20260909Staff Comments.pdf

RECEIVED
September 09, 2026
ERIKA K. MELANSON IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83702
[phone]
IDAHO BAR NO. 11560
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF AVISTA )
CORPORATION'S POWER COST ) CASE NO. AVU-E-26-05
ADJUSTMENT 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, Erika K. Melanson, Deputy Attorney
General, submits the following comments.
BACKGROUND
On July 31, 2026,Avista Corporation("Company") applied to the Commission requesting
approval of the proposed Power Cost Adjustment ("PCA") surcharge for recovery of deferred
power costs for the period July 1, 2025, through June 30, 2026, effective October 1, 2026
("Application").
On August 6, 2026, the Company amended its Application to correct scrivener's errors
("Amended Application").
The PCA is a mechanism that monitors changes in revenues and costs associated with
hydroelectric generation, secondary market prices, thermal fuel costs, and revenues and expenses
from power contracts. Amended Application at 2. The current PCA rebate rate is 0.3010 per
kilowatt-hour ("kWh"), based on an overall rebate of approximately $9.6 million, which the
STAFF COMMENTS 1 SEPTEMBER 9, 2026

Commission approved in Order No. 36777, effective October 1, 2025, through September 30,
2026.
The Company represents that the proposed PCA rate adjustment of 0.1570 per kWh would
result in a surcharge of approximately $14.6 million to customers effective October 1, 2026. Id.
at 3.
The Company states that the proposed surcharge is explained by the expiration of the
existing rebate rate and power supply costs that exceeded the costs embedded in retail rates. Id.
The Company attributes the higher costs primarily to lower market energy prices,the exclusion of
certain wind generation resources from the authorized base for September 2025 through August
2026, and higher customer loads during several months of the year. Id.
STAFF ANALYSIS
Staff reviewed the Company's Amended Application, testimony of Company witnesses
Kevin Holland and Annette Brandon, monthly journals, and additional information provided in
responses to Staff requests. Staff s review consisted of. (1) a review of the PCA deferrals, (2) a
prudence review of actual net power cost ("NPC"), (3) an analysis of the PCA rate, 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 Amended Application to update
Schedule 66, Temporary Power Cost Adjustment—Idaho, subject to Staffs 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 revenues and expenses, and other deferral items. Staff
selected a sample of transactions and believes the sampled power cost transactions are reasonable,
prudently incurred, and consistent with previous Commission orders and the Company's risk
management policies. Under the Company's PCA mechanism, the Company and its customers
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 lower,customers are credited 90%of the difference,with the Company retaining 10%. Holland
STAFF COMMENTS 2 SEPTEMBER 9, 2026

Direct at 8. The sharing mechanism provides an incentive for the Company to lower NPC by
operating its system more efficiently.
The Company calculated a total balance of $4,979,318 to be collected from customers
through the updated PCA rate. Brandon Direct, Table No. 2 at 5. Table No. 1 below summarizes
the PCA calculation, including the beginning balance in July 2025, actual deferrals through June
2026, and projected amortization and interest through September 2026. Staff reviewed the
calculations for each month's PCA balance and a sample of invoices supporting the Company's
actual NPC. Staff reviewed the Company's calculations and verified the total PCA balance of
$4,979,318. Staff recommends that the Commission authorize recovery of the balance to be
collected through the updated PCA rate discussed later in these comments.
Table No. 1: Summary of Balancing Account for Current PCA Year-Idaho
Row PCA Balance
A Beginning Balance July 2025 $ (11,302,437)
B Net Power Cost Deferral July 2025 through June 2026 $ 8,227,143
C Amortizations July 2025 through June 2026 (Return to Customers) $ 8,705,512
D REC Retirement Benefit $ (2,717,969)
E Interest July 2025 through June 2026 $ (298,028)
F Beginning Balance as of July 2026 (SUM Ato E) $ 2,614,221
G Projected Amortization July 2026 through September 2026 $ 2,331,366
H Projected Interest July 2026 through September 2026 $ 33,731
1 Projected Ending Balance through September 2026 (Sum F to H) $ 4,979,318
Net Power Supply Deferral Balance
The Company calculated an NPC deferral balance of$8,227,143, as shown in Table No. 2
below. The deferral balance was calculated by subtracting all components of system actual NPC
from system NPC authorized in base rates for each month from July 2025 through June 2026. The
resulting monthly amounts were multiplied by the Idaho Allocation Factor and then multiplied by
90% to account for the Company's 90%/10% sharing mechanism. Brandon Workpapers, Tab
"Act-Auth-Proposed", Column O, Line 72. A summary of each NPC deferral component and the
total NPC deferral balance is shown in Table No. 2.
STAFF COMMENTS 3 SEPTEMBER 9, 2026

