20251009Staff Comments.pdf

RECEIVED
October 09, 2025
ERIKA K. MELANSON IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 11560
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 AVISTA )
CORPORATION'S APPLICATION FOR AN ) CASE NO. AVU-G-25-07
ORDER APPROVING A CHANGE IN RATES )
FOR PURCHASED GAS COSTS AND )
AMORTIZATION OF GAS-RELATED ) COMMENTS OF THE
DEFERRAL BALANCES ) COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its attorney of record, Erika K. Melanson, Deputy Attorney
General, submits the following comments.
BACKGROUND
On July 31, 2025, Avista Corporation ("Company") applied to the Commission for an
order approving a revised schedule of rates and charges for natural gas service in the state of
Idaho ("Application"). If the Company's Application is approved as filed, the monthly bill of an
average residential or small commercial customer using 66 therms per month would decrease
$4.13, or approximately 6.4%. The Company has requested the proposed rates in this Purchased
Gas Cost Adjustment("PGA") filing be made effective on November 1, 2025.
STAFF COMMENTS 1 OCTOBER 9, 2025

The Company's rates include a base-rate component and a gas-related cost—PGA—
component. The base-rate component is intended to cover the Company's fixed costs to serve its
customers—for example, the Company's costs for equipment and facilities to provide service—
and rarely change. The Company's PGA is a Commission-approved mechanism that adjusts
rates up or down to reflect actual changes in the Company's costs to buy natural gas from
suppliers (compared to the same cost assumptions embedded in rates)—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 states that, if approved as filed, the Company's annual revenue will
decrease by approximately $6.5 million or about 7.2%. Application at 1.
The Company represents that its proposed PGA will: (1)pass through changes in the
estimated cost of natural gas for the period of November 2025 through October 2026, and(2)
revise the amortization rate(s)to refund or collect the balance of deferred natural gas costs. Id. at
2.
The proposed weighted average cost of gas ("WACOG") in the Company's Application
would change from the $0.23850 per therm currently included in rates to $0.21148 per therm—a
decrease in natural gas costs compared to those currently included in rates. Id. at 3.
The Company states the demand costs are expected to increase for residential customers
by approximately $0.00985 per therm. Id. at 4.
The Company's proposed amortization rate change for Schedules 101 and 111 is a
decrease in revenue of$0.04544 per therm. Id.
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.
STAFF ANALYSIS
Staff examined the Company's Application and accompanying workpapers and
recommends the Commission approve the Company's Application to decrease natural gas
revenues in Idaho by approximately $6.5 million, or about 7.2%. Id. Staff determined that the
Company's proposed WACOG request is reasonable, as is the Company's reported Lost and
Unaccounted For("LAUF") gas volumes. Staff verified that the Company's filing will not
STAFF COMMENTS 2 OCTOBER 9, 2025

change the Company's earnings and confirmed that the proposed changes to Tariff Schedules
150 and 155 accurately capture the Company's fixed(demand) and variable (commodity) costs
given the coming year's forecasted gas purchases and properly amortizes the deferral balance
from the prior year.
Weighted Average Cost of Gas
The WACOG includes calculated costs from Schedule 150, Gas Research Institute
funding, and the Revenue Conversion Factor. The WACOG is a forward-looking estimate of
those costs. In this case, the Company proposes a WACOG of$0.21148 per therm. Application
at 3. This is a decrease of approximately 11.33% from the current approved WACOG of
$0.23850 per therm. This decrease is a result of current forward prices being lower compared to
when the Company filed its PGA in the prior year. Id. Staff encourages the Company to update
its WACOG if gas prices materially deviate.
Chart No. 1 below illustrates the changes in WACOG over time.
Chart No. 1: Historical WACOG
Avista WACOG($/Therm)
$0.4000
$0.3500
E $0.3000
$0.2500
t $0.2000
$0.1500
$0.1000
$0.0500
$0.0000
2016 2017 2017 2018 2019 2020 2021 2021 2022 2023 2024 2025
$0.2400 $0.2190 $0.1640 $0.1700 $0.1533 $0.1624 $0.2030 $0.2654 $0.3518 $0.2883 $0.2385 $0.2115
Year
Schedule 150—Purchased Gas Cost Adjustment
Tariff Schedule 150 is a component of the PGA and includes both commodity and
demand costs. The Company's commodity costs consist of expenses incurred by the Company
related to the purchase or production of natural gas, transportation of gas to the city gate, storage,
and the transmission and distribution costs required to deliver natural gas to customers. The
Company estimates its commodity costs without a gross revenue factor will decrease from the
currently approved $0.23760 per therm to $0.21056 per therm. Exhibit A. The proposed
STAFF COMMENTS 3 OCTOBER 9, 2025

