 - 20,028
206 Gas for compressor station fuel 854 - - - - - -
207 Other fuel and power for compressor stations 855 - - - - - -
208 Mains expenses 856 1,885 989 437 22 - 437
209 Measuring and regulating station expenses 857 - - - - - -
210 Transmission and compression of gas by others 858 - - - - - -
211 Other expenses 859 - - - - - -
212 Rents 860 - - - - - -
213 Subtotal - Transmission Operation Expenses 115,547$ 60,629$ 26,774$ 1,342$ -$ 26,801$
214 Transmission Maintenance Expenses
215 Maintenance supervision and engineering 861 -$ -$ -$ -$ -$ -$
216 Maintenance of structures and improvements 862 - - - - - -
217 Maintenance of mains 863 17,387 9,123 4,029 202 - 4,033
218 Transmission Mains - Pipeline Integrity 863.1 28,262 14,829 6,549 328 - 6,555
219 Maintenance of compressor station equipment 864 - - - - - -
220 Maintenance of measuring and regulating station equipment 865 - - - - - -
221 Maintenance of communication equipment 866 133,623 70,114 30,963 1,552 - 30,994
222 Maintenance of other equipment 867 - - - - - -
223 Subtotal - Transmission Maintenance Expenses 179,272$ 94,066$ 41,541$ 2,083$ -$ 41,582$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 28 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
224 Distribution Operation Expenses
225 Operation supervision and engineering 870 4,317,916$ 3,232,126$ 839,334$ 18,807$ 5,215$ 222,435$
226 Operation supervision and engineering- Gas Supply and Control 870.1 62,783 21,913 10,108 1,834 1,505 27,423
227 Distribution load dispatching 871 253,255 88,392 40,775 7,398 6,072 110,618
228 Compressor station fuel and power (major only) 873 - - - - - -
229 Mains and services expenses 874 4,725,499 3,652,875 773,038 17,035 648 281,903
230 Measuring and regulating station expenses—general 875 437,602 323,468 66,352 2,296 4 45,482
231 Measuring and regulating station expenses—industrial 876 330,316 - 301,042 9,840 1,255 18,179
232 Measuring and regulating station expenses—city gate check stations 877 - - - - - -
233 Meter and house regulator expenses 878 1,633,964 1,207,261 414,650 1,972 1,732 8,348
234 Meter and house regulator expenses - installation credits 878.3 (1,833,969) (1,355,035) (465,405) (2,214) (1,944) (9,370)
235 Customer installations expenses 879 2,404,356 2,194,901 208,601 204 42 607
236 Other expenses 880 4,819,166 3,612,022 937,832 18,444 1,767 249,099
237 Rents 881 241,488 180,763 46,941 1,052 292 12,440
238 Subtotal - Distribution Operation Expenses 17,392,377$ 13,158,686$ 3,173,269$ 76,668$ 16,588$ 967,165$
239 Distribution Maintenance Expenses
240 Maintenance supervision and engineering 885 252,408$ 194,732$ 48,156$ 711$ 97$ 8,712$
241 Maintenance of structures and improvements 886 - - - - - -
242 Maintenance of mains 887 1,559,102 1,152,463 236,402 8,179 15 162,043
243 Distribution Mains - Pipeline Integrity 887.1 90,461 66,867 13,716 475 1 9,402
244 Maintenance of compressor station equipment 888 - - - - - -
245 Maintenance of measuring and regulating station equipment—general 889 577,682 427,013 87,592 3,031 6 60,041
246 Maintenance of measuring and regulating station equipment—industrial 890 122,251 - 111,416 3,642 465 6,728
247 Maintenance of measuring and regulating station equipment—city gate 891 - - - - - -
248 Maintenance of services 892 3,159,609 2,572,336 562,811 5,088 923 18,451
249 Maintenance of meters and house regulators 893 1,235,301 912,708 313,482 1,491 1,310 6,312
250 Maintenance of other equipment 894 569,681 439,508 108,687 1,605 219 19,662
251 Subtotal - Distribution Maintenance Expenses 7,566,497$ 5,765,627$ 1,482,263$ 24,221$ 3,034$ 291,351$
252 Total Production, Storage, LNG, Transmission, and Distribution Expense 26,741,871$ 19,833,141$ 5,037,502$ 126,137$ 26,864$ 1,718,227$
253 Customer Accounts, Service, and Sales Expense
254 Customer Account
255 Supervision 901 177,085$ 161,050$ 15,930$ 25$ 5$ 75$
256 Meter reading expenses 902 1,078,574 984,615 93,577 91 19 272
257 Customer records and collection expenses 903 7,216,280 6,587,637 626,082 612 125 1,823
258 Uncollectible accounts 904 510,784 436,041 72,479 541 111 1,612
259 Miscellaneous customer accounts expenses 905 - - - - - -
260 Subtotal - Customer Account 8,982,723$ 8,169,343$ 808,069$ 1,270$ 260$ 3,782$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 29 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
261 Customer Service & Information Expenses
262 Supervision 907 -$ -$ -$ -$ -$ -$
263 Customer assistance expenses 908 835,629 762,834 72,499 71 14 211
264 Informational and instructional advertising expenses 909 126,903 115,848 11,010 11 2 32
265 Miscellaneous customer service and informational expenses 910 - - - - - -
266 Subtotal - Customer Service & Information Expenses 962,532$ 878,681$ 83,509$ 82$ 17$ 243$
267 Sales Expenses
268 Supervision 911 231,731$ 211,544$ 20,105$ 20$ 4$ 59$
269 Demonstrating and selling expenses 912 1,241,710 1,133,539 107,730 105 22 314
270 Advertising expenses 913 40,610 37,072 3,523 3 1 10
271 Miscellaneous sales expenses 916 - - - - - -
272 Subtotal - Sales Expenses 1,514,051$ 1,382,155$ 131,359$ 128$ 26$ 383$
273 Total Customer Accounts, Service, and Sales Expense 11,459,306$ 10,430,179$ 1,022,936$ 1,480$ 302$ 4,408$
274 Administrative and General Expenses
275 Administrative and general salaries 920 6,169,823$ 4,569,647$ 1,198,230$ 28,325$ 8,063$ 365,560$
276 Administrative and general salaries - Gas Supply and Control 920.1 164,929 57,564 26,554 4,818 3,954 72,038
277 Office supplies and expenses 921 5,722,640 4,238,443 1,111,383 26,272 7,478 339,064
278 Outside services employed 923 596,622 441,885 115,869 2,739 780 35,350
279 Property insurance 924 122,539 87,670 24,521 617 46 9,685
280 Injuries and damages 925 1,221,147 904,436 237,157 5,606 1,596 72,353