Table No. 2—PCA Deferral
Row Net Power Cost Deferral
A LCA—Idaho Sales Adjustment $ 1,210,204
B Net Power Supply—Actual Minus Authorized $ 8,676,794
C REC Revenues $ -
D Schedule 25P Net Cost $ (961,837)
E EIM Incremental O&M $ 216,105
F Total Cost (Subject to Company Sharing(Sum A to E) $ 9,141,266
G Sharing Percentage over Authorized 90%
H Total Idaho Deferral Amount (F Mult. By G) $ 8,227,143
Staff reviewed the calculation of each month's deferral balance and reviewed a sample of
invoices supporting actual NPC. Staff agrees with the Company's calculation of the total NPC
deferral balance of$8,227,143.
Load Change Adjustment—Idaho Sales Adjustment
The Idaho Load Change Adjustment ("LCA") captures the over or under-recovery of net
power supply costs through base rates attributable to the difference between actual sales and sales
used to set base rates. The Company used approved Load Change Adjustment Rate ("LCAR") of
$24.50/megawatt-hour ("MWh") for the months of July and August 2025, and an LCAR of
$23.67/MWh for the months of September 2025 through June 2026. See Appendix A of Settlement
Stipulations for Case Nos. AVU-E-23-01 and AVU-E-25-01. Staff reviewed the Company's
calculations and agrees with the Company's calculated LCA balance of$1,210,204. See Brandon
Workpapers, Tab "Act-Auth-Proposed" Column O, Line 57.
Net Power Supply—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, 2026. 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, 557—Expense Broker Fees,
and 537—MT Invasive Species Expense. Id. Column A, Lines 18 through 26.
STAFF COMMENTS 4 SEPTEMBER 9, 2026

Purchased power costs reflect the Idaho jurisdictional share of the difference between the
costs the Company incurred for power purchases during the deferral period and the authorized
power costs included in base rates. During the review period, actual NPC were higher than
authorized NPC. The Company's proposed Idaho jurisdictional share of the difference between
base-to-actual is $8,676,794. Id. Column O, Line 56.
According to the Company,the difference in actual NPC relative to NPC embedded in base
rates can be attributed to 1) downward shifts in market energy pricing; 2) wind-generation
resources excluded from the authorized base for September 2025 through August 2026; and 3)
higher customer loads during several months of the year.1 Holland Direct at 9. Staff discusses the
differences between the base and actual NPC later in these comments.
Renewable Energy Credit Revenue
The Company records Renewable Energy Credit ("REC") revenue in FERC Account No.
557. Order No. 33605 requires the Company to separately track REC revenues and expenses in
its PCA filings. The Company does not currently have REC revenue included in base rates; thus,
all REC revenue is credited to customers. The Company did not record any REC sales during the
PCA period.
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 the
associated costs to the Idaho jurisdiction. Monthly differences between the actual Clearwater
power costs and the amount of REC revenue generated are tracked through the PCA.
All of the energy generated by Clearwater is sold as energy outside of Idaho so that the
associated RECs can be sold as bundled RECs. Petition (AVU-E-18-13) at 7; Order No. 34252.
'Although Holland states higher customer loads during some months,he also states,"For the Review Period,Idaho
retail sales were 5 aMW below the authorized level."Holland Direct at 18. The effect of actual load that is lower
than authorized is an increase in the PCA.
STAFF COMMENTS 5 SEPTEMBER 9, 2026

