20250912Staff Comments.pdf

RECEIVED
September 12, 2025
JEFFREY R. LOLL IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 11675
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 POWER COST ) CASE NO. AVU-E-25-07
ADJUSTMENT (PCA)ANNUAL RATE )
ADJUSTMENT FILING )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its attorney of record, Jeffrey R. Loll, Deputy Attorney
General, submits the following comments.
BACKGROUND
On July 31, 2025, Avista Corporation, doing business as Avista Utilities ("Company"),
filed its annual Power Cost Adjustment("PCA") application ("Application"). The Company
requests that the Commission issue an order approving the level of power costs deferred in the
rebate direction for the period of July 1, 2024, through June 30, 2025, and approving a PCA
rebate rate of 0.3010 per kilowatt-hour to be effective October 1, 2025. Application at 1.
The PCA is a mechanism used to track changes in revenues and costs associated with
variations in hydroelectric generation, secondary prices, thermal fuel costs, and changes in power
STAFF COMMENTS 1 SEPTEMBER 12, 2025

contract revenues and expenses. The present PCA rebate is a rate of 0.2460 per kilowatt-hour,
based on an overall rebate of approximately $7.9 million, which was approved by the
Commission in Order No. 36339, dated October 1, 2024, and is effective October 1, 2024,
through September 30, 2025.
The Company represents that the proposed PCA rate adjustment of 0.3010 per kilowatt-
hour would create a rebate of approximately $9.6 million to customers effective October 1, 2025.
Id. at 3. The Company states that the rebate is primarily associated with power supply costs that
were lower than those included in retail rates, due to higher off-system sales revenues, and that
the net effect of the expiring rebate, and the proposed rebate, is an overall decrease in revenue of
approximately 0.5 percent, or$1.756 million. Id.
STAFF REVIEW
Staff reviewed the Company's Application, testimonies of Company witnesses Kevin
Holland and Annette Brandon, monthly journals, and additional information provided in
responses to production requests. The results of Staff s review include: (1) a review of the PCA
deferral, (2) a prudence analysis of actual net power cost("NPC"), (3) an analysis of the PCA
rates, and(4) a review of the customer notice and press release.
Based on its review, Staff believes the PCA is generally prudent and recommends
approval of the Company's Application updating Schedule 66, Temporary Power Cost
Adjustment—Idaho, with Staff s adjustments as discussed in further detail below.
Review of PCA Deferral
Staff performed an audit of the Company's NPC by reviewing the Company's natural gas
purchases, market purchases, transmission revenue and expenses, and other deferral items.
Based on review of the transactions, Staff believes the various power cost transactions are
reasonable, prudently incurred, and comply with previous Commission orders and the
Company's risk management policies.
Under the Company's PCA mechanism, the Company and its ratepayers share the
difference between actual NPC and the NPC embedded in base rates. The sharing percentage is
90% for ratepayers and 10% for the Company. When actual costs are higher than those
recovered through base rates, Idaho customers pay 90% of the difference. When actual costs are
STAFF COMMENTS 2 SEPTEMBER 12, 2025

lower, customers are credited 90% of the difference, allowing the Company to keep 10%. See
Holland Direct at 7. This provides an incentive for the Company to lower NPC by operating its
system more efficiently.
Staff s recommended deferral balance is a negative $4,853,052 as shown on Table No. 1
below, resulting in a projected ending balance through September 2025 of negative $9,559,674.
Table No. 1: Summary of Power Supply and Deferrals for Current PCA Year-Idaho
Idaho Power Cost Deferral Amount
LCA' —Idaho Sales Adjustment $ (1,797,928)
Net Power Supply—Actual Minus Authorized (2,186,366)
RECZ Revenues (960,768)
Schedule 25P Net Cost (808,011)
EIM3 Incremental O&M 360,791
Total Cost (Subject to Company Sharing) $ (5,392,282)
Sharing Percentage over Authorized 90%
Total Idaho Deferral Amount $ (4,853,052)
Balancing Account
Beginning Balance as of July 2025 (11,302,437
Projected Amortization July 2025 through September 2025 1,876,276
Interest4 (133,513)
Projected Ending Balance through September 2025 (9,559,674)
1 Load Change Adjustment
2 Renewable Energy Credit
3 Energy Imbalance Market
4 Calculated using the Authorized Customer Deposit Rate of 5%per annum
Load Change Adjustment("LCA")—Idaho Sales Adjustment
The Idaho LCA captures the over-or under-recovery of net power supply expense through
base rates attributable to the difference between actual sales and sales used to set base rates. The
Company used the correct Load Change Adjustment Rate ("LCAR") of$24.41/Megawatt-hour
("MWh") for the months of July and August 2024, and an LCAR of$24.50/MWh for the months
of September 2024 to June 2025. See AVU-E-23-01 and AVU-E-25-01.
STAFF COMMENTS 3 SEPTEMBER 12, 2025