281 Employee pensions and benefits 926 1,594,449 1,180,920 309,655 7,320 2,084 94,471
282 Franchise requirements 927 - - - - - -
283 Regulatory commission expenses 928 118,537 77,727 28,743 749 593 10,726
284 Duplicate charges—Credit 929 - - - - - -
285 General advertising expenses 930.1 78,048 71,249 6,771 7 1 20
286 Miscellaneous general expenses 930.2 436,330 333,057 79,075 1,782 356 22,061
287 Rents 931 819,634 607,058 159,180 3,763 1,071 48,563
288 Maintenance of general plant 935 4 3 1 0 0 0
289 Subtotal - Administrative and General Expenses 17,044,704$ 12,569,659$ 3,297,139$ 81,996$ 26,021$ 1,069,889$
290 TOTAL OPERATION AND MAINTENANCE EXPENSE 55,245,881$ 42,832,979$ 9,357,577$ 209,613$ 53,188$ 2,792,524$
291 Adjustments, Depreciation and Amortization Expense
292 Depreciation Expense
293 Depreciation expense intangible plant 403.1 4,703,175$ 3,457,317$ 919,501$ 22,053$ 5,179$ 299,126$
294 Depreciation expense storage and terminaling 403.2 1,112,919 583,965 257,884 12,930 - 258,140
295 Depreciation expense transmission 403.3 1,064,501 558,559 246,664 12,368 - 246,909
296 Depreciation expense distribution 403.4 13,524,126 10,136,494 2,631,858 51,761 4,960 699,053
297 Depreciation expense general plant 403.5 1,725,030 1,235,987 344,772 8,656 708 134,907
298 Subtotal - Depreciation Expense 22,129,750$ 15,972,322$ 4,400,679$ 107,768$ 10,847$ 1,638,135$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 30 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 5 - Cost of Service Allocation Study Detail by Account
Line
No.Account Description FERC Account Account Balance Residential Service General Service Large Volume
Transport Service
(Interruptible)
Transport Service
(Firm)
299 Amortization Expense
300 Amortization and depletion of producing natural gas land and land 404.1 - - - - - -
301 Amortization of underground storage land and land rights 404.2 - - - - - -
302 Amortization of other limited-term gas plant 404.3 - - - - - -
303 Amortization of other gas plant 405 - - - - - -
304 Amortization of gas plant acquisition adjustments 406 - - - - - -
305 Amortization of property losses, unrecovered plant and regulatory 407.1 - - - - - -
306 Amortization of conversion expense 407.2 - - - - - -
307 Subtotal - Amortization Expense - - - - - -
308 Total Adjustments, Depreciation and Amortization Expense 22,129,750$ 15,972,322$ 4,400,679$ 107,768$ 10,847$ 1,638,135$
309 Taxes
310 Taxes Other Than Income Taxes
311 Taxes Other Than Income Taxes - Payroll 408.1 2,282,838$ 1,690,772$ 443,346$ 10,480$ 2,983$ 135,257$
312 Taxes Other Than Income Taxes - Property 408.2 3,623,049 2,592,099 725,013 18,248 1,346 286,343
313 Taxes Other Than Income Taxes - Franchise 408.3 13,950 9,147 3,383 88 70 1,262
314 Taxes Other Than Income Taxes - IPUC Fee 408.4 520,047 341,003 126,102 3,284 2,602 47,056
315 Subtotal - Taxes Other Than Income Taxes 6,439,884$ 4,633,021$ 1,297,843$ 32,101$ 7,001$ 469,918$
316 Income Taxes
317 Income Taxes - federal taxes utility operating income 409.1 5,054,746$ 3,630,323$ 1,008,080$ 24,646$ 1,999$ 389,699$
318 Income Taxes - state taxes utility operating income 409.1 771,296 553,945 153,821 3,761 305 59,464
319 Income Taxes - other taxes utility operating income 410.1 - - - - - -
320 Provision for deferred income taxes—credit, utility operating income 411.1 - - - - - -
321 Investment Tax credit Adj. 411.4 - - - - - -
322 Subtotal - Income Taxes 5,826,042$ 4,184,268$ 1,161,902$ 28,406$ 2,304$ 449,163$
323 Total Taxes 12,265,926$ 8,817,289$ 2,459,744$ 60,507$ 9,304$ 919,081$
324 REVENUE REQUIREMENT AT EQUAL RATES OF RETURN
325 Test Year Expenses at Current Rates 89,641,557$ 67,622,590$ 16,218,001$ 377,888$ 73,339$ 5,349,740$
326 Return on Rate Base 28,559,731$ 20,511,622$ 5,695,736$ 139,250$ 11,292$ 2,201,832$
327 Gross Up Items - - - - -
328 Federal Income Tax 2,233,076$ 1,603,797$ 445,348$ 10,888$ 883$ 172,160$
329 State Income Tax 654,723 470,223 130,573 3,192 259 50,476
330 Uncollectible Account - Increase 26,996 23,046 3,831 29 6 85
331 Taxes Other Than Income Taxes - IPUC Fee 22,619 14,832 5,485 143 113 2,047
332 TOTAL REVENUE REQUIREMENT AT EQUAL RATES OF RETURN 121,138,702$ 90,246,109$ 22,498,973$ 531,389$ 85,891$ 7,776,340$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 31 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 6 - Functionalized and Classified Rate Base and Revenue Requirement, and Unit Costs by Customer Class
Line Description TOTAL Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
1 Functional Rate Base
2 Storage
3 Demand 28,145,723$ 14,768,477$ 6,521,884$ 327,009$ -$ 6,528,354$
4 Commodity - - - - - -
5 Customer - - - - - -
6 Subtotal 28,145,723$ 14,768,477$ 6,521,884$ 327,009$ -$ 6,528,354$
7 Transmission
8 Demand 22,994,119$ 12,065,354$ 5,328,162$ 267,155$ -$ 5,333,448$
9 Commodity - - - - - -
10 Customer - - - - - -
11 Subtotal 22,994,119$ 12,065,354$ 5,328,162$ 267,155$ -$ 5,333,448$
12 Distribution
13 Demand 156,337,840$ 115,562,357$ 23,705,053$ 820,145$ 1,498$ 16,248,788$
14 Commodity - - - - - -
15 Customer 6,635,543 4,359,288 1,673,239 54,799 29,842 518,376
16 Subtotal 162,973,383$ 119,921,645$ 25,378,291$ 874,944$ 31,340$ 16,767,163$
17 Customer
18 Demand -$ -$ -$ -$ -$ -$
19 Commodity - - - - - -
20 Customer 173,400,088 131,556,895 40,054,372 420,309 121,877 1,246,634
21 Subtotal 173,400,088$ 131,556,895$ 40,054,372$ 420,309$ 121,877$ 1,246,634$
22 Total
23 Demand 207,477,682$ 142,396,188$ 35,555,098$ 1,414,309$ 1,498$ 28,110,589$
24 Commodity - - - - - -
25 Customer 180,035,631 135,916,183 41,727,611 475,108 151,719 1,765,010
26 TOTAL RATE BASE 387,513,313$ 278,312,371$ 77,282,709$ 1,889,417$ 153,217$ 29,875,599$
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 32 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 6 - Functionalized and Classified Rate Base and Revenue Requirement, and Unit Costs by Customer Class
