20250131Direct C. Kalich_Exhibits.pdf

RECEIVED
Friday, January 31, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
[e-mail]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-25-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND ) DIRECT TESTIMONY
NATURAL GAS SERVICE TO ELECTRIC ) OF
AND NATURAL GAS CUSTOMERS IN THE ) CLINT G. KALICH
STATE OF IDAHO )
FOR AVISTA CORPORATION
(ELECTRIC ONLY)

1 I. INTRODUCTION
2 Q. Please state your name, the name of your employer, and your business
3 address.
4 A. My name is Clint G. Kalich. I am employed by Avista Corporation at 1411
5 East Mission Avenue, Spokane, Washington. I am an Energy Resources Planning Advisor in
6 the Energy Resources department of Avista Utilities.
7 Q. Please state your educational background and professional experience.
8 A. I graduated from Central Washington University in 1991 with a Bachelor of
9 Science Degree in Business Economics. Shortly after graduation, I accepted an analyst
10 position with Economic and Engineering Services, Inc. (now EES Consulting, Inc.), a
11 Northwest management-consulting firm located in Bellevue, Washington. While employed
12 by EES, I worked primarily for municipalities, public utility districts, and cooperatives in
13 electric utility management. My specific areas of focus were economic analyses of new
14 resource development,rate case proceedings involving the Bonneville Power Administration,
15 integrated (least-cost) resource planning, and demand-side management program
16 development.
17 In late 1995, I left Economic and Engineering Services, Inc. to join Tacoma Power in
18 Tacoma, Washington. I provided key analytical and policy support in the areas of resource
19 development, procurement, and optimization, hydroelectric operations and re-licensing,
20 unbundled power supply ratemaking, contract negotiations, and system operations. I helped
21 develop, and ultimately managed, Tacoma Power's industrial market access program serving
22 one-quarter of the Company's retail load.
23 In mid-2000 I joined Avista Utilities as a Senior Power Supply Analyst and in 2002
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Avista Corporation

I accepted the position of Manager, Resource Planning and Analysis focusing on the electric
2 side of Company business. In 2022 the Company promoted me to Senior Manager, Resource
3 Planning and Analysis, and added gas planning to my responsibilities. In 2024, 1 accepted the
4 role of Energy Resources Planning Advisor. In each of these positions I assist or assisted the
5 Company in resource analyses, dispatch modeling, resource procurement, energy policy,
6 integrated resource planning and regulatory filings.
7 Q. What is the scope of your testimony in this proceeding?
8 A. My testimony includes documentation of the rationale for key inputs and
9 assumptions driving power supply cost values including loads, natural gas and electricity
10 prices, and a comparison to current levels of authorized power supply expense. I will provide
11 an overview on contract changes since our last filing. Finally, I will identify and explain the
12 proposed pro forma adjustments to test period power supply revenues and expenses,including
13 the Retail Revenue Credit used in the Power Cost Adjustment(PCA)over the Two-Year Rate
14 Plan.
15 A table of contents for my testimony is below:
16 Description Page
17 I. Introduction 1
18 II. Dispatch Model 3
19 III. Other Key Modeling Assumptions 7
20 IV. Modeling Results 15
21 V. Overview of Pro Forma Power Supply Adjustment 16
22 VI. Pro Forma Power Supply Adjustment 18
23 VII. PCA Authorized Values 21
24
25 Q. Are you sponsoring any exhibits in this proceeding?
26 A. Yes. I am sponsoring Exhibit No. 8, Schedules 1 through 5, as shown in Table
27 No. 1 below. Confidential Schedule 1C, and Schedules 2 through 5, are contained within one
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Avista Corporation