Idaho customers are credited 10%of the bundled REC revenue less 10% of transmission wheeling
expense. Id. The Company recorded$1,142,541 of REC revenue minus$180,704 of transmission
expense during the PCA year. Staff reviewed the Company's calculation and agrees with the
resulting $961,837 credit to customers. See Brandon Workpapers, Tab "Act-Ruth-Proposed"
Column O, Line 62.
Energy Imbalance Market
In Order Nos. 35156 and 35543, the Commission authorized the Company to include
incremental Energy Imbalance Market (`BIM") expenses in the PCA up to the amount of benefits
realized from the EIM. Staff reviewed the Company's calculation and agrees with $216,105 of
incremental EIM operations and maintenance expenses for recovery through the Idaho PCA. Id.
Column O, Line 68.
Amortizations-July 2025 through June 2026
The Company amortized $8,705,512 back to customers through the PCA rebate rate
approved in Case No. AVU-E-25-07. The total amortization was calculated by multiplying the
actual kWh billed by the approved PCA rebate rate. The Company calculated the total balance by
adding the monthly balances from July 2025 through June 2026. Brandon Workpapers,Tab "Act-
Auth-Proposed", Column R, Line 84. Staff reviewed the Company's calculation and agrees with
the total amortization balance of$8,705,512 from July 2025 through June 2026.
REC Retirement Benefit
In July 2026, the Company retired $2,717,969 of RECs to meet the state of Washington's
Renewable Portfolio Standards ("RPS") and Clean Energy Transformation Act ("CETA")
requirements. Brandon Direct at 4. Absent the RPS and CETA requirements imposed by
Washington, the RECs would have been sold, with the resulting revenue providing a benefit to
Idaho customers. Id. The Company recorded an adjustment to account for the benefit Idaho
customers would have received if the RECs had been sold. Id. The credit flows through the
balancing account"Beginning Balance as of July 2026"of$2,614,220 shown in Table No. 1. Staff
reviewed the Company's calculation and agrees with the REC adjustment of$2,717,969 credited
STAFF COMMENTS 6 SEPTEMBER 9, 2026

to Idaho customers to partially offset the increase. Brandon Workpapers, Tab "Act-Auth-
Proposed", Column C, Line 82.
Interest—July 2025 Through June 2026
The Company may accrue interest on the deferral balance, which is calculated monthly.
The Company calculated interest using the Commission-approved annual customer deposit rate,
which is 5% for 2025 and 4% for 2026. Order Nos. 36390 and 36836. The Company calculated
net interest balance from July 2025 through June 2026 of negative $298,028 by summing the
monthly interest balances. Brandon Workpapers, Tab"Act-Auth-Proposed", Columns C through
N, Line 87. Staff reviewed the Company's calculation and agrees with the total net interest of
negative $298,028 from July 2025 through June 2026.
Projected Amortizations and Interest—July 2026 through September 2026
The Company included projected amortizations and interest for the months of July 2026
through September 2026 to account for the expected amount to be amortized through
surcharges/credits through the existing PCA and interest expected to accrue on the PCA balance.
Id. Columns O through Q, Lines 85 and 87. The Company calculated projected amortization of
$2,331,366 from July 2026 through September 2026 by multiplying the current PCA rate per kWh
by the forecasted kWh usage for July through September and summing the monthly amounts. Id.
Columns O through Q, Line 85. The Company calculated projected interest of$33,731 from July
2026 through September 2026 by multiplying the June 2026 ending actual deferral balance by the
applicable interest rate for July, then multiplying the projected July and August ending PCA
balances by the applicable interest rates for August and September and summing the monthly
interest balances. Id. Line 87. Staff reviewed the Company's calculations and agree with the
projected amortization of$2,331,366 and the projected interest of$33,731 for July 2026 through
September 2026.
Prudence of Net Power Cost
Staff believes that the Company's actual NPC during the PCA year (July 2025 through
June 2026) was prudently incurred based on dispatching its resources and purchasing and selling
power from and into the market in a cost-effective manner using its existing resources. Staff s
STAFF COMMENTS 7 SEPTEMBER 9, 2026