Line Description TOTAL Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
27 Functional Revenue Requirement
28 Storage
29 Demand 5,862,968$ 3,076,386$ 1,358,558$ 68,118$ -$ 1,359,906$
30 Commodity - - - - - -
31 Customer - - - - - -
32 Subtotal 5,862,968$ 3,076,386$ 1,358,558$ 68,118$ -$ 1,359,906$
33 Transmission
34 Demand 4,375,009$ 2,295,632$ 1,013,770$ 50,831$ -$ 1,014,776$
35 Commodity - - - - - -
36 Customer - - - - - -
37 Subtotal 4,375,009$ 2,295,632$ 1,013,770$ 50,831$ -$ 1,014,776$
38 Distribution
39 Demand 39,444,861$ 29,156,992$ 5,980,910$ 206,927$ 378$ 4,099,655$
40 Commodity - - - - - -
41 Customer 12,472,938 8,355,536 3,105,063 94,456 50,268 867,616
42 Subtotal 51,917,799$ 37,512,527$ 9,085,972$ 301,383$ 50,646$ 4,967,270$
43 Customer
44 Demand -$ -$ -$ -$ -$ -$
45 Commodity - - - - - -
46 Customer 58,982,926 47,361,563 11,040,672 111,058 35,246 434,388
47 Subtotal 58,982,926$ 47,361,563$ 11,040,672$ 111,058$ 35,246$ 434,388$
48 Total
49 Demand 49,682,838$ 34,529,010$ 8,353,238$ 325,876$ 378$ 6,474,337$
50 Commodity - - - - - -
51 Customer 71,455,864 55,717,099 14,145,735 205,513 85,514 1,302,003
52
TOTAL REVENUE REQUIREMENT AT EQUAL
RATES OF RETURN
121,138,702$ 90,246,109$ 22,498,973$ 531,389$ 85,891$ 7,776,340$
53 Demand 41.01% 38.26% 37.13% 61.33% 0.44% 83.26%
54 Energy 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%
55 Customer 58.99% 61.74% 62.87% 38.67% 99.56% 16.74%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 33 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 6 - Functionalized and Classified Rate Base and Revenue Requirement, and Unit Costs by Customer Class
Line Description TOTAL Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
56 Unit Costs
57 Storage
58 Demand 0.08$ 0.08$ 0.08$ 0.08$ -$ 0.08$
59 Commodity -$ -$ -$ -$ -$ -$
60 Customer -$ -$ -$ -$ -$ -$
61 Transmission
62 Demand 0.06$ 0.06$ 0.06$ 0.06$ -$ 0.06$
63 Commodity -$ -$ -$ -$ -$ -$
64 Customer -$ -$ -$ -$ -$ -$
65 Distribution
66 Demand 0.51$ 0.72$ 0.34$ 0.23$ -$ 0.23$
67 Commodity -$ -$ -$ -$ -$ -$
68 Customer 2.57$ 1.89$ 7.39$ 229.82$ 598.43$ 708.84$
69 Customer
70 Demand -$ -$ -$ -$ -$ -$
71 Commodity -$ -$ -$ -$ -$ -$
72 Customer 12.17$ 10.71$ 26.27$ 270.21$ 419.59$ 354.89$
73 Total
74 Commodity -$ -$ -$ -$ -$ -$
75 Customer (per cust month) 14.75$ 12.60$ 33.65$ 500.03$ 1,018.02$ 1,063.73$
76 Demand & Customer (per cust month) 25.00$ 20.40$ 53.53$ 1,292.92$ 1,022.52$ 6,353.22$
77 Demand (per MDFQ) 0.36$ 0.36$
78 BILLING DETERMINANTS
79 Demand (Peak Day Demand * 12) 76,848,665 40,323,630 17,807,254 892,860 0 17,824,920
80 Commodity 805,130,573 282,522,986 138,067,893 13,566,644 41,523,144 329,449,906
81 Customers (Number of Bills) 4,844,910 4,422,848 420,343 411 84 1,224
82 Demand 19,013,507 903,088 18,110,419
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 34 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 7 – Alternative Cost of Service and Rate of Return under Present and Proposed Rates
Line
No.Revenue Requirement Summary Total System Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
1 Rate Base
2 Plant in Service 839,989,014$ 598,517,569$ 167,024,168$ 4,174,370$ 5,012,456$ 65,260,451$
3 Accumulated Reserve (402,520,761) (284,507,567) (80,776,311) (2,096,977) (2,497,346) (32,642,561)
4 Other Rate Base Items (49,954,940) (36,798,682) (9,444,704) (213,345) (249,466) (3,248,743)
5 Total Rate Base 387,513,313$ 277,211,320$ 76,803,153$ 1,864,049$ 2,265,644$ 29,369,147$
6 Rate of Return Under Current ROR
7 Revenue at Current Rates
8 Gas Service Revenue 107,349,830$ 70,391,038$ 26,030,361$ 677,926$ 537,118$ 9,713,387$
9 Other Revenues 2,450,925 1,820,764 452,973 10,633 11,581 154,974
10 Total Revenue 109,800,755$ 72,211,802$ 26,483,334$ 688,559$ 548,699$ 9,868,361$
11 Expenses at Current Rates
12 O&M and A&G Expenses 55,245,881$ 42,757,743$ 9,324,809$ 207,879$ 197,532$ 2,757,918$
13 Depreciation and Amortization Expense 22,129,750 15,913,889 4,375,229 106,422 122,954 1,611,257
14 Taxes Other Than Income 6,439,884 4,619,025 1,291,747 31,778 33,853 463,480
15 Total Operating Expenses 83,815,515$ 63,290,657$ 14,991,785$ 346,079$ 354,339$ 4,832,655$
16 Earnings Before Interest and Taxes 25,985,240$ 8,921,145$ 11,491,550$ 342,480$ 194,360$ 5,035,706$
17 Current State/Federal Income Taxes 5,826,042$ 2,000,173$ 2,576,472$ 76,786$ 43,577$ 1,129,035$
18 Deferred Income Tax - - - - - -
19 Total Income Taxes 5,826,042$ 2,000,173$ 2,576,472$ 76,786$ 43,577$ 1,129,035$
20 Total Expenses at Current Rates 89,641,557$ 65,290,829$ 17,568,257$ 422,865$ 397,916$ 5,961,690$
21 Operating Income at Current Rates 20,159,198$ 6,920,972$ 8,915,077$ 265,694$ 150,783$ 3,906,671$
22 Current Rate of Return 5.20% 2.50% 11.61% 14.25% 6.66% 13.30%
23 Relative Rate of Return 1.00 0.48 2.23 2.74 1.28 2.56
24 Current Revenue to Cost Ratio 0.91 0.80 1.18 1.31 0.96 1.29
25 Current Parity Ratio 1.00 0.89 1.31 1.45 1.06 1.42
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 35 of 36
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Schedule 7 – Alternative Cost of Service and Rate of Return under Present and Proposed Rates
Line
No.Revenue Requirement Summary Total System Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
26 Rate of Return Under Equal ROR
27 Revenue Requirement Required Return at Equal Rates of Return
28 Required Return 7.37% 7.37% 7.37% 7.37% 7.37% 7.37%
29 Required Operating Income 28,559,731$ 20,430,474$ 5,660,392$ 137,380$ 166,978$ 2,164,506$
30 Expenses at Required Return
31 O&M and A&G Expenses 55,245,881$ 42,757,743$ 9,324,809$ 207,879$ 197,532$ 2,757,918$
32 Depreciation and Amortization Expense 22,129,750 15,913,889 4,375,229 106,422 122,954 1,611,257
