20240911Staff Comments.pdf

RECEIVED
Wednesday, September 11, 2024 10.40:15 AM
IDAHO PUBLIC
UTILITIES COMMISSION
MICHAEL DUVAL
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 11714
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF INTERMOUNTAIN )
GAS COMPANY'S REQUEST FOR ) CASE NO. INT-G-24-04
AUTHORITY TO DECREASE ITS PRICES )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission, by and
through its Attorney of record, Michael Duval, Deputy Attorney General, submits the following
comments.
BACKGROUND
On August 9, 2024, Intermountain Gas Company("Company"), applied for authority to
place into effect new rate schedules for the Company's Purchased Gas Adjustment ("PGA")
costs, effective October 1, 2024, ("Application"). If approved, the Company represents that the
new rates will decrease its annualized revenues by approximately $46.8 million, or 13.5 percent.
The Company represents that the typical residential customer's monthly bill would decrease by
$6.69 or 13.14 percent, and the typical commercial customer's monthly bill would decrease by
$33.26 or 14.46 percent.
STAFF COMMENTS 1 SEPTEMBER 11, 2024

The Company's rates include a base-rate component and a gas-related PGA cost
component. The base-rate component is intended to cover the Company's fixed costs to serve its
customer. For example, the Company's costs for equipment and facilities to provide service
rarely change. The Company's PGA is a Commission-approved mechanism that adjusts rates up
or down to reflect changes in the Company's costs to buy natural gas from suppliers including
changes in transportation, storage, and other related costs. The Company defers these costs into
its PGA account and then passes them on to customers through an increase or decrease in rates.
The Company seeks to pass through various changes in gas-related costs from: (1) firm
transportation providers; (2) a decrease in the Company's Weighted Average Cost of Gas
("WACOG"); (3)the customer allocation of costs related to the PGA; (4)temporary surcharges
and credits related to purchases and interstate transportation costs; (5)benefits associated with
the Company's use of storage and certain firm capacity rights; and(6)benefits related to the sale
of liquefied natural gas through its Nampa facility. The Company also asks to end the temporary
surcharges and credits established in Case No. INT-G-23-04.
The proposed WACOG in the Company's Application would change from the $0.30455
per therm currently included in rates to $0.26839 per therm, a decrease of approximately$16.5
million in natural gas costs compared to those currently included in rates.
The Company discussed various transmission issues but noted that it had benefited from
savings due to new firm transportation capacity allowing it to access to less expensive gas from
Alberta, Canada.
The Company's Application includes descriptions of all components that make up the
PGA along with exhibits that show the summaries of all price changes by customer class and
proposed tariffs.
The Company requested approval of its rate schedules found in Exhibit No. 3 be
approved and that "the filing requirement for the Deferred Gas Cost Balance, LNG Sales Cost
Benefit Analysis, and Weighted Average Cost of Gas reports be maintained at quarterly
frequency." Application at 13.
STAFF ANALYSIS
Staff examined the Company's Application, exhibits, workpapers, and responses to
Production Requests and confirmed: (1)the PGA proposal would not affect the Company's
STAFF COMMENTS 2 SEPTEMBER 11, 2024

