20230907Application.pdf

Case No. AVU-G-23-06 Page 1 of 5

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION OF )
AVISTA UTILITIES FOR AN ORDER APPROVING ) CASE: AVU-G-23-06
A CHANGE IN RATES FOR PURCHASED GAS )
COSTS AND AMORTIZATION OF GAS-RELATED )
DEFERRAL BALANCES )

Application is hereby made to the Idaho Public Utilities Commission for an Order approving a revised
schedule of rates and charges for natural gas service in the state of Idaho. The Applicant requests that
the proposed rates included in this Purchased Gas Cost Adjustment (“PGA”) filing be made effective on
November 1, 2023. If approved as filed, the Company’s annual revenue will increase by approximately
$5.4 million or about 5.0%. In support of this Application, Applicant states as follows:

I.

The name of the Applicant is AVISTA CORPORATION, doing business as AVISTA UTILITIES
(hereinafter Avista, Applicant or Company), a Washington corporation, whose principal business office
is 1411 East Mission Avenue, Spokane, Washington, and is qualified to do business in the state of Idaho.
Applicant maintains district offices in Moscow, Lewiston, Coeur d'Alene, Sandpoint, and Kellogg,
Idaho. Communications in reference to this Application should be addressed to:

Patrick D. Ehrbar
Director of Regulatory Affairs
Avista Utilities
1411 E. Mission Avenue
Spokane, WA 99220-3727
Phone: [phone]
[e-mail]
[e-mail]

II.

Attorney for the Applicant and his address is as follows:

David J. Meyer
Vice President and Chief Counsel for Regulatory
And Governmental Affairs
Avista Utilities
1411 E. Mission Avenue
Spokane, WA 99220-3727
Phone: [phone]
[e-mail]
RECEIVED
Thursday, September 7, 2023 2:19:26 PM
IDAHO PUBLIC
UTILITIES COMMISSION
Case No. AVU-G-23-06 Page 2 of 5

III.

The Applicant is a public utility engaged in the distribution of natural gas in certain portions of Northern
Idaho, Eastern and Central Washington, and Southwestern and Northeastern Oregon, and further
engaged in the generation, transmission, and distribution of electricity in Northern Idaho and Eastern
Washington.

IV.

Thirty-Third Revision Sheet 150, which Applicant requests the Commission approve, is filed herewith
as Exhibit "A". Additionally, Twenty-Fifth Revision Sheet 155, which Applicant requests the
Commission approve, is also filed herewith as Exhibit "A". Also included in Exhibit "A" is a copy of
Thirty-Second Revision Sheet 150 and Twenty-Fourth Revision Tariff Sheet 155 with the changes
underlined and a copy of Thirty-First Revision Sheet 150 and Twenty-Third Revision Tariff Sheet 155
with the proposed changes shown by lining over the current language or rates.

V.

The existing rates and charges for natural gas service on file with the Commission and designated as
Applicant's Tariff IPUC No. 27, which will be superseded by the rates and charges filed herewith, are
incorporated herein as though fully attached hereto.

VI.

Notice to the Public of Applicant's proposed tariffs is to be given simultaneously with the filing of this
Application by posting, at each of the Company's district offices in Idaho, a Notice in the form attached
hereto as Exhibit "B" and by means of a press release distributed to various informational agencies, a
draft copy attached hereto in Exhibit “C”. In addition, Exhibit “C” to this Application also contains the
form of customer notice that the Company will send to its customers in its monthly bills in the September
timeframe.

VII.

The circumstances and conditions relied on for approval of Applicant's revised rates are as follows:
Applicant purchases natural gas for customer usage and transports it over Williams Northwest Pipeline,
Gas Transmission Northwest (GTN), TC Energy - Alberta, TC Energy - BC and Enbridge Energy
Pipeline systems, and defers the effect of timing differences due to implementation of rate changes and
differences between Applicant's actual weighted average cost of gas (“WACOG”) purchased and the
WACOG embedded in rates. Applicant also defers various pipeline refunds or charges and
miscellaneous revenue received from natural gas related transactions including pipeline capacity
releases. Workpapers for all proposed Commodity, Demand and Amortization costs are provided with
this filing as Exhibit “D”.

VIII.

This filing reflects the Company’s proposed annual PGA to: 1) pass through changes in the estimated
cost of natural gas for the period of November 2023 through October 2024 (Schedule 150), and 2) revise
Case No. AVU-G-23-06 Page 3 of 5

the amortization rate(s) to refund or collect the balance of deferred natural gas costs (Schedule 155).
Below is a table summarizing the proposed rate changes reflected in this filing:

IX.

Schedule 150 / Purchase Gas Cost - Commodity Costs

As shown in the table above, the estimated WACOG change is a decrease of $0.06236 per therm; the
proposed WACOG of $0.28834 per therm compared to the present WACOG of $0.35070 per therm
included in rates. The decrease is a result of current forward prices being lower compared to when the
Company filed its PGA in the prior year, however, the natural gas market in the western US experienced
a period of extreme pricing volatility this winter due to a confluence of fundamental factors in the
region. Prolonged colder than average temperatures region wide, combined with below average hydro
generation led to a market where gas fired electric generators and LDC’s were competing for a limited
supply of natural gas.