I workbook in my workpapers, with all formulas and links intact for ease of reference.
2 Schedules 1C, 2, 4 and 5 have two exhibits each, one for each rate year. In addition to these
3 schedules, sheets after them in the workbook provide detail and supporting calculations.
4 Information contained in these exhibits were prepared by me or at my direction.
5 Table No. 1 — Confidential Exhibit No. 8 List of Schedules
Schedule Name Description
Confidential Schedule 1C RY1/RY2 Dispatch Model Results
Schedule 2 RY1/RY2 Pro Forma and Adjustment Summary
Schedule 3 Pro Forma Line Descriptions
Schedule 4 RY1/RY2 Market Purchases and Sales, Plant
Generation and Fuel Cost Summary
Schedule 5 RY1/RY2 Proposed Power Supply Base for PCA
6
7 II. DISPATCH MODEL
8 Q. Has the Company made any changes to the overall Portfolio Modeling
9 Methodology used in this case as compared to the last general rate case?
10 A. No. We are using the same methodology as our 2023 General Rate Case filing,
11 Case No. AVU-E-23-01, including using Aurora (Model) to optimize Company-owned
12 resource and contract dispatch during each hour of the pro forma year.
13 Q. What experience does the Company have using Aurora?
14 A. The Model has been at Avista since April 2002 and used for numerous studies
15 including each of our integrated resource plans and rate filings after 2002. We also use Aurora
16 for various resource evaluations, market forecasting and requests-for-proposal evaluations.
17 Q. Please briefly describe how the Model is used in this case.
18 A. The Company uses the Model with "input prices". Using input prices instead
19 of Aurora-generated prices allows the Model to optimize against prices input by Avista for
20 electricity and natural gas that reflect market conditions forecast for the rate period. Using
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Avista Corporation

I this method, prices more accurately reflect current forward prices in the wholesale
2 marketplace, the overall modeling process is simplified, and greater transparency is possible.
3 Once prices are input, the Model dispatches resources and contracts against load
4 obligations to determine net variable costs. When market electricity prices are lower than
5 operating one or more Company resources in each hour or set of hours, wholesale market
6 power purchases displace the generation. Where Avista generation capabilities exceed hourly
7 loads, and surplus resources cost less to operate than the market price of electricity, electricity
8 is sold into the market to lower power supply costs in the pro forma period. Once resources
9 are dispatched and market purchases and sales are determined for all hourly periods of the pro
10 forma period(s), costs are summarized into my Exhibit No. 8, Schedule 2. The Market
11 Purchases and Sales, Plant Generation, and Fuel Cost Summary is provided as Exhibit No. 8,
12 Schedule 4.
13 Q. What are the prices input into the Model?
14 A. Modeled operations use the one-month average of Intercontinental Exchange
15 (ICE)prices from October 1,2024,through October 31,2024,as shown in Table No.2 below.l
1 A trading month contains approximately 20 trading days.
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Avista Corporation