decrease is primarily related to lower forward prices compared to the prior PGA. Application at
3.
The Company's demand costs are the costs incurred for the interstate transportation of
natural gas. The demand costs of Schedule 150 without a gross revenue factor includes an
increase for customers of$0.00976 per therm, increasing from $0.08961 to $0.09937. Exhibit A.
This increase is related to a variety of factors including Canadian exchange rate, updated demand
forecast, and new pipeline rates in effect during the upcoming PGA year. Application at 4.
Schedule 155—Amortization of the Deferral Account
Tariff Schedule 155 reflects the amortization of the Company's deferral account. The
deferral consists of the difference in the price the Company paid for natural gas and the WACOG
established in the previous PGA. The Company's proposed amortization rate change for
Schedule 101 and Schedule I I I is a decrease in revenue of$0.04544 per therm. The current rate
for Schedule 101 and Schedule I I I is $0.01734 per therm in the rebate direction and the
proposed rate is $0.06278 per therm in the rebate direction reflecting the $0.04544 decrease. Id.
Included in the deferral activity are two items that benefit customers: excess capacity
releases totaling $3,077,923—discussed in detail in the Procurement Plan section below and the
benefits from the Deferred Exchange Contract totaling $2,496,113. The associated benefits,
along with the excess capacity releases, are included in the deferral activity shown in Table No.
1. The deferral also includes the monthly interest charges on the deferred balances.
The Company calculated the balance for amortization to be $6,380,991. On a per therm
basis, the net impact of the expiring amortization surcharge and the proposed amortization rebate
of$0.06278 is a change of$0.04544.
In the workpapers, which accompanied Exhibit D in the Application, the Company
provided a reconciliation of Tariff Schedule 155 deferral and amortization, which is shown in
Table No. 1 below:
STAFF COMMENTS 4 OCTOBER 9, 2025

Table No. 1: PGA Deferral and Amortization Reconciliation
Amortization Balance as of June 30, 2024 $ 3,821,930
Amortization Activity (2,153,943)
True-Up (November 1, 2024) 3,882,275
Interest on Unamortized Balance (50,378)
Total Unamortized Balance $ 5,499,884
Current Year Deferral Activity
Deferral Balance as of June 30, 2024 $ 1,955,830
Deferral of Demand Costs 4,013,541
Deferral of Commodity Price Differences (4,597,471)
Interest on Deferrals 120,189
Excess Capacity Releases (3,077,923)
Deferred Exchange Contract (2,496,113)
Total Amortization Balance $ 12,116,268
Total Balance to be amortized via Rate Schedule 155 (6,380,991
Market Fundamentals and Price Analysis
Throughout the previous thirty-six months, the Company has been hedging natural gas on
both a periodic and discretionary basis for the upcoming PGA year. Application at 3.
Approximately 50% of the annual load requirements for this year's PGA period(November 2025
through October 2026)have been hedged at a fixed price derived from the Company's
Procurement Plan. Id. Through June, the hedged volumes for the PGA period have been
executed at a weighted average price of$2.73 per dekatherm, or$0.27331 per therm. Id.
The Company used a 30-day historical average of AECO forward prices (ending June 30,
2025) to develop an estimated cost associated with index purchases. Id. at 4. The index
purchases represent approximately 33% of estimated annual load requirements for the coming
year. Id. The annual weighted average price for these volumes is $2.58 per dekatherm, or
$0.2584 per therm. Id. Last year the annual weighted average price was $2.19 per dekatherm, or
$0.2186 per therm.
Staff also examined the forecasts of national and regional organizations to see how
perceived market conditions might vary from the NYMEX/NGX futures prices. Specifically,
STAFF COMMENTS 5 OCTOBER 9, 2025