analysis was based on comparing the actual amount of power from the Company's resources and
their unit costs to amounts used to determine base rates. Because the amounts of power supplied
from each resource is optimally determined through the Company's NPC model for determining
NPC in base rates, Staff believes comparing actual results to the model results can provide an
indication of whether the Company dispatched its system prudently. In addition,because the PCA
deferral consists primarily of differences between authorized and actual NPC,the analysis can also
explain some of the main reasons for this year's surcharge. Finally, Staff verified that the
adjustments included in the Stipulation and Settlements in Case Nos. AVU-E-23-01 and AVU-E-
25-01 were properly reflected in the deferral. While performing this review, Staff is
recommending further potential adjustments be included in the Company's next general rate case.
Staff performed an analysis of data provided in the Company's Variance Analysis as
illustrated in Table No. 3 below and by analyzing the cost and load differences between the
authorized amounts of NPC embedded in base rates and actual amounts incurred during the PCA
year. July 2025—June 2026 Variance Analysis Workpapers; Company Witness Brandon
Workpapers. The major drivers for the surcharge in this year's PCA are caused by:
1. receiving approximately $8.3 million less revenue from sales into the market as
compared to those assumed in base rates;
2. dispatching its gas units 533,671 MWh less driven by higher unit gas prices than those
assumed in base rates;
3. dispatching its thermal units by 533,671 MWh less driven by higher thermal unit fuel
cost than those in base rates;
4. implementing adjustments to NPC included in general rate case Stipulation and
Settlements (Case Nos. AVU-E-23-01 and AVU-E-25-01) that effectively reduces the
total amount of NPC collected from customers but in some cases purposely increases
the amount of the surcharge; and
5. increasing the amount of the surcharge due to actual MWh sales being lower than sales
embedded in base rates through the Retail Revenue Adjustment.
STAFF COMMENTS 8 SEPTEMBER 9, 2026

Table No. 3: System-level Generation and Unit Cost for Each Resource
Resources Actual Authorized Variance Actual Authorized
Generation Generation Generation Unit Cost Unit Cost
(MWh) (MWh) (MWh) ($/MWh) ($/MWh)
Mkt. Purchases 11369,685 538,876 830,809 31.26 59.74
Mkt. Sales (4,277,832) (3,121,005) (1,156,827) 36.03 47.44
Hydro 6,086,535 5,730,491 356,044 15.11 16.12
Wind 1,095,957 532,206 563,751 42.89 48.16
Thermal 1,104,404 1,118,754 (14,350) 23.30 20.83
Natural Gas 3,925,715 4,459,386 (533,671) 31.23 29.45
Id.
The Company's actual amount of market sales was about $8.3 million (system) less than
the amount embedded in base rates, which was a major factor increasing the amount of the
surcharge.Id. Although the Company was able to sell about 1.2 million more MWhs, the average
unit price it received was about$28/MWh($47.44 minus $36.03) less than prices assumed in base
rates.Id. The cost of fuel was about$2.47/MWh($23.30 minus$20.83)higher for the Company's
thermal units and about 1.78/MWh($31.23 minus$29.45)higher for its gas units.Id. These higher
costs corresponded to lower actual amounts of generation from both types of resources. However,
the lower amounts of generation were made up by an increase in the actual amount of market
purchases, wind, and hydro, which were about $28.5/MWh ($59.74 minus $31.26), $5.27/MWh
($48.16 minus $42.89), and $1.01/MWh ($16.12 minus $15.11) less than those assumed in base
rates, respectively. Staff believes that because the Company dispatched and purchased more of its
resources with lower unit costs and dispatched less from resources with higher unit costs as
compared to the base, that the Company operated its system in a cost-effective manner.
The Stipulation and Settlements in Case Nos. AVU-E-23-01 and AVU-E-25-01 included
three different adjustment methods that reduce the total amount of NPC collected from Idaho
customers; however,two of the methods contribute to increasing the amount collected through the
PCA. Method I replaces the cost of the Power Purchase Agreement ("PPA") in base rates by
removing the PPA from the model and replacing it with an optimal mix of the Company's other
resources and then effectively comparing it to the actual cost of the PPA in the PCA. Because the
actual cost is so much higher than the cost of the replacement resources, the sharing provides a 10
STAFF COMMENTS 9 SEPTEMBER 9, 2026