earnings; (2) the deferred costs are prudent and properly calculated; and(3) the Company's
WACOG request is reasonable. Staff recommends that the Company's Application be approved.
Table No. 1 below summarizes the impact of the proposed changes on each customer
class.
Table No. 1: Summary of Proposed Rates
Average Average
Change in Class Change in Average Price
Customer Class: Revenue $/Therm % Change $/Therm
RS Residential $ (30,311,225) $ (0.10203) -13.14% $ 0.67428
GS-1 General Service (14,223,117) (0.09795) -14.46% 0.57949
LV-1 Large Volume (1,576,890) (0.10718) -22.07% 0.37836
T-3 Transportation(Volumetric) (71,306) (0.00174) -12.43% 0.01226
T-4 Transportation(Volumetric) - - 0.00% 0.01200
T-4 Demand Charge 578,729 0.03172 -10.72% 0.26414
TOTAL $ (46,761,267) $ (0.05545) -13.50% $ 0.35517
Overall, the Company's proposal decreases annual revenue by approximately$46.7
million which is detailed in Table No. 2 below.
Table No. 2: Proposed Change to Annual Revenue
Deferrals:
INT-G-23-04 Temporaries Reversed $ 753,695
Additional INT-G-23-04 Temporary Credits and Charges
Fixed Deferred Gas Costs $ (19,606,661)
Variable Deferred Gas Costs (9,317,520)
Lost and Unaccounted for Gas (3,253,724)
LNG Sales Credit (1,401,373)
Total Additional Temporary Credits and Surcharges (33,579,278)
Total Deferrals $ (32,825,583)
Fixed Cost Changes:
NWP Full Rate Reservation $ (1,659,797)
NWP Discounted Reservation (298,780)
Upstream Full Rate 8,479,972
Upstream Discounted (100,416)
SGS-2F and LS-2F (3,758)
Other Storage Costs 33,000
Total Fixed Cost Changes $ 6,450,221
Changes in WACOG $ (16,525,191)
Reallocation and True-Up of Fixed Costs $ (3,857,968)
Total Base Rate Price Changes $ (13,932,938)
STAFF COMMENTS 3 SEPTEMBER 11, 2024

Total Annual Price Change $ (46,758,521)
Total Annual Price Change (Exh.No 1) S (46,761,267)
Differences due to rounding $ 2,746
The Company reversed$753,695 in temporary credits and surcharges that were part of
last year's PGA, Case No. INT-G-23-04. The deferral account consists of capacity release
revenues, overcollections from last year's PGA, per therm amortization of deferrals, LNG off-
system sales revenue and interest. The proposed temporary credits and surcharges in this
Application reduce the deferral by $33,579,278. This results in a total deferral balance reduction
of$32,825,583.
The Company included fixed cost changes in its Application. The fixed cost changes
include changes to the demand charges for transportation and storage of$6,450,221.
Additionally, the Company included commodity price changes (WACOG) of$16,525,191 and
reallocation and true-up of fixed costs, which is an adjustment based upon normalization of sales
volume and an adjustment to the fixed cost collection rate, of$3,857,968. Overall, the total rate
base price changes included by the Company are a reduction of$13,932,938.
The total deferral balance reduction and reduction in base rate price changes totals to an
annual price change reduction of$46,758,521. The Company calculates a rounding difference of
$2,746 due to the per therm rate going to only five decimal places. This results in a final annual
price change calculation of$46,761,267. Staff has reviewed all inputs and believes the total
annual price change is calculated accurately.
Weighted Average Cost of Gas
The WACOG is the Company's average variable cost to buy and transport natural gas to
meet customers' estimated annual requirements. The components of the WACOG include the
volumetric interstate transportation rate, the city gate costs, the IGI Resources administration
fees, and the Gas Technology Institute charges. The proposed WACOG is $0.26839 per therm,
an 11.9% decrease from the current WACOG of$0.30455. Chart No. 1 below displays the
WACOG changes from the previous ten years.
STAFF COMMENTS 4 SEPTEMBER 11, 2024