Net Power Supply Deferral—Actual Minus Authorized
The net power supply deferral captures the difference between actual NPC and the NPC
embedded in base rates for the twelve months ending June 30, 2024. The deferral includes the
following Federal Energy Regulatory Commission ("FERC")Uniform System of Accounts: 555
—Purchased Power, 447— Sale for Resale, 501 —Thermal Fuel, 547—CT Fuel, 456—
Transmission Revenue, 565 —Transmission Expense, 557—Resource Optimization, 537—MT
Invasive Species Expense, and 557—Expense Broker Fees.
During the review period, actual NPC was lower than the authorized NPC for the Idaho
jurisdiction. The Company's proposed Idaho's jurisdictional share of the base-to-actual
difference is $2,186,366. See Exhibit AMB-1.
Renewable Energy Credit Revenue
The Company books Renewable Energy Credit ("REC")revenue in FERC Account No.
557. Based on Order No. 33605, the Company has separately reported actual and authorized
REC revenue and expenses in its PCA filing. Idaho customers received a benefit of$960,768 for
REC revenues which reduce the deferral balance. Id. at 4.
Schedule 25P Net Cost—Idaho
In Order No. 34252, the Commission authorized a Power Purchase and Sale Agreement
between the Company and Clearwater Paper Corporation ("Clearwater"). Clearwater owns and
operates four thermal electric generating units rated at 132.2 MW. The units are cogeneration
qualifying facilities under the Public Utility Regulatory Policies Act of 1978. The agreement
allows the Company to purchase energy and capacity from Clearwater and directly assign it to
the Idaho jurisdiction. Any monthly difference between actual Clearwater power purchase
expense and the amount embedded in the base retail rates developed in AVU-E-23-01 general
rate case, is tracked through the PCA. Parties and ratepayers benefit from the Company selling
bundled RECs under the new agreement. Bundled RECs generally command a higher price than
unbundled REC's. Idaho customers received a benefit of$808,011 from the agreement during
the PCA year which helped offset the deferral balance. See Exhibit AMB-1 at 2.
STAFF COMMENTS 4 SEPTEMBER 12, 2025

Energy Imbalance Market(`BIM")
In Order Nos. 35156 and 35543, the Commission authorized the Company to include
EIM incremental expenses in the PCA up to the benefits realized from the EIM. The Company
included$360,791 (or$324,712 after sharing) in incremental EIM operation and maintenance
("O&M") expenditures for recovery in the Idaho PCA. Holland Direct at 8.
Renewable Portfolio Standard(Washington.) Compliance
In July 2024, the Company booked $2,755,522 of REC credits, which were retired for the
REC Retirement Benefit to meet Washington's Renewable Portfolio Standard("RPS"). The
credit is based on the Idaho allocation of RECs that were retired to meet Washington RPS (WA
I-937) that otherwise would have been sold. The RECs used to meet Washington RPS are
tracked 100% in the PCA. Id.
Prudence Analysis of Actual Net Power Cost
Staff believes that the Company's actual NPC during the PCA year(July 2024 through
June 2025) is reasonable and prudent. Staff analyzed the prudence of actual NPC in two ways.
First, for each of the accounts that make up NPC, Staff compared the actual amount of
generation and unit cost to amounts used to determine the Company's base rates (authorized) as
summarized in Table No. 2 below. Second, Staff analyzed plant downtime and several
Commission ordered adjustments that affected the Company's actual net power cost.
Analysis of Base-to-Actual Differences
Because the PCA deferral consists primarily of differences between authorized and actual
NPC, the analysis explains reasons for this year's rebate. Based on the analysis, Staff believes
that the Company dispatched its available resources cost-effectively and prudently by
dispatching its lower cost resources more and its higher cost resources less. The major drivers
affecting NPC in this year's PCA were: (1) an increase in electricity sales at prices higher than
authorized, (2) an increase in the amount of electricity purchases at prices lower than authorized,
(3) a lower amount of available hydro generation, and(4) an increase in natural gas generation at
costs less than authorized.
STAFF COMMENTS 5 SEPTEMBER 12, 2025