33 Taxes Other Than Income 6,439,884 4,619,025 1,291,747 31,778 33,853 463,480
34 Total Operating Expenses 83,815,515$ 63,290,657$ 14,991,785$ 346,079$ 354,339$ 4,832,655$
35 Deferred Income Tax -$ -$ -$ -$ -$ -$
36 Current State/Federal Income Taxes 5,826,042 4,167,714 1,154,692 28,025 34,063 441,548
37 Income Taxes and Other 5,826,042$ 4,167,714$ 1,154,692$ 28,025$ 34,063$ 441,548$
38 Increase - Federal Income Tax 2,233,076$ 1,597,452$ 442,584$ 10,742$ 13,056$ 169,242$
39 Increase - State Utility Tax 654,723 468,362 129,763 3,149 3,828 49,621
40 Increase - Bad Debts 26,996 23,046 3,831 29 6 85
41 Increase - Annual Filing Fee 22,619 14,832 5,485 143 113 2,047
42 Revenue Increase Related Expenses 2,937,414$ 2,103,692$ 581,662$ 14,063$ 17,003$ 220,994$
43 Total Expenses at Required Return 92,578,971$ 69,562,063$ 16,728,139$ 388,167$ 405,405$ 5,495,198$
44 Total Revenue Requirement Required Return at Equal Rates of Return 121,138,702$ 89,992,537$ 22,388,531$ 525,547$ 572,383$ 7,659,704$
45 LESS
46 Current Miscellaneous Revenue Margin 2,450,925 1,820,764 452,973 10,633 11,581 154,974
47 Total Rate Margin at Equal Rates of Return 118,687,777$ 88,171,773$ 21,935,558$ 514,914$ 560,802$ 7,504,730$
48 Total Current Rate Margin 107,349,830$ 70,391,038$ 26,030,361$ 677,926$ 537,118$ 9,713,387$
49 Base Rate Margin (Deficiency)/Surplus (11,337,947)$ (17,780,735)$ 4,094,803$ 163,012$ (23,684)$ 2,208,657$
50 Proposed Margin Increase 11,337,947$ 9,293,097$ 1,451,307$ 37,797$ 14,182$ 541,564$
51 Total Revenue Increase as Proposed 121,138,702$ 81,504,898$ 27,934,641$ 726,356$ 562,881$ 10,409,925$
52 Income Prior to Taxes 37,273,572$ 18,176,364$ 12,933,541$ 380,106$ 208,423$ 5,575,138$
53 Income Taxes and Other 8,713,841$ 6,233,529$ 1,727,039$ 41,916$ 50,947$ 660,411$
54 Proposed Operating Income 28,559,731$ 11,942,835$ 11,206,503$ 338,190$ 157,476$ 4,914,727$
55 Proposed Rate of Return 7.37% 4.31% 14.59% 18.14% 6.95% 16.73%
56 Relative Rate of Return 1.00 0.58 1.98 2.46 0.94 2.27
57 Proposed Revenue to Cost Ratio 1.00 0.91 1.25 1.38 0.98 1.36
58 Proposed Parity Ratio 1.00 0.91 1.25 1.38 0.98 1.36
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 2
Page 36 of 36
Preston N. Carter ISB No. 8462
Morgan D. Goodin ISB No. 11184
Blake W. Ringer ISB No. 11223
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
[e-mail]
Attorneys for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF INTERMOUNTAIN GAS COMPANY.
FOR AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR NATURAL
GAS SERVICE IN THE STATE OF IDAHO
CASE NO. INT-G-22-07
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
EXHIBIT 3 TO ACCOMPANY THE
DIRECT TESTIMONY OF RONALD J. AMEN
Intermountain Gas Company
Gas Class Cost of Service Study
Test Year Ended December 31, 2022
Exhibit 3 – Proposed Revenue Targets
Line
No.Description Total System Residential Service General Service Large Volume
Transport
Service
(Interruptible)
Transport
Service
(Firm)
1 Total Rate Base 387,513,313$ 278,312,371$ 77,282,709$ 1,889,417$ 153,217$ 29,875,599$
2 Gas Service Revenue 107,349,830$ 70,391,038$ 26,030,361$ 677,926$ 537,118$ 9,713,387$
3 Other Revenues 2,450,925 1,825,894 455,208 10,751 1,738 157,334
4 Total Revenue 109,800,755$ 72,216,932$ 26,485,569$ 688,677$ 538,856$ 9,870,721$
5 Current Revenue to Cost Ratio 0.91 0.80 1.18 1.30 6.27 1.27
6 Current Parity Ratio 1.00 0.88 1.30 1.43 6.92 1.40
7 Scenario A: Revenues at Equalized Rates of Return
8 Revenue Increase/(Decrease) 11,337,947$ 18,029,176$ (3,986,596)$ (157,288)$ (452,964)$ (2,094,381)$
9 Total Rate Revenue at Equalized Rates of Return 118,687,777 88,420,214 22,043,765 520,638 84,154 7,619,006
10 Other Revenues 2,450,925 1,825,894 455,208 10,751 1,738 157,334
11 Total Revenue at Equalized Rates of Return 121,138,702$ 90,246,109$ 22,498,973$ 531,389$ 85,891$ 7,776,340$
12 % Increase of Total Revenues 10.33% 24.97% -15.05% -22.84% -84.06% -21.22%
13 % Increase of Margin Revenues 10.56% 25.61% -15.32% -23.20% -84.33% -21.56%
14 Resulting Revenue to Cost Ratio 1.00 1.00 1.00 1.00 1.00 1.00
15 Resulting Parity Ratio 1.00 1.00 1.00 1.00 1.00 1.00
16 Scenario B: Equal Percentage Increase on Gas Service Revenue
17 Percent Increase 10.56%10.56%10.56%10.56%10.56%10.56%
18 Revenue Increase/(Decrease) 11,337,947$ 7,434,477$ 2,749,244$ 71,600$ 56,729$ 1,025,897$
19 Total Rate Revenue 118,687,777 77,825,515 28,779,605 749,526 593,847 10,739,284
20 Other Revenues 2,450,925 1,825,894 455,208 10,751 1,738 157,334
21 Total Revenue at Equal Percentage Increase 121,138,702$ 79,651,409$ 29,234,813$ 760,278$ 595,584$ 10,896,618$
22 Resulting Revenue to Cost Ratio 1.00 0.88 1.30 1.43 6.93 1.40
23 Resulting Parity Ratio 1.00 0.88 1.30 1.43 6.93 1.40
24 Proposed Scenario C: Moderated based on the Current Parity Ratio
25 Multiple of System Increase 1.25 0.53 0.53 0.25 0.53
26 Percent Increase 13.20% 5.58% 5.58% 2.64% 5.58%
27 Revenue Increase/(Decrease)11,337,947$ 9,293,097$ 1,451,307$ 37,797$ 14,182$ 541,564$
28 Total Rate Revenue 118,687,777 79,684,135 27,481,668 715,723 551,300 10,254,951
29 Other Revenues 2,450,925 1,825,894 455,208 10,751 1,738 157,334
30 Total Revenue at Proposed 121,138,702$ 81,510,029$ 27,936,876$ 726,475$ 553,038$ 10,412,285$
31 Base Rate Margin at Proposed 118,687,777$ 79,684,135$ 27,481,668$ 715,723$ 551,300$ 10,254,951$
32 Percent Increase on Base Rate Margin 10.56% 13.20% 5.58% 5.58% 2.64% 5.58%
33 Proposed Revenue to Cost Ratio 1.00 0.90 1.24 1.37 6.44 1.34
34 Proposed Parity Ratio 1.00 0.90 1.24 1.37 6.44 1.34 Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 3
Page 1 of 1
Preston N. Carter ISB No. 8462
Morgan D. Goodin ISB No. 11184
Blake W. Ringer ISB No. 11223
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
[e-mail]
Attorneys for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF INTERMOUNTAIN GAS COMPANY.