I Table No. 2 -Monthly Forward Prices at Key Trading Hubs
2 Mid-C Mid-C Mid-C
AECO Malin LLH HLH Flat
3 Period ($/dth) ($/dth) ($/MWh) ($/MWh) ($/MWh)
Sep-25 1.64 3.28 43.32 80.10 64.57
Oct-25 1.80 2.92 46.09 61.29 54.92
4 Nov-25 2.32 4.24 64.76 71.23 68.36
Dec-25 2.54 6.32 87.29 103.38 96.63
Jan-26 2.63 6.15 97.06 110.68 104.97
5 Feb-26 2.61 5.40 83.71 94.20 89.70
Mar-26 2.32 3.70 47.27 57.36 52.91
6 A r-26 2.07 2.70 35.41 38.41 37.14
Ma -26 2.00 2.72 25.96 29.71 28.06
Jun-26 2.00 2.87 27.04 34.72 31.47
7 Jul-26 2.00 3.43 48.48 82.10 68.00
Au -26 2.00 3.49 58.23 116.40 90.75
8 Se -26 2.00 3.44 49.91 80.66 67.68
Oct-26 2.13 3.37 66.16 76.23 72.01
Nov-26 2.61 4.71 70.93 82.26 77.22
9 Dec-26 2.81 6.19 85.93 101.82 95.15
Jan-27 2.87 6.38 89.57 102.19 96.63
10 Feb-27 2.84 5.68 79.21 87.84 84.14
Mar-27 2.50 3.91 62.02 1 66.85 64.83
Apr-27 2.01 2.99 34.21 34.44 34.34
11 Ma -27 1.89 3.00 30.62 31.76 31.26
Jun-27 1.98 3.13 27.75 32.80 30.67
12 Jul-27 2.06 3.31 63.00 93.37 80.64
Au -27 2.12 3.37 72.91 134.68 107.44
RY1 Average 2.16 3.94 55.39 73.30 65.62
13 RY2 Average 2.32 4.12 61.02 77.08 70.17
14 Modeled market prices are shaped hourly for electricity and daily for natural gas based on test
15 year actuals. For example, if the Mid-Columbia (Mid-C) electricity price in the first hour of
16 the test year is ninety percent of the average of all hourly prices in the first month of the test
17 year, then the price input in the Model for that hour is equal to ninety percent of the forward
18 price for the matching calendar month. Similar math is performed for natural gas,but because
19 the market for natural gas is traded in daily blocks the shape is daily using the daily gas price
20 test year shapes. Backup for the price calculations is included in my workpapers.2
21 Q. How does the Company model hydro in this case?
22 A. A single year of median monthly values is extracted from the most recent 30
2 See Kalich workpaper"NaturalGas_Elec_Prices.xlsx".
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Avista Corporation

I years by combining 1994-2018 from the 90-year water record and actual generation from
2 2019-2023. This is consistent with climate modeling in Avista's and other Northwest utilities'
3 IRPs and is more closely aligned with expected climate conditions. Data for our hydro
4 facilities and Mid-C hydro contracts are presented in workpapers.3
5 Q. How does the Model operate Company-controlled hydroelectric
6 generation resources?
7 A. To reflect the flexibility of hydroelectric resources,Avista develops individual
8 operations logic for each river system based on the most recent five years of historical
9 experience. This separation by river system ensures the flexibility inherent in these resources
10 is credited to customers in the pro forma exercise.
11 Q. Please compare operating statistics from the Model to recent historical
12 hydro plant operations.
13 A. Over the pro forma period the Model generates 66.5%of Clark Fork generation
14 during on-peak hours, approximating the five-year average of on-peak generation. Since on-
15 peak hours represent only 57% of the year, this demonstrates a substantial shift to the more
16 valuable on-peak hours. Avista ensures this historical shaping for each river system is
17 reflected in each month. A summary of our three river systems is shown below in Table No.
18 3. Data supporting these calculations is in my workpapers.
19 Table No. 3—Comparison of Historical and Pro Forma On-Peak Hydro Generation
20 River System History Modeled
Clark Fork River 67.0% 66.5%
21 Spokane River 59.3% 59.4%
Mid-Columbia 58.4% 58.8%
22
s See Kalich workpaper"Hydro History.xlsx"and"30-year(1994-2023)Carl Fork Hydro".
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Avista Corporation

I Q. How are reserves modeled?
2 A. Due to software limitations, Avista cannot implicitly represent reserves in the
3 Model. Instead, we reflect reserve obligations in two ways in the Model. We shape hydro
4 generation to match five years of historical operations to reflect how hydro plants contribute
5 to reserves. We also limit the dispatch of our Northeast and Rathdrum gas plants,just as we
6 do in actual operations to meet reserve obligations. I discuss the impacts of placing reserves
7 on our thermal fleet later in testimony.
8 Q. How are firm natural gas transportation contracts valued in
9 circumstances when they are not needed for fueling generation facilities?
10 A. When natural gas plants consume less fuel in a day than our transportation
11 rights permit,we reduce pro forma power supply costs in the period by the value of any surplus
12 transportation. The surplus value equals the difference in natural gas prices between the
13 AECO and Malin hubs, as AECO gas is typically less expensive than Malin gas.
14
15 III. OTHER KEY MODELING ASSUMPTIONS
16 Q. Are other key modeling assumptions being made by the Company?
17 A. Yes. We make several additional assumptions affecting loads, as well as
18 forced and planned maintenance that drive our modeled pro forma costs.
19 Q. What is the Company's assumption for rate period loads?
20 A. Consistent with prior GRC proceedings, historical loads are weather adjusted.
21 In this filing,test year loads ending June 30,2024,average 1,047.7 megawatts. This compares
22 to weather normalized pro forma loads of 1,056.1 average megawatts. Table No. 4 below
23 details data included in this proceeding. Please see Company witness Mr. Garbarino's direct
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Avista Corporation