For the PCA year, the Company purchased 1,443,665 MWh over the authorized amount
and at a cost that was $8.04/MWh less than the cost reflected in base rates. Similarly, the
Company was able to sell 2,535,600 MWh over the authorized amount and at a price that was
$11.79/MWh greater than what was reflected in base rates. July 2024—June 2025 Variance
Analysis 7.14.25 excel file. Both of these items contributed to the Company's rebate amount.
The Company generated approximately 243,000 MWh less, or 5.2%with its hydro
generation. Id. Staff believes that the reduction is primarily due to decreased generation by
578,572 MWh from Clark Fork hydro. The Company states that the reduced generation in Clark
Fork hydro resulted from reduced river flow brought on by low snowpack and reduced
precipitation. Holland Direct at 14. To offset the reduced generation in hydro resources, the
Company dispatched its natural-gas generation resources by 993,724 MW more than the
amounts reflected in base rates and at a cost of$0.65/MWh less than the cost reflected in base
rates. Even though hydro generation decreased, increasing the amount of natural-gas generation
to make for the lost amount of hydro generation was prudent given that natural gas unit prices
were reasonable and contributed to the rebate in this year's PCA. Id. at 17.
Table No. 2: Generation and Unit Cost for Type of Resource
Actual Authorized Variance Actual Authorized
Resources Generation Generation MWh Unit Cost Unit Cost
MWh MWh $/MWh $/MWh
Purchases 1,898,044 454,379 1,443,665 31.17 39.21
Sales (4,181,443) (1,645,843) (2,535,600) 47.59 35.80
Hydro 4,433,195 4,676,075 (242,880) 16.6 6.11
Wind 19035,756 801,857 233,899 41.13 36.56
Thermal 1,698,922 1,845,646 (146,724) 23.84 17.11
Natural Gas 497189929 397259205 993,724 28.80 29.45
Plant Downtime
Excessive plant downtime can have a major impact on the Company's actual NPC passed
through the PCA. Staff reviewed the amount of planned and forced outages that occurred for
each of the Company's generating units provided in Company's response to Production Request
No. 10. Based on the review, Staff came to the following two conclusions: (1) the amount and
causes of downtime due to forced outages were reasonable when compared to downtime that
STAFF COMMENTS 6 SEPTEMBER 12, 2025