FOR AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR NATURAL
GAS SERVICE IN THE STATE OF IDAHO
CASE NO. INT-G-22-07
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
EXHIBIT 4 TO ACCOMPANY THE
DIRECT TESTIMONY OF RONALD J. AMEN
Intermountain Gas Company
Exhibit 4 - Proposed Rate Design and Proof of Revenue
Residential
Billing Current Base Rates Proposed Base Rates Difference
Description Units Determinants Rates Revenues Rates Revenues $%
RS_RESIDENTIAL SERVICE
Customer Charge Cust Bills 4,420,205 5.50$ 24,311,128$ 9.00$ 39,781,845$ 15,470,718$ 63.64%
Distribution Charge Therms 282,067,442 0.16305$ 45,991,097$ 0.14116$ 39,816,640$ (6,174,457)$ -13.43%
Total Base Revenues 70,302,225$ 79,598,485$ 9,296,260$ 13.22%
IS-R_RESIDENTIAL INTERRUPTIBLE SNOWMELT SERVICE
Customer Charge Cust Bills 2,643 5.50$ 14,537$ 8.00$ 21,144$ 6,608$ 45.46%
Distribution Charge Therms 455,543 0.16305$ 74,276$ 0.14116$ 64,305$ (9,972)$ -13.43%
Total Base Revenues 88,813$ 85,449$ (3,364)$ -3.79%
Total Customer Charge Revenue Cust 24,325,664$ 39,802,989$ 15,477,325$ 63.63%
Total Distribution Charge Revenue Therms 46,065,374$ 39,880,945$ (6,184,429)$ -13.43%
Total Base Revenues 70,391,038$ 79,683,934$ 9,292,896$ 13.20%
Target Revenue
79,684,135$
Cust Bills 4,420,205 5.50$ 24,311,128$ 9.00$ 39,781,845$ $15,470,718 63.64%
Cust Bills 2,643 5.50$ 14,537 8.00$ 21,144 6,608 45.46%
Therms 282,522,986 0.16305$ 46,065,374$ 0.14116$ 39,881,146$ ($6,184,228)-13.43%
Total Base Revenues 70,391,038$ 79,684,135$ 9,293,097$ 13.20%
Target Revenue Difference (201)$
Target Revenue Difference %0.00%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 4
Page 1 of 6
Intermountain Gas Company
Exhibit 4 - Proposed Rate Design and Proof of Revenue
General Service
Billing Current Base Rates Proposed Base Rates Difference
Description Units Determinants Rates Revenues Rates Revenues $%
GS-1_GENERAL SERVICE
Customer Charge Cust 419,593 9.50$ 3,986,134$ 15.00$ 6,293,895$ 2,307,762$ 57.90%
Block 1 - First 200 therms per bill Therms 38,275,720 0.18465$ 7,067,612$ 0.17745$ 6,792,026$ (275,585)$ -3.90%
Block 2 - Next 1,800 therms per bill Therms 66,831,695 0.16117 10,771,263 0.15489 10,351,561 (419,702) -3.90%
Block 3 - Next 8,000 therms per bill Therms 27,156,148 0.13850 3,761,127 0.13310 3,614,483 (146,643) -3.90%
Block 4 - Over 10,000 therms per bill Therms 5,463,381 0.06994 382,109 0.06721 367,194 (14,915) -3.90%
137,726,944 21,982,110$ 21,125,265$ (856,845)$ -3.90%
Total Base Revenues 25,968,244$ 27,419,160$ 1,450,916$ 5.59%
GS-1 IRRIGATION CUSTOMERS
Customer Charge Cust 109 9.50$ 1,036$ 15.00$ 1,635$ 599.50$ 57.90%
Block 1 - First 200 therms per bill Therms 11,063 0.18465$ 2,044$ 0.17745$ 1,963$ (80.66)$ -3.95%
Block 2 - Next 1,800 therms per bill Therms 47,781 0.16117 7,701 0.15489 7,401 (300.06) -3.90%
Block 3 - Next 8,000 therms per bill Therms 12,661 0.13850 1,754 0.13310 1,685 (68.37) -3.90%
Block 4 - Over 10,000 therms per bill Therms 0 0.06994 - 0.06721 - - 0.00%
71,505 11,498$ 11,049$ (449.09)$ -3.91%
Total Base Revenues 12,534$ 12,684$ 150.41$ 1.20%
GS-1 - COMPRESSED NATURAL GAS
Customer Charge Cust 6 9.50$ 57.00$ 15.00$ 90.00$ 33.00$ 57.90%
Block 1 - First 10,000 therms per bill Therms 0 0.13850$ - 0.13310$ - - 0.00%
Block 2 - Over 10,000 therms per bill Therms 0 0.06994 - 0.06721 - - 0.00%
0 -$ -$ -$ 0.00%
Total Base Revenues $57 $90 $33 57.90%
IS-C - SMALL COMMERCIAL INTERRUPTIBLE SNOWMELT SERVICE
Customer Charge Cust 635 9.50$ 6,033$ 12.50$ 7,938$ 1,905.0$ 31.58%
Block 1 - First 200 therms per bill Therms 56,452 0.18465$ 10,424$ 0.17745$ 10,017$ (406)$ -3.90%
Block 2 - Next 1,800 therms per bill Therms 157,470 0.16117 25,379 0.15489 24,390 (989) -3.90%
Block 3 - Next 8,000 therms per bill Therms 55,522 0.13850 7,690 0.13310 7,390 (300) -3.90%
Block 4 - Over 10,000 therms per bill Therms 0 0.06994 - 0.06721 - - 0.00%
269,444 43,493$ 41,798$ (1,695)$ -3.90%
Total Base Revenues 49,526$ 49,735$ 210$ 0.42%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 4
Page 2 of 6
Intermountain Gas Company
Exhibit 4 - Proposed Rate Design and Proof of Revenue
General Service
Billing Current Base Rates Proposed Base Rates Difference
Description Units Determinants Rates Revenues Rates Revenues $%
General Service Total:
Customer Charge Cust 420,343 3,993,259$ 6,303,558$ 2,310,299$ 57.86%
Block 1 - First 200 therms per bill Therms 38,343,235 7,080,079 6,804,007 (276,072) -3.90%
Block 2 - Next 1,800 therms per bill Therms 67,036,946 10,804,344 10,383,353 (420,991) -3.90%