% discount to customers based on the difference in costs, and the total cost collected from
customers is reduced. However, by collecting a much smaller amount through base rates, this
method increases the PCA in the surcharge direction by 90% of the total difference. Method 2
includes 90% of the cost of the PPA in both base rates and actual cost in the PCA. This method
effectively reduces the cost of the PPA by 10% to customers. Method 3 reduces NPC collected
from customers by only including the lesser of market or contract cost as actual cost in the PCA.
The amount of reduction is determined by how much of the actual cost of the PPA was adjusted
to market prices. However, 10%of this reduction is given back to the Company through customer
sharing,increasing the PCA in the surcharge direction. Each of the PPA adjustments are discussed
in more detail in the sub-sections below.
Finally, the amount of actual Idaho sales was $52,439 MWhs less than amounts assumed
in base rates. Id. This difference reduced the amount of NPC recovered through base rates by
$1.2 million requiring a true up to actual NPC cost due to lost sales as reflected in the Retail
Revenue Adjustment. Id.
Palouse Wind Adjustments
The Palouse Wind PPA was contracted by the Company in 2011 for a 30-year term.
Lafferty, Direct (Case No. AVU-E-12-08) at 12-14. In almost every general rate case since, the
intervening parties in each case have agreed to apply some form of adjustment reducing the cost
of the contract by about 10%,primarily by not including the cost in base rates and discounting the
cost of the contract through the 90%/10% sharing in the PCA. Relevant to this case, two methods
for adjusting the cost of Palouse Wind PPA were used,which Staff verified were applied correctly.
However, Staff performed additional analysis and determined that the cost of the Palouse Wind
PPA was about 150%higher than the cost of the same generation at market prices included in the
Company's variance analysis. July 2025-June 2026 Variance Analysis 7.8.26. Staff believes that
Idaho customers should not be paying these significantly higher-than-market costs and that a larger
adjustment should be applied in the next general rate case.
In Case No. AVU-E-23-01,the parties agreed to include the cost of the Palouse Wind PPA
in both base rates and actual cost in the PCA at 90 % of the cost as described as Method 2 above.
Stipulation and Settlement (Case No. AVU-E-23-01) at 13; Order No. 35909. This adjustment
applies to months July and August of 2025 in the deferral. Staff verified Company witness
STAFF COMMENTS 10 SEPTEMBER 9, 2026

Brandon's workpapers with the Company's monthly journals and believes the Company's method
is consistent with the agreement and that the calculations are accurate.
For months September 2025 through June 2026 of the deferral,the parties agreed to remove
the cost of Palouse Wind PPA from NPC in base rates and replace it with the optimized cost of the
Company's other resources decreasing system power supply expense by $1.7 million and Idaho
customer's share by$605,000, as described as Method 1, above. Settlement and Stipulation(Case
No. AVU-E-25-01) at 6-7; Order No. 36741. Staff reviewed the Company's NPC deferral
calculations included in the Company witness Brandon's workpapers and the Company's monthly
journals and verified the Company accurately adjusted the PPA costs according to the Stipulation
and Settlement.
Staff used data from the Company's variance analysis to compare the cost of the Palouse
Wind PPA to the cost of the same amount of generation during the annual deferral period priced
at market. July 2025-June 2026 Variance Analysis 7.8.26. These results, along with the same
comparison of two of the Company's more recently acquired wind PPAs are reflected in Table No
4, below.
Table No. 4: Comparison of Wind Project PPAs to Market
Wind Resource Total MWhs Total Cost based Actual Contract Difference %Difference
(HL+LL) on Market Price Cost Contract to (Total Market
Market Cost to Total
Contract Cost)
Palouse Wind 314,648 $ 8,841,723 $ 21,902,774 $ 13,061,051 147.72%
Rattlesnake Wind 403,557 $ 11,080,540 $ 12,164,603 $ 1,084,063 9.78%
Clearwater Wind 377,752 $ 10,644,652 $ 12,938,959 $ 2,294,307 21.55%
Based on Staff s analysis, the Palouse Wind PPA was approximately $13 million more
than if the same amount of energy was purchased at market. This difference is about 150%higher
when compared to market, which Staff does not believe is reasonable. The Palouse Wind PPA
was also much higher in cost compared to the cost of the Company's other wind PPAs, both of
which were more comparable to market. In addition, neither the $1.7 million adjustment nor the
traditional 10% adjustment through sharing of about $2.2 million would make up for the $13
million difference if the price of the Palouse Wind PPA was adjusted to market. Because of current
agreements through settlements authorized by the Commission, Staff does not make a
recommendation for an adjustment at this time. However, Staff recommends that the Commission
STAFF COMMENTS 11 SEPTEMBER 9, 2026