I testimony for additional information on the weather normalization.
2 Table No. 4 —Pro Forma Weather Normalized Loads
Weather
3 Test Year Adjustment Modeled
Month Load(MW) (MW) Load(MW)
4 Sep-25 1,272.3 -18.5 1,253.8
Oct-25 1,184.5 34.2 1,218.7
5 Nov-25 1,048.3 17.5 1,065.8
Dec-25 945.6 18.7 964.3
6 Jan-26 907.2 6.2 913.4
Feb-26 895.9 5.8 901.7
7 Mar-261 1,115.0 -27.7 1,087.3
Apr-26 1,083.0 -23.5 1,059.4
8 May-26 915.0 2.7 917.7
Jun-26 937.2 19.4 956.6
9 Jul-26 1,116.7 3.1 1,119.8
Aug-26 1,155.0 64.5 1,219.5
10 1 Average 1 1,047.71 8.31 1,056.1
11 Q. What are the assumed forced outage and planned maintenance rates for
12 the Company's thermal generation?
13 A. As in previous cases, except for Colstrip, a five-year average (through 2023)
14 is used to represent forced and planned outage rates at each plant. Eight years is used for
15 Colstrip, reflecting two, four-year, maintenance cycles at the plant. A single maintenance
16 cycle for Colstrip is too short, and multiple cycles cannot be represented within the 5-year
17 period used for other plants. Table No. 5 below details forced and maintenance outage rates,
18 comparing them to what currently exists in rates.
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Avista Corporation

I Table No. 5 -Forced Outage and Maintenance Rates, Pro Forma 2025 and 2023 GRCs
2
Forced Outage Rate Maintenance Rate
Facility 2025 2023 Difference 2025 2023 Difference
Boulder Park 11.4% 11.4% 0.0% 4.6% 4.7% -0.1%
Coyote Springs 2 5.0% 5.0% 0.0% 17.2% 16.5% 0.7%
Kettle Falls 4.0% 3.7% 0.3% 13.5% 14.0% -0.5%
Kettle Falls CT 1.8% 6.2% -4.4% 1.1% 1.8% -0.7%
Lancaster 2.0% 1.4% 0.6% 5.0% 5.3% -0.3%
Northeast n/a n/a n/a n/a n/a n/a
Rathdrum 1.9% 1.9% 0.0% 5.4% 4.8% 0.6%
3
4 Q. Are the Rathdrum and Northeast natural gas-fired plants modeled
5 differently in this case than in the past?
6 A. No. Rathdrum and Northeast natural gas-fired plants provide most of Avista's
7 contingency reserves and contributed to other operating reserves. Both are high heat rate
8 facilities, meaning they are not expected to run a lot over a year and their operating margins are
9 relatively low even when operating. Northeast, even if cost-effective to run relative to market
10 prices, is limited to 100 hours per year due to Spokane Regional Clean Air Agency regulation.
11 As such,Northeast is assumed to be set aside exclusively for emergency and is available to meet
12 operating reserve requirements in all hours. This approach is consistent with our last general rate
13 case. Northeast, on a stand-alone basis, is not large enough to meet our contingency and
14 operating reserve requirements in April through July when the hydro system generally has
15 limited capacity to supplement the plant. As such,one Rathdrum unit is typically set aside during
16 this period, even when market conditions show it to be lower cost than buying power from the
17 market.
18 Q. What are the contingency and other reserve requirements Avista must retain
19 that removes these resources from dispatching when market prices would otherwise allow
20 an opportunity to generate additional value for customers?
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Avista Corporation