Chart No. 1: WACOG (Per Therm)
IGC PGA WACOG ($/Therm)
0.600
0.500
E 0.400
s 0.300
H
1^ 0.200
0.100
0.000
$0.328 $0.297 $0.260 $0.227 $0.209 $0.217 $0.260 $0.424 $0.392 $0.528 $0.305 $0.268 1
2015 2016 2017 2018 2019 2020 2021 2022* 2022* 2022 2023 2024
*Out of cycle ad'ustment
Market Fundamentals & Price Analysis
The Company forecasts that natural gas will be more abundant by the start of the
upcoming winter, which is contributing to depressed natural gas prices. Application at 7. The
Company received additional firm transportation capacity on the Gas Transmission Northwest
("GTN") expansion project in July 2024 and expects to have additional firm transportation
capacity available in January 2025. Id. The Company continues to store and hedge much of its
forecasted supply at fixed prices. Staff reviewed the Company's projected natural gas costs and
believes it is reasonable by analyzing the Company's projected cost to purchase natural gas by
comparing it to forecasts by U.S. Energy Information Administration ("EIA"), as shown below.
Natural Gas Production 1
We forecast U.S. natural gas production to average 103 Bcf/d in 2024, down
slightly from 2023, and then increase to average of 105 Bcf/d in 2025. The main
drivers for our forecast of growth in U.S. production next year are an increasing
Henry Hub price and growing natural gas demand as feed gas for liquefied natural
gas (LNG) projects scheduled to come online in 2024 and 2025. The U.S.
benchmark Henry Hub spot price averaged $2.07 per million British thermal units
(MMBtu) in July.
We forecast the price will average about $2.60/MMBtu for the rest of 2024
(August—December), which is slightly less than the average of $2.69/MMBtu
during the same period in 2023, and we expect the price to average $2.30/MMBtu
'EIA Short Term Energy Outlook at 3.https://www.eia.gov/outlooks/steo/pdf/steo_full.pdf
STAFF COMMENTS 5 SEPTEMBER 11, 2024

for all of 2024. If natural gas production is greater and consumption in the electric
power sector is less than we expect, prices could be lower than in our forecast.
Risk Mana eg ment
In Order No. 35942, the Commission recommended the Company schedule a workshop
with Staff and other interested parties to review its risk management policies. On April 18,
2024, Staff attended a workshop with the Company and IGI Resources. Staff reviewed the
Company's risk management policies and discussed how the Company evaluates how much
natural gas to hedge. Staff reviewed the process of how IGI Resources procures gas based on the
required hedging targets determined by the Company. Staff believes that the Company
sufficiently met the Commission's recommendation.
Table No. 3: Hedtint!Ratios
% Locked-in Gas by PGA Year
2020 2021 2022 2023 2024
Non-Summer Months (Oct. -Mar.) 74 67 66 74 80
Summer Months 72 46 28 57 76
Full Year 74 70 57 75 79
Purchasing
The Company continues to utilize index or spot purchases allowing it to take
advantage of low prices for real-time needs. This year the Company purchased roughly 21% of
its natural gas at index or spot prices. As shown in the section above, the Company hedged
roughly 79% of its gas purchases. Staff reviewed the Company's natural gas purchases during
the PGA period by examining a 3-month sample of invoices. Staff confirmed that the natural gas
purchases reconciled with the amount of natural gas purchases reported in the monthly deferrals.
2%Locked-in gas includes storage volumes that are both hedged and index purchases.
STAFF COMMENTS 6 SEPTEMBER 11, 2024

Transportation & Storm
The Company delivers domestically produced natural gas to its city gates through the
Northwest Pipeline. The Company also delivers natural gas from Canada by using pipeline
capacity on GTN, TransCanada's Foothills Pipeline system, and TransCanada's Alberta system.
Permanent transportation and storage costs reflect savings of$2.3 million. Typically,
natural gas added to storage is procured during the summer season when prices are normally
lower than in winter. The Company has been purchasing storage as needed to meet peak times in
the winter and to hedge against higher prices.
Pipeline Capacity
The Company holds excess pipeline capacity in case of increased demand. It mitigates
the cost of holding this excess by selling it back into the market benefitting customers through
the PGA. This year the Company released firm transportation capacity on the Northwest
Pipeline, its upstream pipelines, and a portion of its Clay Basin storage capacity. The
Company's capacity release revenue for the current PGA is forecasted to be $9,056,000, which
will be credited back to customers over the coming PGA year, a significant increase from last
year's $5.7 million credit to customers. These credits are included in the Fixed Deferred Gas
Costs listed in Table No. 2. The Company's historical capacity release is shown below in Chart
No. 2.
Chart No. 2: Historical Capacity Releases
IGC Historical Transportation Capacity Release
$10,000,000
$9,000,000
$8,000,000
$7,000,000
$6,000,000
$5,000,000
$4,000,000
$3,000,000
$2,000,000
$1,000,000
$ 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
Senesl $3,886,165 $3,940,000 $3,940,000 $5,453,000 $7,125,000 $6,410,000 $6,351,000 $6,629,000 $5,740,000 $9,056,000
STAFF COMMENTS 7 SEPTEMBER 11, 2024