require the Company to mitigate the impact of Palouse Wind PPA on Idaho customers beyond
historical methods when it files its next general rate case.
Columbia Basin Hydro and Chelan Hydro Adjustments
Staff believes the calculation for the Columbia Basin Hydro ("CBH") and Chelan hydro
adjustment is consistent with the agreed upon method (Method 3) and is accurate. 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 the Company's previous PCA case (Case No. AVU-E-25-07) to be consistent
with the Commission Order No. 36339. Staff compared the cost in the agreed-upon mechanism
to the actual amounts in the Company's response to Staff s Production Request No. 3 Confidential
Attachment Nos. A and B and confirmed that the CBH and Chelan Hydro adjustment calculation
is consistent with the agreed-upon method. Staff also confirmed that the CBH and Chelan Hydro
adjustments included in actual NPC in the PCA are consistent with the monthly journals and
Company witness Brandon's Workpapers. Staff also verified that the removal of the CBH
transmission costs from the authorized base amount is accurate by comparing Company witness
Brandon's Workpapers with the Company's Response to Staff s Audit Request No. I I
Confidential Attachment B, and that the method is consistent with the Stipulation and Settlement
from Case No. AVU-E-23-01.
Rattlesnake Flat Wind Adjustment
According to the Stipulation and Settlement in Case No.AVU-E-23-01,the settling parties
agreed to include the cost of the Rattlesnake Wind PPA authorized base rates at 90%and compare
it with 90%of the actual costs to calculate the base-to-actual difference (Method 2). Staff verified
that the proper adjustments were made by reviewing Company witness Brandon's workpapers and
monthly journals. Staff believes the Company's method is consistent with the agreement and the
calculations are accurate.
Plant Downtime
Staff believes that excessive plant downtime can have major impacts 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
STAFF COMMENTS 12 SEPTEMBER 9, 2026

Staff s Audit Request Nos. 9 and 10. Based on its review, Staff discovered that the duration and
causes of downtime due to forced outages were reasonable when compared to downtime that
occurred during the previous deferral year. Staff also verified that the duration of scheduled
outages had sound justification and was reasonable.
Analysis of PCA Rates
PCA rate adjustments are spread on a uniform ¢per kWh basis. Based on its review of the
PCA rate calculations, Staff verified that the Company's proposed PCA surcharge was calculated
correctly and will reasonably recover the PCA balance from customers. 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 proposed PCA surcharge rate of
0.1570 per kWh, residential customers using an average of 939 kWh per month would see their
monthly bills increase from $119.52 to $123.83, an increase of$4.31 per month, or 3.6%. Table
No. 5 below provides a summary of the proposed PCA rate calculation to be effective October 1,
2026, if authorized.
Table No. 5: Summary of Proposed SurcharLye Rate
A Total Amortization and Deferral Balance including interest thru 9/30/26 $ 4,979,318
B Conversion factor(Case No. AVU-E-25-01:Per Final Stipulation& Settlement) 0.995661
C Revenue Requirement(A/B) 5,001,017
D System Forecasted Load from October 1, 2026 through September 30, 2027 (kWh) 3,193,504,000
E Proposed Rate(C/D) 1 $ 0.00157
Table No. 6 below provides the percent change by customer class to show the impact from
the proposed PCA surcharge rate. Because PCA rate adjustments are spread on a uniform ¢ per
kWh basis, the resulting percentage change in billed revenue varies by customer class.
STAFF COMMENTS 13 SEPTEMBER 9, 2026