occurred during the previous year; and(2)the amount of planned outages had sound justification
and was reasonable, even though the amount of actual downtime for Colstrip Units 3 and 4 was
7.8% greater than the amount of time allotted by the Company.
Clearwater Adjustment
Staff believes that the Company correctly adjusted Clearwater's purchased power cost
included in the Company's actual Purchased Power expense in the Company's PCA. Staff
investigated whether the purchased power cost includes the Clearwater adjustment by comparing
the Power Deferral Calculation in the provided monthly journals included in response to
Production Request No. 19— Staff PR 019C. Staff verified through Company witness
Brandon's workpapers that the Company purchased $13.3 million of Clearwater's generation
during the deferral period.
In addition, Staff verified that 10% of transmission costs at a cost of$168,951 and REC
revenue of($979,962) are included in the deferral in accordance with Section 10(d) of the
Clearwater contract.
Boulder Park Dispatch Cost
In Case No. AVU-E-24-07, Order No. 36339, the Commission ordered the Company to
track the cost impact of using a Boulder Park dispatch cost without the cost of allowances over
the remaining PCA year and submit that data in next year's PCA filing. However, the Company
states that the allowance cost was not included in the dispatch, and it resulted in no lost revenue.
Holland Direct at 19.
Palouse Wind and Rattlesnake Flat Wind Adjustments
Staff verified that Purchased Power expense, Account No. 555, reduced the amount of
recovery for the actual cost of Palouse Wind and Rattlesnake Flat Wind to 90% after reviewing
the monthly journals and Company witness Brandon's workpapers. Commission Order No.
35909, required the Company to adjust 10% out of the actual cost of Palouse Wind and
Rattlesnake Flats from net power costs.
STAFF COMMENTS 7 SEPTEMBER 12, 2025

Columbia Basin Hydro/Chelan Hydro Adjustments
Staff believes the calculation for the CBH and Chelan hydro adjustment is consistent with
the agreed-to mechanism and is correct. Staff and the Company had a meeting and agreed on a
mechanism to re-evaluate the "lesser of market or contract cost prior to filing this PCA case to
be consistent with Order No. 36339. Staff compared the cost in the agreed-to mechanism to the
actual amounts in the Company's response to Staff Production Request No. 17—Confidential
Attachment and confirmed that the CBH and Chelan Hydro adjustment calculations are
consistent with the agreed-to mechanism. Staff also confirmed that the adjustments of CBH and
Chelan Hydro would be included in actual Purchased Power expense by comparing the provided
monthly journal to Brandon's workpapers. In addition, Staff verified that the contract cost for
Chelan hydro increased from $1,755,720 to $1,790,648 starting January 2025. See Company's
response to Staff Production Request No. 18.
The mechanism also allows the Company to recover all or some of the approximately
$1.013 million in transmission cost to the extent that market prices are higher than the cost of
CBH generation, with the cost of transmission included, as calculated in the Company's response
to Staff Production Request No. 17—Confidential Attachment. Staff verified the transmission
cost by reviewing transmission invoices provided in the forementioned re-evaluation meeting
before filing this PCA.
Analysis of PCA Rates
PCA rate adjustments are spread on a uniform cents per kWh basis. Based on its review
of the PCA rate calculations, Staff verified that the result is accurate and will reasonably refund
customers for overcollection of actual NPC embedded in base rates. Staff compared the
Company's forecasted load during the rate effective year to its actual sales during the deferral
period and believes the forecasted load is reasonable. Using the PCA rebate rate of 0.3010 per
kilowatt-hour, residential customers using an average of 939 kilowatt-hours per month would see
their monthly bills decrease from $104.30 to $103.79, a decrease of$0.51 per month, or 0.5%.
Table No. 3 provides a summary of the PCA rate calculation to be effective October 1, 2025, if
authorized.
STAFF COMMENTS 8 SEPTEMBER 12, 2025