Block 3 - Next 8,000 therms per bill Therms 27,224,331 3,770,570 3,623,558 (147,011) -3.90%
Block 4 - Over 10,000 therms per bill Therms 5,463,381 382,109 367,194 (14,915) -3.90%
Total Base Revenues 26,030,360$ 27,481,669$ 1,451,309$ 5.58%
Target Revenue
27,481,668$
Customer Charge Cust 419,708 9.50$ 3,987,226$ 15.00$ 6,295,620$ 2,308,394$ 57.90%
Customer Charge - Interruptible Cust 635 9.50$ 6,033 12.50$ 7,938$ 1,905$ 31.58%
Block 1 - First 200 therms per bill Therms 38,343,235 0.18465$ 7,080,078$ 0.17745$ 6,804,101$ (275,977)$ -3.90%
Block 2 - Next 1,800 therms per bill Therms 67,036,946 0.16117 10,804,345 0.15489 10,383,199 (421,146) -3.90%
Block 3 - Next 8,000 therms per bill Therms 27,224,331 0.13850 3,770,570 0.13310 3,623,596 (146,974) -3.90%
Block 4 - Over 10,000 therms per bill Therms 5,463,381 0.06994 382,109 0.06721 367,215 (14,894) -3.90%
138,067,893 22,037,102$ 21,178,111$ (858,991)$ -3.90%
Total Base Revenues 26,030,361$ 27,481,668$ 1,451,308$ 5.58%
Target Revenue Difference 1$
Target Revenue Difference %0.00%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 4
Page 3 of 6
Intermountain Gas Company
Exhibit 4 - Proposed Rate Design and Proof of Revenue
Large Volume
Billing Current Base Rates Proposed Base Rates Difference
Description Units Determinants Rates Revenues Rates Revenues $%
LV-1_LARGE VOLUME
Customer Charge Cust 411 -$ -$ 150.00$ 61,650$ 61,650$
Demand Charge Demand 895,110 0.3000$ 268,533$ 0.3200$ 286,435$ 17,902$ 6.67%
Overrun Demand Charge Demand 7,978 0.3000$ 2,393$ 0.3200 2,553$ 160$ 6.67%
Current
Block 1 - First 250,000 therms per bill Therms 13,566,644 0.03000$ 406,999$
Block 2 - Next 500,000 therms per bill Therms 0 0.01211$ -
Block 3 - Over 750,000 therms per bill Therms 0 0.00307$ -
406,999$
Proposed
Block 1 - First 35,000 therms per bill Therms 10,083,597 0.03000$ 302,508$
Block 2 - Next 35,000 therms per bill Therms 2,221,333 0.01908 42,390
Block 3 - Over 70,000 therms per bill Therms 1,261,714 0.01600 20,187
406,999$ 365,085$ (41,914)$ -10.30%
Total Base Revenues 677,926$ 715,723$ 37,798$ 5.58%
Target Revenue 715,723$
Target Revenue Difference -
Target Revenue Difference %0.00%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 4
Page 4 of 6
Intermountain Gas Company
Exhibit 4 - Proposed Rate Design and Proof of Revenue
Transportation
Billing Current Base Rates Proposed Base Rates Difference
Description Units Determinants Rates Revenues Rates Revenues $%
T-3 - TRANSPORT INTERRUPTIBLE
Basic Service Charge Cust 84 -$ $0 300.00$ 25,200$ 25,200$ 0.00%
Block 1 - First 100,000 therms per bill Therms 7,990,121 0.03853$ 307,859$ 0.03774$ 301,544$ (6,315)$ -2.05%
Block 2 - Next 50,000 therms per bill Therms 3,576,050 0.01569 56,108 0.01537 54,957 (1,151) -2.05%
Block 3 - Over 150,000 therms per bill Therms 29,956,973 0.00578 173,151 0.00566 169,599 (3,552) -2.05%
All Volume 41,523,144 537,118$ 526,100$ (11,018)$ -2.05%
Total Base Revenues 537,118$ 551,300$ 14,182$ 2.64%
Target Revenue 551,300
Target Revenue Difference -
Target Revenue Difference %0.00%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 4
Page 5 of 6
Intermountain Gas Company
Exhibit 4 - Proposed Rate Design and Proof of Revenue
Transportation
Billing Current Base Rates Proposed Base Rates Difference
Description Units Determinants Rates Revenues Rates Revenues $%
T-4 - TRANSPORT FIRM
Basic Service Charge Cust 1224 -$ -$ 150.00$ 183,600$ 183,600$ 0.00%
Demand Charge Demand 17,824,920 0.3000$ 5,347,476$ 0.3200$ 5,703,974$ 356,498$ 6.67%
Overrun Demand Charge Demand 285,499 0.3000$ 85,650$ 0.3200$ 91,360$ 5,710$ 6.67%
Block 1 - First 250,000 therms per bill Therms 131,975,926 0.02395$ 3,160,823$ 0.02393$ 3,157,689$ (3,134)$ -0.10%
Block 2 - Next 500,000 therms per bill Therms 103,237,613 0.00847 874,423 0.00846 873,556 (867) -0.10%
Block 3 - Over 750,000 therms per bill Therms 94,236,367 0.00260 245,015 0.00260 244,772 (243) -0.10%
All Volumes 329,449,906 4,280,261$ 4,276,017$ (4,244)$ -0.10%
Total Base Revenues 9,713,387$ 10,254,951$ 541,564$ 5.58%
Target Revenue 10,254,951$
Target Revenue Difference -
Target Revenue Difference %0.00%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 4
Page 6 of 6
Preston N. Carter ISB No. 8462
Morgan D. Goodin ISB No. 11184
Blake W. Ringer ISB No. 11223
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
[e-mail]
Attorneys for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF INTERMOUNTAIN GAS COMPANY.