Staff reviewed the forecasts from the Energy Information Administration("EIA").' The EIA
Short-Term Energy Natural Gas Outlook' states:
Natural Gas
Historically, average annual prices for gas and oil change in tandem. We expect this year will be
the first time they move in the opposite direction since 2014.By 2026, we forecast natural gas
prices will be nearly double compared with 2024, while the West Texas Intermediate(WTI)crude
oil price in our outlook falls 3801o, leading to the lowest crude oil-to-natural gas price premium
since 2005 at just over$4.00/MMBtu. The U.S. benchmark Henry Hub natural gas price averaged
$3.66IMMBtu in the first half of 2025(IH25), 67%higher than the 2024 annual average of
$2.19IMMBtu. In contrast, the U.S. benchmark WTI crude oil price has averaged about
$12.00/MMBtu in I H25, 11%lower than the 2024 annual average.
With these price movements, we expect decreases in natural gas produced as a byproduct of oil
directed drilling will offset increases in that produced by natural gas-directed drilling. Overall, we
expect U.S. marketed natural gas production will average 117.1 billion cubic feet per day(Bcf/d) in
2025 and 116.8 Bcf/d in 2026
Natural gas inventories
Natural gas inventories remain relatively high, and August ended with 6%more natural gas in
storage compared with the five year average. The Henry Hub spot price averaged$2.91IMMBtu in
August(10%below our August STEO estimate).Lower prices over this summer have been driven
by robust production and reduced natural gas consumption in the electric power sector.However,
we continue to expect prices will gradually rise through the upcoming winter because inventories in
our forecast are withdrawn at faster-than-normal rate this winter. The relatively strong inventory
draws in our forecast mostly reflect rising LNG exports amid flattening U.S natural gas production.
We forecast U.S. natural gas inventories will end March at I%above the five year average.In the
forecast, the Henry Hub price reaches its winter peak in January at$4.60IMMBtu.
Based on Staff s review of the market fundamentals and trends, Staff believes that the
Company's cost of its current hedges and estimated cost of forward-looking index purchases are
reasonable.
Procurement Plan
The Company uses a diversified approach to procure natural gas for the coming PGA
year. The Company's Procurement Plan uses a structured approach to execute its hedges that
'EIA website Homepage-U.S.Energy Information Administration(EIA).
z Source Short-Term Energy Outlook-U.S.Energy Information Administration(EIA)(Last visited Sep 18,2025).
STAFF COMMENTS 6 OCTOBER 9, 2025