Liquid Natural Gas Storm
In Order No. 32793, the Commission authorized the Company to sell excess Liquid
Natural Gas ("LNG") capacity from its Nampa LNG Facility to non-utility customers. In Order
No. 35836, the Commission approved a Settlement and Stipulation authorizing the change in the
non-utility LNG credits to $0.03 per gallon for capital improvements and$0.04 per gallon for
operational and maintenance expenses. The new sales credit rates were used to calculate the
2024 LNG sales benefits.
Historical LNG benefits included in the PGA are shown below in Chart No. 3. The
Company proposes to credit customers $1,401,373 for their share of revenues of LNG sales.
Staff reviewed the Company's non-utility sales of LNG and verified the credit to ratepayers has
been calculated correctly.
Chart No. 3: LNG Sales Ratepaver Benefits
IGC Historical LNG Benefit
$1,600,000
$1,400,000
$1,200,000
$1,000,000
$800,000
$600,000
$400,000
$200,000
$0
2015 PGA 2016 PGA 2017 PGA 2018 PGA 2019 PGA 2020 PGA 2021 PGA 2022 PGA 2023 PGA 2024 PGA
Seriesl $689,367 $236,805 $495,418 $529,445 $1,129,239 $1,005,060 $717,972 $221,993 $1,423,100 $1,401,373
Lost& Unaccounted for Gas and Line Break
Lost and Unaccounted for("LAUF") Gas is the difference between the volume of natural
gas delivered to the distribution system at the city gate and volume of gas billed to customers at
the meter. This year the Company's LAUF Gas rate is -0.8945% (found gas). The Company
allocates LAUF Gas at 75%to core customers (Residential and General Service) and 25%to
industrial customers (Large Volume and Transportation). In this PGA, the total credit for LAUF
is $3,253,724, of which is $2,433,477 credited to core customers and $820,247 is credited to
industrial customers.
STAFF COMMENTS 8 SEPTEMBER 11, 2024

The Company charges a Line Break Rate to parties who are responsible for damage to the
distribution system causing a gas leak. The Company proposed to decrease the rate from the
current rate of$0.50639 to $0.47576. The Line Break Rate includes the WACOG of$0.26839
and Gas Transportation Cost of$0.20737. Staff believes the Company calculated the proposed
Line Break Rate consistent with Order No. 33139.
Payment Fees Deferral
In Order No. 34099, Case No. INT-G-18-01, the Company was directed to create a
regulatory asset to capture costs associated with in-person customer pay station transactions
handled by Western Union. Because the funds were collected from customers on a per-therm
basis, it was appropriate to return this amount on a per-therm basis through the PGA.
As of October 1, 2023, the remaining balance of the in-person customer payment fee
account was $32,461. The balance grew another $265 through June 30, 2024, to total $32,726.
The Company estimates that through September 30, 2024, it will amortize $34,577 bringing the
balance to negative $1,851. The Company has rolled the balance into the fixed deferral gas
costs, illustrated in Tabe No. 2. Because the Company projects that it will have over amortized,
it has included this amount as a credit to customers. Staff agrees that the amortization estimate
through September 30, 2024, is reasonable and that the difference between actual amortization
and the estimate will be immaterial.
Residential EneW Efficiency Credit
In Commission Order No. 35538, Case No. INT-G-22-05, the Commission approved the
credit of$4.85 million in over-collected Energy Efficiency Residential Funds to be passed back
to residential customers in the PGA. Because the funds were collected from customers on a per-
therm basis, it was appropriate to return this amount on a per-therm basis through the PGA.
As of October 1, 2023, the remaining balance in the energy efficiency funds account was
$686,777. Through June 30, 2024, the Company amortized$532,528 of the balance, leaving
$154,249 remaining. The Company estimates that through September 30, 2024, an additional
$44,640 will be amortized, leaving $109,609 remaining. Due to the small amount remaining, the
Company has rolled this remaining balance into the fixed deferral gas costs, illustrated in Table
STAFF COMMENTS 9 SEPTEMBER 11, 2024