FOR AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR NATURAL
GAS SERVICE IN THE STATE OF IDAHO
CASE NO. INT-G-22-07
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
EXHIBIT 5 TO ACCOMPANY THE
DIRECT TESTIMONY OF RONALD J. AMEN
Intermountain Gas Company
Exhibit 5 – Bill Impact
Residential
RS_RESIDENTIAL SERVICE
CURRENT PROPOSED
RATES RATES
CUSTOMER CHARGE 5.50$ 9.00$
DISTRIBUTION CHARGE $0.16305 $0.14116
COG $0.55523 $0.55523
EE $0.01564 $0.01564
THERM CURRENT PROPOSED AMOUNT PERCENT
$ $ $
Usage Per THERM
0 5.50 9.00 3.50 63.64%
10 12.84 16.12 3.28 25.56%
20 20.18 23.24 3.06 15.18%
30 27.52 30.36 2.84 10.33%
40 34.86 37.48 2.62 7.53%
50 42.20 44.60 2.41 5.70%
(1)60 49.54 51.72 2.19 4.41%
70 56.87 58.84 1.97 3.46%
80 64.21 65.96 1.75 2.72%
90 71.55 73.08 1.53 2.14%
100 78.89 80.20 1.31 1.66%
110 86.23 87.32 1.09 1.27%
120 93.57 94.44 0.87 0.93%
130 100.91 101.56 0.65 0.65%
140 108.25 108.68 0.44 0.40%
150 115.59 115.80 0.22 0.19%
160 122.93 122.92 (0.00)0.00%
170 130.27 130.05 (0.22)-0.17%
180 137.61 137.17 (0.44)-0.32%
190 144.94 144.29 (0.66)-0.45%
200 152.28 151.41 (0.88)-0.58%
210 159.62 158.53 (1.10)-0.69%
220 166.96 165.65 (1.32)-0.79%
230 174.30 172.77 (1.53)-0.88%
240 181.64 179.89 (1.75)-0.97%
250 188.98 187.01 (1.97)-1.04%
260 196.32 194.13 (2.19)-1.12%
270 203.66 201.25 (2.41)-1.18%
280 211.00 208.37 (2.63)-1.25%
290 218.34 215.49 (2.85)-1.30%
300 225.68 222.61 (3.07)-1.36%
(1)Rs_Residential Service average monthly usage
DIFFERENCE
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 1 of 8
Intermountain Gas Company
Exhibit 5 – Bill Impact
Residential
IS-R_RESIDENTIAL INTERRUPTIBLE SNOWMELT SERVICE
CURRENT PROPOSED
RATES RATES
CUSTOMER CHARGE 5.50$ 8.00$
DISTRIBUTION CHARGE $0.16305 $0.14116
COG $0.57313 $0.57313
EE $0.00000 $0.00000
DIFFERENCE
THERM CURRENT PROPOSED AMOUNT PERCENT
$ $ $
Usage Per THERM
0 5.50 8.00 2.50 45.45%
10 12.86 15.14 2.28 17.74%
20 20.22 22.29 2.06 10.20%
30 27.59 29.43 1.84 6.68%
40 34.95 36.57 1.62 4.65%
50 42.31 43.71 1.41 3.32%
60 49.67 50.86 1.19 2.39%
70 57.03 58.00 0.97 1.70%
80 64.39 65.14 0.75 1.16%
90 71.76 72.29 0.53 0.74%
100 79.12 79.43 0.31 0.39%
110 86.48 86.57 0.09 0.11%
120 93.84 93.71 (0.13)-0.14%
130 101.20 100.86 (0.35)-0.34%
140 108.57 108.00 (0.56)-0.52%
150 115.93 115.14 (0.78)-0.68%
160 123.29 122.29 (1.00)-0.81%
(1)170 130.65 129.43 (1.22)-0.93%
180 138.01 136.57 (1.44)-1.04%
190 145.37 143.72 (1.66)-1.14%
200 152.74 150.86 (1.88)-1.23%
210 160.10 158.00 (2.10)-1.31%
220 167.46 165.14 (2.32)-1.38%
230 174.82 172.29 (2.53)-1.45%
240 182.18 179.43 (2.75)-1.51%
250 189.55 186.57 (2.97)-1.57%
260 196.91 193.72 (3.19)-1.62%
270 204.27 200.86 (3.41)-1.67%
280 211.63 208.00 (3.63)-1.71%
290 218.99 215.14 (3.85)-1.76%
300 226.35 222.29 (4.07)-1.80%
(1)Is-R_Residential Interruptible Snowmelt Service average monthly usage
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 2 of 8
Intermountain Gas Company
Exhibit 5 – Bill Impact
General Service
GS-1_GENERAL SERVICE
GS-1 IRRIGATION CUSTOMERS
CURRENT PROPOSED
RATES RATES
CUSTOMER CHARGE 9.50$ $15.00
Block 1 200 $0.18465 $0.17745
Block 2 1800 $0.16117 $0.15489
Block 3 8000 $0.13850 $0.13310
Block 4 10000 $0.06994 $0.06721
COG $0.56651 $0.56651
EE $0.00320 $0.00320
DIFFERENCE
THERM CURRENT PROPOSED AMOUNT PERCENT
$ $ $
Usage Per THERM
- 9.50 15.00 5.50 57.89%
100 84.94 89.72 4.78 5.63%
200 160.37 164.43 4.06 2.53%
(1)300 233.46 236.89 3.43 1.47%
400 306.55 309.35 2.80 0.91%
500 379.64 381.81 2.18 0.57%
600 452.72 454.27 1.55 0.34%
(2)700 525.81 526.73 0.92 0.17%
800 598.90 599.19 0.29 0.05%
900 671.99 671.65 (0.34)-0.05%
1000 745.08 744.11 (0.96)-0.13%
1100 818.16 816.57 (1.59)-0.19%
1200 891.25 889.03 (2.22)-0.25%
1300 964.34 961.49 (2.85)-0.30%
1400 1,037.43 1,033.95 (3.48)-0.34%
1500 1,110.52 1,106.41 (4.10)-0.37%
1600 1,183.60 1,178.87 (4.73)-0.40%
1700 1,256.69 1,251.33 (5.36)-0.43%
1800 1,329.78 1,323.79 (5.99)-0.45%
1900 1,402.87 1,396.25 (6.62)-0.47%
2000 1,475.96 1,468.71 (7.24)-0.49%
2100 1,546.78 1,538.99 (7.78)-0.50%
2200 1,617.60 1,609.27 (8.32)-0.51%
2300 1,688.42 1,679.56 (8.86)-0.52%
2400 1,759.24 1,749.84 (9.40)-0.53%
2500 1,830.06 1,820.12 (9.94)-0.54%
2600 1,900.88 1,890.40 (10.48)-0.55%
2700 1,971.70 1,960.68 (11.02)-0.56%
2800 2,042.52 2,030.96 (11.56)-0.57%
2900 2,113.35 2,101.24 (12.10)-0.57%
3000 2,184.17 2,171.52 (12.64)-0.58%
(1)GS-1 Geneneral Service average monthly usage
(2)GS-1 Irrigation Service average monthly usage
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 3 of 8
Intermountain Gas Company
Exhibit 5 – Bill Impact
General Service
GS-1 - COMPRESSED NATURAL GAS
CURRENT PROPOSED
RATES RATES
CUSTOMER CHARGE 9.50$ 15.00$
Block 1 10,000 $0.13850 $0.13310
Block 2 10,000 $0.06994 $0.06721
COG $0.56651 $0.56651
EE $0.00000 $0.00000
DIFFERENCE
THERM CURRENT PROPOSED AMOUNT PERCENT
$ $ $
Usage Per THERM
- 9.50 15.00 5.50 57.89%
1000 714.51 714.61 0.10 0.01%
2000 1,419.52 1,414.22 (5.30)-0.37%
3000 2,124.53 2,113.83 (10.70)-0.50%
4000 2,829.54 2,813.44 (16.10)-0.57%
5000 3,534.55 3,513.05 (21.50)-0.61%
6000 4,239.56 4,212.66 (26.90)-0.63%
7000 4,944.57 4,912.27 (32.30)-0.65%
8000 5,649.58 5,611.88 (37.70)-0.67%
9000 6,354.59 6,311.49 (43.10)-0.68%
10000 7,059.60 7,011.10 (48.50)-0.69%
11000 7,696.05 7,644.82 (51.23)-0.67%
12000 8,332.50 8,278.54 (53.96)-0.65%