Generally speaking, the electric interconnection between the Pacific Northwest and California played a
key role in the price volatility in the region. California has in recent years relied on imports of power
from the Northwest to balance its system in the winter. Lower than average precipitation during the fall
reduced hydro output in the northwest this year which forced Mid-C power prices high enough to
disincentivize power exports to California. California’s only option to cover the missing imports was to
increase gas-fired generation which put additional pressure on the natural gas market. These conditions
persisted for most of the winter and forced both generators and LDC’s to rely on storage withdrawals
more than usual. Storage balances throughout the region were drawn down earlier than normal which
put even more upward pressure on the market. Prices at most West Coast trading hubs were consistently
5 to 10 times higher than they have been for the past several years. The exception was the AECO hub
in western Canada which was not affected by the supply constraints experienced south of the border.

Although natural gas market prices in the western US experienced extreme pricing this past winter, by
early spring demand had tapered. Hydroelectric generation was strong, and weather was moderate,
resulting in healthy storage injections in the region this past spring and early summer at much lower
prices than the previous year. Nationwide, production has ramped up and storage balances are above the
5-year average putting downward pressure on forward prices. These factors resulted in forward prices
for the upcoming PGA year less than what they were for the 2022-23 PGA year.

Avista has been hedging natural gas on both a periodic and discretionary basis throughout the previous
thirty-six months for the forthcoming PGA year. Approximately 58% of the annual load requirements
for this year’s PGA period (November 2023 through October 2024) have been hedged at a fixed-price
Commodity Demand Total Amortization Total PGA
Sch.Change Change Sch. 150 Change Rate Change
Service No.per therm per therm Change per therm per therm
General 101 (0.06236)$ (0.00354)$ (0.06590)$ 0.12118$ 0.05528$
Lg. General 111 (0.06236)$ (0.00354)$ (0.06590)$ 0.12118$ 0.05528$
Lg General 112 (0.06236)$ (0.00354)$ (0.06590)$ -$ (0.06590)$
Interruptible 131 (0.06236)$ -$ (0.06236)$ -$ (0.06236)$
Transportation 146 -$ -$ -$ -$ -$
Case No. AVU-G-23-06 Page 4 of 5

derived from the Company’s Plan. Through June, the hedge volumes for the PGA period have been
executed at a weighted average price of $3.66 per dekatherm ($0.3660 per therm).

Available underground storage capacity at the Jackson Prairie Natural Gas Storage Facility represents
approximately 23% of annual load requirements (30% of load requirements during the December to
March withdrawal period). The estimated WACOG for all storage volumes is $2.01 per dekatherm
($0.2009 per therm). The Company utilizes its underground storage to capture seasonal price spreads
(differentials), improve the reliability of supply, increase operational flexibility and mitigate peak
demand price spikes.

The Company used a 30-day historical average of AECO forward prices (ending July 31, 2023) to
develop an estimated cost associated with index purchases. These index purchases represent
approximately 19% of estimated annual load requirements for the coming year. The annual weighted
average price for these volumes is $2.25 per dekatherm ($0.2247 per therm).

X.

Schedule 150 / Purchase Gas Cost - Demand Costs

Demand costs reflect the cost of pipeline transportation to the Company’s system, as well as fixed costs
associated with natural gas storage. As shown in the table above, demand costs are expected to decrease
for residential customers by approximately $0.00354 per therm. This decrease 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.

XI.

Schedule 155 / Amortization Rate Change

As shown in the table above, the proposed amortization rate change for Schedule 101 and Schedule 111
is an increase in revenue of $0.12118 per therm. The current rate applicable to Schedule 101 and
Schedule 111 is $0.13163 per therm in the surcharge direction; the proposed rate is $0.25281 per therm
in the surcharge direction.

In this PGA filing, the Company has used the deferral and amortization balances as of July 31, 2023,
inclusive of the residual amortization balance from the prior PGA, and proposed amortizing the balance
over 12-months which is consistent with historical PGA filings. The company included forecasted
amortization of the prior year surcharge deferral balance from August 1, 2023 through October 31, 2023
being collected through Schedule 155, which reduced the surcharge balance to be collected in the
upcoming PGA year by approximately $1.7 million. The result is a surcharge amortization rate to collect
approximately $24.7 million from customers. On a per therm basis, the net impact of the expiring
amortization surcharge and the new amortization surcharge is a change in the amortization rate of
$0.12118 per therm.

XII.

If approved as filed, the Company’s annual revenue will increase by approximately $5.4 million or about
5.0% effective November 1, 2023. Residential or small commercial customers using an average of 64
Case No. AVU-G-23-06 Page 5 of 5

therms per month would see an increase of $3.54 per month, or approximately 4.7%. The present bill
for 64 therms is $74.62 while the proposed bill is $78.16.

XIII.

Exhibit "D" attached hereto contains support workpapers for the Proposed Tariff Rates proposed by
Applicant contained in Exhibit "A".

XIV.

Avista requests that the rates proposed in this filing be approved to become effective on November 1,
2023, and requests that the matter be processed under the Commission’s Modified Procedure rules
through the use of written comments. Avista stands ready for immediate consideration on its
Application.

XV.

WHEREFORE, Avista requests the Commission issue its Order finding its proposed rates to be just,
reasonable, and nondiscriminatory and to become effective for all natural gas service on and after
November 1, 2023. The overall increase is approximately $5.4 million or 5.0%. The Company requests
that the matter be processed under the Commission’s Modified Procedure rules through the use of written
comments.

Dated at Spokane, Washington, this 1st day of September 2023.

AVISTA UTILITIES
BY

/s/ David J. Meyer
______________________________________
David J. Meyer
Vice President and Chief Counsel for
Regulatory & Governmental Affairs
Avista Corporation