includes a range of possible hedge windows with varying long-term and short-term trigger
prices. However, its Procurement Plan also allows it to make discretionary decisions so it can
adjust to changes in market conditions.
Capacity Release
The Company buys the right to transport gas through several interstate pipelines. This
enables the Company to buy natural gas from a variety of supply basins,both in the U.S. and in
Canada, and then transport that gas to its service territory. Whenever the Company has surplus
capacity on the pipelines that serve its customers, surplus capacity is sold to other pipeline users,
and the resulting revenue is included in the amortization calculations. The Company's total
excess capacity release revenue this year for Idaho was $3,077,923.
Lost and Unaccounted for Gas3
Staff reviewed the Company's LAUF gas rate and compared it to previous years. The
Company reported a LAUF gas rate of 2.61% lost gas. Exhibit D. Staff examined the
Company's supporting LAUF gas workpapers and reconciled this data with the information
reported to the Pipeline and Hazardous Material Safety Administration. Staff notes that the five-
year average is 0.78% lost gas. Id.
Reporting
Staff recommends the Company continues the quarterly submission of the WACOG
report, the Gas Accounting Data Download ("GADD") report, and deferred costs report with a
journal entry as they have been. Additionally, Staff recommends the Company continue to
submit the deferral calculation workbook("DCW") in Excel format. The workbook summarizes
the numbers in the GADD and ties them to the PGA workpaper. The DCW workbook needs to
be filed with the last quarterly report before the PGA Application.
s The American Gas Association describes unaccounted for natural gas in the utility system,defined as follows:At a
city gate,natural gas is transferred from an interstate or intrastate pipeline to a local natural gas utility.At that
moment,some utilities measure the volume of gas using highly sophisticated technology that can quickly and
precisely take into account a variety of factors,including temperature and pressure. The utility reports the volume of
gas sold to customers as represented on their bills. The difference between the city-gate measurement and the
volume of gas sold is treated as unaccounted for gas by regulators,who build a form of reimbursement for this gas
into the utility's rate structure.
STAFF COMMENTS 7 OCTOBER 9, 2025

The reports requested have provided Staff with an opportunity to improve efficiencies,
decrease turnaround time of data requests, and decrease the number of Staff s audit/production
requests.
Customer Comments,Notice, and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined both met the requirements of Rule 125 of the
Commission's Rules of Procedure.4 See IDAPA 31.01.01 .125. The notice was included with
bills mailed to customers beginning August 1, 2025, and ending August 29, 2025.
As of October 9, 2025, no customer comments had been filed. The Commission set a
comment deadline of October 9, 2025,providing customers with a reasonable opportunity to file
timely comments.
STAFF RECOMMENDATION
After examining the Company's Application, natural gas purchases, and deferral activity
for the year, Staff recommends that Commission:
1. Approve the Company's proposed Tariff Schedule 150, with the proposed WACOG
of$0.21148 per therm and demand charge of$0.09980 per therm, for a total of
$0.31128 per therm, as filed;
2. Approve the Company's proposed Tariff Schedule 155, with the proposed
amortization rebate rate of$.06278 per therm, as filed;
3. Direct the Company to continue filing WACOG reports, GADD reports, and deferred
costs report with journal entries quarterly, as they have been, and the DCW workbook
in Excel format with the last quarterly report before the next PGA filing; and
4. Consider late-filed comments from customers.
4 The press release and customer notice addressed the following cases: Electric:AVU-E-25-07 Power Cost
Adjustment(PCA),AVU-E-25-08 Fixed Cost Adjustment(FCA),AVU-E-25-09 Bonneville Power Administration
Residential Exchange(ResEx),and AVU-E-25-10 Energy Efficiency. Natural Gas:AVU-G-25-05 Fixed Cost
Adjustment(FCA),AVU-G-25-06 Energy Efficiency,and AVU-G-25-07 Purchased Gas Cost(PGA).
STAFF COMMENTS 8 OCTOBER 9, 2025

STAFF RECOMMENDATION
Respectfully submitted this 9th day of October 2025.
Erika K. Melanson
Deputy Attorney General
Technical Staff. Leena Gilman
Vicki Stephens
Curtis Thaden
I:\Utility\UMISC\COMMENTS\AVU-G-25-07 Comments.docx
STAFF COMMENTS 9 OCTOBER 9, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 91h DAY OF OCTOBER 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF , IN CASE
NO. AVU-G-25-07, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
DAVID J MEYER PATRICK D. EHRBAR
VP & CHIEF COUNSEL DIRECTOR OF REGULATORY AFFAIRS
AVISTA UTILITIES AVISTA UTILITIES
1411 E. MISSION AVE 1411 E. MISSION AVE
SPOKANE WA 99220-3727 SPOKANE WA 99220-3727
E-mail: david.me ergavistacorp.com E-mail: pat.ehrbargavistacorp.com
dockets(d),avistacorp.com
PATRIC'IA JORD , SECRETARY
CERTIFICATE OF SERVICE