I A. We must carry three percent each of online generation and load as contingency
2 reserves as Avista's obligation under in the Western Power Pool Reserves Sharing Agreement
3 (WPP Reserves Sharing Agreement). Our modeled pro forma generation of approximately 1,250
4 average megawatts(aMW), and average pro forma load of 1,056 MW necessitate approximately
5 70 aMW of contingency reserves.
6 The level of reserves beyond the obligations of the WPP Reserves Sharing Agreement
7 are not defined by agreement. Yet standard industry(and prudent)practice dictates that utilities
8 should prepare for losing their largest single online generator—both with capacity and fuel. For
9 Avista at any given point in time our largest online generator could be a 75 to 150 MW hydro
10 unit at our Clark Fork Project. Or it could be one of our large natural gas plants like Coyote
11 Springs 2, generating more than 300 MW. The combination of Northeast, and a single unit at
12 Rathdrum,approximate the lower end of this range. Over the two-year pro forma period,average
13 contingency reserve levels equate to 314 MW.4 We generally supplement Northeast and
14 Rathdrum with hydro unit capability ensuring adequate reserves are held in operations.
15 Q. Please describe any material change to thermal resources during this rate
16 period.
17 A. As discussed in Company witness Mr. Kinney's testimony, Avista will transfer
18 ownership of its 15% shares of Units 3 and 4 of Colstrip to NorthWestern Energy at the end of
19 2025. Therefore, only 4 months of the benefits and expense of Colstrip are included in the RY1
20 (RY1) pro forma, and no benefits or expenses are included in the RY2 (RY2) pro forma.
21 Company witness Ms. Andrews also discusses the removal of Colstrip within her testimony over
22 the Two Year Rate Plan.
a See Workpaper Confidential Contingency and Single Largest Unit Summary.
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Avista Corporation

I Q. NPE for both pro forma years rises significantly as compared with the test
2 year. What is the major driver of this rise, and are any offsets to it included in the case?
3 A. The roughly $90 million (system) increase in RY1 as compared with the RY1
4 from the 2023 GRC reflects the removal of Colstrip from our portfolio. See Table No. 6 below
5 for this calculation based on the mark-to-market estimated results of this case and the cost of fuel
6 as compared with the last cases
7 Table No. 6—RY1 Increase to NPE Compared with RY1 from the 2023 GRC
8 RYI (2023 ID GRC) RY1 (2025 GRC) RY2 (2025 GRC)
MTM Value of Power 139,880 24,806 -
9 Fuel Expense (31,951) (6,608) -
10 Increase to NPS 107,929 18,198 -
Difference between GRCs 89,731 107,929
11
12 Q. Please describe any material changes to power contracts since the 2023
13 filing and the impact on power costs.
14 A. Avista updates all contracts over the pro forma term to account for expiring
15 and new contracts. Table No. 7 below lists all the long-term contracts with material changes
16 in RY1.6
5 Offsetting this increase are lower depreciation and fixed operations and maintenance costs due to the removal
Colstrip operating costs January 1,2026,as discussed by Ms.Andrews.
6 Please note this table is intended to illustrate changes to long-term contracts. As such,the table will not tie to
the total for 555 Purchase Power in Adjustment 3.00 Power Supply Adjustment.
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Avista Corporation