No. 2. Staff agrees that the estimated amortization through September 30, 2024, is reasonable
and that the difference between actual amortization and the estimate will be immaterial.
PGA Rporting
In Order No. 34448, the Commission found that quarterly WACOG and monthly deferred
cost reports provide useful information, assist Staff with determining whether to audit earlier
than planned, and whether an interim filing might be needed. In its Application, the Company
requested that the Commission maintain the quarterly requirement of filing for the Deferred Gas
Cost Balance, LNG Sales Cost Benefit Analysis, and WACOG reports. The Company stated
that it is committed to notifying the Commission if an interim filing might be needed. Staff
believes quarterly reporting is reasonable given the Company's commitment to notify the
Commission.
Customer Notice &Press Release
The Company's press release and customer notice were included with its Application.
Each document addresses the following cases: (1) this case (INT-G-24-04); and(2) the natural
gas Energy Efficiency adjustment(INT-G-24-03). Staff reviewed the documents and determined
that both meet the requirements of Rule 125 of the Commission's Rules of Procedure. IDAPA
31.01.01.125. The notice was included with bills mailed to customers beginning August 14,
2024, and ending September 11, 2024.
The Commission set a comment deadline of September 11, 2024. Some customers in the
last billing cycles may not have received or had adequate time to submit comments before the
comment deadline. Customers should have the opportunity to file comments and have those
comments considered by the Commission. Staff recommends that the Commission consider late
filed comments from customers. As of September 10, 2024, no customer comments had been
filed.
STAFF COMMENTS 10 SEPTEMBER 11, 2024

STAFF RECOMMENDATION
After examining the Company's Application, natural gas purchases, and deferral activity for the
year, Staff recommends the Commission:
1. Approve the Company's Application, decreasing revenues by$46,761,267 as
shown in Table No. 2, and approve the proposed WACOG amount of$0.26839
per therm;
2. Approve the Company's proposed Tariff Rate Schedules RS, GS-1, IS-R, IS-C,
LV-1, T-3, and T-4 as filed with the Application;
3. Direct the Company to continue filing quarterly reports reflecting deferred gas
costs and WACOG projections;
4. Order the Company to file an adjustment to its PGA-related rates, if gas prices
significantly deviate from projections; and
5. Consider late-filed comments from customers.
Respectfully submitted this 1 Ith day of September 2024.
Michael Duva
Deputy Attorney General
Technical Staff: James Chandler
Leena Gilman
Kimberly Loskot
Curtis Thaden
I:\Utility\UMISC\COMMENTS\INT-G-24-04 Comments.docx
STAFF COMMENTS 11 SEPTEMBER 11, 2024

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS L DAY OF SEPTEMBER 2024,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. INT-G-24-04, BY E-MAILING A COPY THEREOF, TO THE FOLLOWING:
LORI BLATTNER PRESTON N CARTER
DIR—REGULATORY AFFAIRS GIVENS PURSLEY LLP
INTERMOUNTAIN GAS CO 601 W BANNOCK ST
PO BOX 7608 BOISE ID 83702
BOISE ID 83707 E-MAIL: prestoncarter(a givenspurslecom
E-MAIL: lori.blattnergint ag s.com stgphaniewggivenspursley.com
1
PATRICIA JORDAN
CERTIFICATE OF SERVICE