Table No. 6: Percent Change of Billed Revenue by Schedule
Forecasted Revenue At Proposed Percent
Customer Class Present Rates
MWh Change (OOOs) Change
(OOOs)
Residential 1,357,313 $ 174,917 $ 6,216 3.6%
General Service 962,222 $ 103,092 $ 4,407 4.3%
Large General Service 95,546 $ 11,156 $ 438 3.9%
Extra Large General Service 348,913 $ 24,076 $ 1,598 6.6%
Clearwater 342,572 $ 19,825 $ 1,569 7.9%
Pumping Service 65,718 $ 8,697 $ 301 3.5%
Street & Area Lights 9,377 $ 4,271 $ 43 1.0%
Total 3,181,661 346,034 14,572 4.2%
Overall Impact of Three Filings (PCA, FCA, and ResEx)Effective October 1, 2026
The Company proposed three electric rate adjustments effective October 1, 2026. If
approved as filed, the proposed PCA, AVU-E-26-05, will increase the Company's electric
revenues by $14.6 million (4.2% increase). The Company's proposed fixed cost adjustment
("FCA") filing, AVU-E-26-06, if approved, will increase electric revenues by about $4.0 million
(1.2% increase). The final proposed filing, Bonneville Power Administration Residential
Exchange Program("ResEx"),AVU-E-26-07, if approved,will decrease electric revenues by$0.3
million(0.1% decrease). Avista Customer Notice at 1.
The net effect of Company's three filings (PCA, FCA, and ResEx) will increase electric
revenues by about $18.3 million (5.3 % increase). The average residential electric customer's
monthly bill may increase by $7.76 or 6.5 %. Id. Table No. 7 below summarizes the overall
impact to electric revenues of the three filings.
STAFF COMMENTS 14 SEPTEMBER 9, 2026

Table No. 7: Summary of Overall Impact to Electric Revenues
Filing Changes in Revenues % Change
FCA $4.0 million 1.2%
PCA $14.6 million 4.2%
ResEx Credit ($0.3 million) (0.100
Total $18.3 million 5.3%
Customer Notice and Press Release
The Company's press release and customer notice were included with its Application. Staff
reviewed the documents and believes that both met the requirements of Rule 125 of the
Commission's Rules of Procedure2, IDAPA 31. 01. 01. 125. The notice was included with billing
statements mailed to customers from August 4 through September 1,2026. For customers enrolled
in paperless billing, the notice was e-mailed during the same period and included a link to the
digital version of the notice.
The Commission set a public comment deadline of September 9, 2026. As of September
9, 2026,two customer comments had been submitted to the Commission opposing the Company's
proposal. Customers in the later part of the billing cycle may not have received their notices or
had adequate time to submit comments before the comment deadline. Staff believes customers
should have the opportunity to file comments and have those comments considered by the
Commission. Staff recommends that the Commission consider late-filed customer comments.
STAFF RECOMMENDATION
Staff recommends that the Commission approve the Company's PCA deferral balance of
$4,979,318.
2 The press release and customer notice addressed the following cases. Electric: AVU-E-26-05 Power Cost
Adjustment (PCA), AVU-E-26-06 Fixed Cost Adjustment (FCA), and AVU-E-26-07 Bonneville Power
Administration Residential Exchange (ResEx). Natural Gas: AVU-G-26-02 Fixed Cost Adjustment(FCA),AVU-
G-26-05 Energy Efficiency,and AVU-G-26-03 Purchased Gas Cost(PGA).
STAFF COMMENTS 15 SEPTEMBER 9, 2026

Staff also recommends that the Commission:
1. approve the Company's request to revise Tariff Schedule 66, Temporary Power Cost
Adjustment—Idaho, as filed,to implement a surcharge rate of 0.1570 per kWh,effective
October 1, 2026, resulting in an annual revenue increase of approximately $l 4.577
million;
2. require the Company to mitigate the impact of Palouse Wind PPA on Idaho customers
beyond historical methods in its next general rate case; and
3. consider late-filed comments from customers.
Respectfully submitted this 9th day of September 2026.
Erika K. Melanson
Deputy Attorney General
Technical Staff. James Chandler, Shubhra Deb Paul, Ray McArthur, Curtis Thaden,
Karla Ducharme, Rebecca Cottrell
I:\Utility\UMISC\COMMENTS\AVU-E-26-05 Comments.doex
STAFF COMMENTS 16 SEPTEMBER 9, 2026

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 91h DAY OF SEPTEMBER 2026,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF , IN CASE
NO. AVU-E-26-05, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
ANNI GLOGOVAC, COUNSEL FOR REGULATORY AFFAIRS
ANNETTE BRANDON, STRATEGIC INITIATIVES MANAGER
AVISTA CORPORATION
P.O. BOX 3727
1411 E. MISSION AVENUE, MSC 27
SPOKANE WA 99220
E-mail: anni.glo og vac(cavistacorp.com
annette.brandon&avistacorp.com
avi stadockets(cry avistacorp.com
PATRICIA JORDA , SECRETARY
CERTIFICATE OF SERVICE