I Table No. 7-Wholesale Contract Changes
2025 GRC 2023 GRC
Contracts aMW aMW Change
Chelan PUD 149.7 92.9 56.8
Douglas PUD 5.6 14.3 -8.7
Grant PUD 36.7 38.1 -1.4
Columbia Basin 47.5 2.4 45.1
Douglas Exchange Purchase 0 11.0 -11.0
Canadian Exchange -3.6 -8.0 4.5
Nichols Pumping -2.1 -5.2 3.1
Palouse Wind 37.5 0 37.5
Rattlesnake Wind 43.4 0 43.4
Clearwater Wind 41.9 0 41.9
Douglas Exchange 0 -15.7 15.7
Other 24.7 26.1 -1.4
Total Contracts 381.3 155.8 225.5
2
3 Our most recent Chelan County Public Utilities District contract meets a portion of
4 our resource needs identified in Avista's 2020 Integrated Resource Plan. Already described
5 in the 2023 GRC,the contract provides a further 5% slice of Chelan's Rocky Reach and Rock
6 Island hydro projects starting January 1, 2026.
7 Our contract with Grant County Public Utilities District for an approximate three
8 percent share of its Priest Rapids project has not materially changed from the previous rate
9 case,but its cost is measurably higher based on an auction process generally reflecting current
10 market prices,which have increased significantly in recent years. The 2024 monthly contract
I I amounts were used to estimate pro forma period deliveries.7
12 Avista contracts with Douglas for approximately 1% of its Wells Dam output. This
13 contract includes a fixed-price capacity charge, as well as an agreed-upon energy charge,both
14 changing annually. A separate capacity exchange contract with Douglas County PUD has
15 expired and is not reflected in the pro forma.
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Avista Corporation

I Columbia Basin Hydro Power provides hydro capacity and energy for Avista as a
2 product of irrigation operations and meets Avista's increasing summer load requirements.
3 This contract is not new, but additional projects come online during the pro forma period
4 (bolded below).
5
6 • March 1, 2023 for the Russell D. Smith (P.E.0 22.7) Development—6.1MW
7 • May 1, 2023, for the E.B.C. 4.6 Development—2.2 MW
8 • January 1, 2025, for the Summer Falls Development—92 MW
9 • March 1, 2025, for the P.E.C. 66.0 Development—2.4 MW
10 • October 1, 2025, for the Quincy Chute Development—9.4 MW
11 • January 1, 2027, for the Main Canal Development—26 MW
12 • September 1, 2030, for the P.E.C. Headworks Development—6 MW
13
14 There is no material change in the Lancaster contract during the pro forma period. Its
15 increase from the 2023 case is a function of annual price appreciation agreed to in the original
16 contract expiring in October 2026, and a new contract executed at the conclusion of Avista's
17 2022 Request for Proposal (RFP).
18 Nichols Pumping is related to Colstrip and the contract expires end of 2025.
19 Therefore, only 4 months of this contract is included in the RY1 pro forma, and there is
20 nothing related to this contract included in the RY2 pro forma.
21 Avista has three wind projects — Palouse, Rattlesnake and Clearwater Wind III.
22 Palouse Wind is a 105 MW project. Avista signed a 30-year power purchase agreement in
23 2011 for the entire output starting in December 2012. Rattlesnake Wind is a 160.5 MW
24 project limited to 144 MW due to its interconnection agreement. Avista signed a 20-year
25 power purchase agreement and this project began operations in December 2020.Avista signed
26 a 20-year power purchase agreement and this project began production in September 2024.
27 All three of these wind projects are included in the pro forma. More information regarding
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Avista Corporation

I these wind projects is included below.
2 The Douglas Exchange expired at the end of 2023 and therefore is not included in
3 either rate year pro formas.
4 Q. What contracts are included in the "Other" line item in Table No. 7
5 above?
6 A. The Other category in Table No. 7 is comprised of several small PURPA
7 contracts, as well as three larger PURPA contracts.
8 Q. Are there contracts not included in the Model?
9 A. Yes. The mark-to-market value of all forward natural gas and power positions
10 with contract durations falling within the pro forma period are included; however, because
11 these are financial hedges, they are not modeled within Aurora. More detail on the modeling
12 of financial hedges is discussed later in my testimony, and in the testimony of Mr. Kinney.
13 Q. How is the Adams-Neilson Solar project treated in this filing?
14 A. Through December 31,2026,the facility serves Washington State Solar Select
15 program customers. In the Aurora Model we show the Adams-Neilson resource, and an
16 offsetting sale at its contract price through 2026, thereby nettingits is impact on power supply
17 expense to zero during this period. Beginning January 1, 2027, Adams-Neilson enters the
18 portfolio to serve all customers.
19 Q. Does the pro forma include the Company's wind facilities?
20 A. Yes. The 2023 GRC did not model any wind or solar project costs or benefits.
21 This case includes output and costs for all Avista wind and solar projects, including our
22 newest, Clearwater Wind III. Clearwater Wind III was acquired as part of Avista's 2022 all-
23 source RFP and began operations in September 2024. These contracts provide favorable
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Avista Corporation