Table No. 3: Summary of Proposed Rebate Rate
A. Total Amortization and Deferral Balance including interest through 9/30/25 ($9,559,674)
B. Conversion Factor(Case No.AVU-E-23-01: Per Final Stipulation&Settlement 0.995661
C. Revenue Requirement(AB) ($9,602,000)
D. System forecasted load from October 1,2025 to September 30,2026(kWh) 3,193,504,000
E. Proposed Rate(C/D) ($0.00301)
Table No. 4 provides the percent change by customer class to show the impact to each
class. Because the PCA rate adjustments are spread on a uniform cents-per-kWh basis, the
resulting revenue percentage change varies by customer class.
Table No. 4: Percent Change of Billed Revenue by Schedule
Customer Class Forecasted Revenue at Present Proposed Change Percent
MWh Rates(000s) (000s) Change
Residential 1,345,606 $ 165,358 $ (740) -0.4%
General Service 923,919 $ 90,280 $ (508) -0.6%
Large General Service 133,466 $ 18,739 $ (73) -0.4%
Extra Large General Service 349,435 $ 22,327 $ (192) -0.9%
Clearwater 368,629 $ 36,136 $ (203) -0.6%
Pumping Service 62,677 $ 7,577 $ (34) -0.4%
Street&Area Lights 9,772 $ 4,530 $ (5) -0.1%
Total 3,193,504 $ 344,947 $ (1,755) -0.5%
Overall Impact of Four Filings (PCA, ResEx, EE Rider, and FCA) Effective October 1,
2025
The Company proposed four electric rate adjustments effective October 1, 2025. If
approved as filed, the Company's PCA, AVU-E-25-07, will decrease the Company's electric
revenues by $1.8 million (0.6% decrease). The Fixed Cost Adjustment("FCA") filing, AVU-E-
25-08, if approved, will increase electric revenues by about $2.6 million (0.6% increase). The
third proposed filing, Bonneville Power Administration Residential Exchange Program
("ResEx"), AVU-E-25-09, if approved, will increase electric revenues by $1.9 million(0.6%
increase). The final proposed filing, Schedule 91, Energy Efficiency Rider Adjustment("EE
STAFF COMMENTS 9 SEPTEMBER 12, 2025

Rider"), AVU-E-25-10, if approved, will increase electric revenues for participants by $3.6
million(1.2% increase). Avista Customer Notice at 1.
The net effect of Company's four filings (PCA, FCA, ResEx, and EE Rider) will increase
electric revenues by about $6.3 million (2.0% increase). The average residential electric
customer's monthly bill may increase by$3.43 or 3.3%. Id. Table No. 5 summarizes the overall
impact to electric revenues of the four filings:
Table No. 5: Summary of Overall Impact to Electric Revenues
Filing Change in Revenues % Change
PCA ($1.8 million) -0.6%
FCA $2.6 million 0.8%
ResEx Credit $1.9 million 0.6%
EE Rider $3.6 million 1.2%
Total $6.3 million 2.0%
Customer 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'. 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 September 12, 2025, no customer comments had been filed. The Commission set a
comment deadline of September 12, 2025. Some customers in the last billing cycles may not
have received or had adequate time to submit comments before the 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.
1 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 10 SEPTEMBER 12, 2025

STAFF RECOMMENDATION
Based on its review of the Company's Application and Staff s audit of the PCA
components, Staff recommends the Commission approve a deferral balance of$9,559,674. Staff
further recommends the Commission approve the Company's request to revise its Tariff
Schedule 66, Temporary Power Cost Adjustment—Idaho as filed, resulting in a decrease to the
Company's annual revenue of approximately $1.756 million, with an effective date of October 1,
2025. Finally, Staff recommends the Commission accept and consider any late filed comments
from customers.
Respectfully submitted this 12th day of September 2025.
i
d;�/ 4
ffrey oll
Deputy Attorney General
Technical Staff. Travis Culbertson
Seungjae Lee
Michael Ott
Curtis Thaden
I:\Utility\UMISC\COMMENTS\AVU-E-25-07 Comments.docx
STAFF COMMENTS 11 SEPTEMBER 12, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 121h DAY OF SEPTEMBER 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF , IN CASE
NO. AVU-E-25-07, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
PATRICK EHRBAR DAVID J. MEYER
DIR OF REGULATORY AFFAIRS VP & CHIEF COUNSEL
AVISTA CORPORATION AVISTA CORPORATION
PO BOX 3727, MSC-27 PO BOX 3727, MSC-10
1411 E. MISSION AVE 1411 E. MISSION AVE
SPOKANE WA 99220-3727 SPOKANE WA 99220-3727
E-mail: patrick.ehrbar(c avistacorp.com E-mail: david.meer(c avistacorp.com
avistadocketskavistacorp.com
PATRICIA JORD: , SECRETARY
CERTIFICATE OF SERVICE