13000 8,968.95 8,912.26 (56.69)-0.63%
14000 9,605.40 9,545.98 (59.42)-0.62%
15000 10,241.85 10,179.70 (62.15)-0.61%
16000 10,878.30 10,813.42 (64.88)-0.60%
17000 11,514.75 11,447.14 (67.61)-0.59%
18000 12,151.20 12,080.86 (70.34)-0.58%
19000 12,787.65 12,714.58 (73.07)-0.57%
20000 13,424.10 13,348.30 (75.80)-0.56%
21000 14,060.55 13,982.02 (78.53)-0.56%
22000 14,697.00 14,615.74 (81.26)-0.55%
23000 15,333.45 15,249.46 (83.99)-0.55%
24000 15,969.90 15,883.18 (86.72)-0.54%
25000 16,606.35 16,516.90 (89.45)-0.54%
26000 17,242.80 17,150.62 (92.18)-0.53%
27000 17,879.25 17,784.34 (94.91)-0.53%
28000 18,515.70 18,418.06 (97.64)-0.53%
29000 19,152.15 19,051.78 (100.37)-0.52%
30000 19,788.60 19,685.50 (103.10)-0.52%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 4 of 8
Intermountain Gas Company
Exhibit 5 – Bill Impact
General Service
IS-C - SMALL COMMERCIAL INTERRUPTIBLE SNOWMELT SERVICE
CURRENT PROPOSED
RATES RATES
CUSTOMER CHARGE 9.50$ 12.50$
Block 1 200 $0.18465 $0.17745
Block 2 1800 $0.16117 $0.15489
Block 3 8000 $0.13850 $0.13310
Block 4 10000 $0.06994 $0.06721
COG $0.56651 $0.56651
EE $0.00000 $0.00000
DIFFERENCE
THERM CURRENT PROPOSED AMOUNT PERCENT
$ $ $
Usage Per THERM
- 9.50 12.50 3.00 31.58%
100 84.62 86.90 2.28 2.69%
200 159.73 161.29 1.56 0.98%
300 232.50 233.43 0.93 0.40%
(1)400 305.27 305.57 0.30 0.10%
500 378.04 377.71 (0.32)-0.09%
600 450.80 449.85 (0.95)-0.21%
700 523.57 521.99 (1.58)-0.30%
800 596.34 594.13 (2.21)-0.37%
900 669.11 666.27 (2.84)-0.42%
1000 741.88 738.41 (3.46)-0.47%
1100 814.64 810.55 (4.09)-0.50%
1200 887.41 882.69 (4.72)-0.53%
1300 960.18 954.83 (5.35)-0.56%
1400 1,032.95 1,026.97 (5.98)-0.58%
1500 1,105.72 1,099.11 (6.60)-0.60%
1600 1,178.48 1,171.25 (7.23)-0.61%
1700 1,251.25 1,243.39 (7.86)-0.63%
1800 1,324.02 1,315.53 (8.49)-0.64%
1900 1,396.79 1,387.67 (9.12)-0.65%
2000 1,469.56 1,459.81 (9.74)-0.66%
2100 1,540.06 1,529.77 (10.28)-0.67%
2200 1,610.56 1,599.73 (10.82)-0.67%
2300 1,681.06 1,669.70 (11.36)-0.68%
2400 1,751.56 1,739.66 (11.90)-0.68%
2500 1,822.06 1,809.62 (12.44)-0.68%
2600 1,892.56 1,879.58 (12.98)-0.69%
2700 1,963.06 1,949.54 (13.52)-0.69%
2800 2,033.56 2,019.50 (14.06)-0.69%
2900 2,104.07 2,089.46 (14.60)-0.69%
3000 2,174.57 2,159.42 (15.14)-0.70%
(1)Is-C - Small Commercial Interruptible Snowmelt Service average monthly usage
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 5 of 8
Intermountain Gas Company
Exhibit 5 – Bill Impact
Large Volume
LV-1_LARGE VOLUME
Current Rates Current Block Proposed Rates Proposed Block
Customer Charge -$ 150.0$
Demand Charge 0.30000$ 0.32000$
Block 1 0.03000$ 250,000 0.03000$ 35,000
Block 2 0.01211$ 500,000 0.01908$ 35,000
Block 3 0.00307$ 750,000 0.01600$ 70,000
COG 0.51173$ 0.51173$
Customer Usage Scenario Monthly Average MDFQ Current Monthly
Bill
Proposed Monthly
Bill Difference $Difference %
High Use / High Demand 40,000 6,000 23,469$ 23,685$ 215$ 0.92%
High Use / Low Demand 40,000 2,000 22,269$ 22,405$ 135$ 0.61%
Avg. Use / Avg. Demand 30,000 3,000 17,152$ 17,362$ 210$ 1.22%
Low Use / High Demand 20,000 3,000 11,735$ 11,945$ 210$ 1.79%
Low Use / Low Demand 20,000 1,000 11,135$ 11,305$ 170$ 1.53%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 6 of 8
Intermountain Gas Company
Exhibit 5 – Bill Impact
Transportation
T-3 - TRANSPORT INTERRUPTIBLE
Current Block Current Proposed
Customer Charge -$ 300$
Demand Charge -$ -$
Block 1 100,000 0.03853$ 0.03774$
Block 2 50,000 0.01569$ 0.01537$
Block 3 150,000 0.00578$ 0.00566$
COG (0.00082)$ (0.00082)$
Monthly Average
Usage (Therm)MDFQ (Therm)Current Monthly
Bill
Proposed
Monthly Bill Difference $Difference %
- - -$ 300$ 300$ 0.00%
100,000 - 3,771$ 3,992$ 221$ 5.86%
200,000 - 4,763$ 4,962$ 199$ 4.18%
300,000 - 5,259$ 5,446$ 187$ 3.56%
400,000 - 5,755$ 5,930$ 175$ 3.04%
500,000 - 6,251$ 6,414$ 163$ 2.61%
600,000 - 6,747$ 6,898$ 151$ 2.24%
700,000 - 7,243$ 7,382$ 139$ 1.92%
800,000 - 7,739$ 7,866$ 127$ 1.64%
900,000 - 8,235$ 8,350$ 115$ 1.40%
1,000,000 - 8,731$ 8,834$ 103$ 1.18%
1,100,000 - 9,227$ 9,318$ 91$ 0.99%
1,200,000 - 9,723$ 9,802$ 79$ 0.81%
1,300,000 - 10,219$ 10,286$ 67$ 0.66%
1,400,000 - 10,715$ 10,770$ 55$ 0.51%
1,500,000 - 11,211$ 11,254$ 43$ 0.38%
1,600,000 - 11,707$ 11,738$ 31$ 0.26%
1,700,000 - 12,203$ 12,222$ 19$ 0.16%
1,800,000 - 12,699$ 12,706$ 7$ 0.06%
1,900,000 - 13,195$ 13,190$ (5)$ -0.04%
2,000,000 - 13,691$ 13,674$ (17)$ -0.12%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 7 of 8
Intermountain Gas Company
Exhibit 5 – Bill Impact
Transportation
T-4 - TRANSPORT FIRM
Current Block Current Rates Proposed Rates
Customer Charge -$ 150.00$
Demand Charge 0.30000$ 0.32000$
Block 1 250,000 0.02395$ 0.02393$
Block 2 500,000 0.00847$ 0.00846$
Block 3 750,000 0.00260$ 0.00260$
COG (0.01968)$ (0.01968)$
Customer Usage Scenario
Monthly
Average Usage
(Therm)
MDFQ (Therm)Current
Monthly Bill
Proposed
Monthly Bill Difference $Difference %
High Use / High Demand 1,000,000 150,000 52,921$ 56,061$ 3,140$ 5.93%
High Use / Low Demand 1,000,000 50,000 24,889$ 26,029$ 1,140$ 4.58%
Avg. Use / Avg. Demand 300,000 30,000 14,821$ 15,565$ 744$ 5.02%
Low Use / High Demand 50,000 7,500 3,300$ 3,599$ 299$ 9.06%
Low Use / Low Demand 50,000 2,500 1,898$ 2,097$ 199$ 10.48%
Case No. INT-G-22-07
R. Amen, IGC
Exhibit No. 5
Page 8 of 8