I outcomes for Idaho customers, with an estimated total benefit of$50.6 million (system) over
2 the two-year pro forma period, as shown in Table No. 8 below. In other words, pro forma
3 power supply expense would be more than$50 million higher absent including these resources
4 in base rates.
5 Table No. 8—Pro Forma Value of Wind and Solar Fleet
6
Resource $000s GWh $/MWh
7 Palouse Wind 46,485 660 70.48
Rattlesnake Wind 27,136 762 35.60
8 Clearwater Wind 22,942 734 31.25
Lind Solar 1,538 34 45.58
9 Total 98,101 2,190 44.80
Market Price of Power 67.93
10 MTM Value of Resources 23.12
11 MTM Value of Resources ($000s) 50,625
12 Q. Is the Company modeling the California EIM in pro forma power
13 expenses?
14 A. No. The Commission approved PCA tracking of EIM expenses and benefits in
15 the 2021 GRC. Avista is not proposing a change here.
16
17 IV. MODELING RESULTS
18 Q. Please summarize results from the power supply modeling.
19 A. The Model tracks our portfolio during each hour of the pro forma study. Many
20 results are shared earlier in my testimony. Overall fuel costs and generation for each resource
21 are calculated and summarized in Exhibit No. 8, Confidential Schedule 1 and Schedule 2.
22 Market sales and purchases, and their revenues and costs, are determined as well and shown
23 in Table No. 9 below, on a system basis:
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Avista Corporation

I Table No. 9— System Balancing Purchases & Sales
2 Item RY1 RY2 2023 GRC RYl Delta RY2 Delta
aMW aMW aMW aMW aMW
3 Market Purchases 14.2 17.9 11.3 2.9 6.6
Market Sales (372.9) (356.6) (285.0) (87.9) (71.6)
4 Net (358.7) (338.7) (273.7) (85.0) (65.0)
5 ($000) ($000) ($000) ($000) ($000)
Market Purchases 13,481 14,174 4,781 8,700 9,393
6 Market Sales (175,397) (177,258) (206,685) 31,288 29,427
Net I (161,917) (163,084) (201,904)1 39,987 1 38,820
7
8 Market transactions, combined with other resource and contract revenues and expenses not
9 accounted for directly in the Model (e.g., fixed costs), determine the net power supply
10 expense.
11
12 V. OVERVIEW OF PRO FORMA POWER SUPPLY ADJUSTMENT
13 Q. Please provide an overview of the pro forma power supply adjustment.
14 A. The pro forma power supply adjustment determines revenues and expenses
15 associated with dispatch of Company resources and contract rights, as determined by the
16 Model's simulation for the pro forma rate period under normal weather and median hydro
17 generation conditions. Further adjustments are made to reflect contract changes between the
18 historical test period and the pro forma period. Table No. 10 below shows total net power
19 supply expense during the test period and the pro forma period. For information purposes
20 only, the power supply expense currently in base retail rates,based on a test year ending June
21 30, 2024, versus the pro forma period, is shown.$
22
s For the remainder of my testimony,for purposes of the power supply adjustment I will refer to the net of power
supply revenues and expenses as power supply expense for ease of reference.
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Avista Corporation

I Table No. 10—Rate Year 1 Net Power Supply Expense (System and Idaho-Share)
2 RY 1 Idaho
Measure Systemf') Allocation(2)
3
($000s) ($000s)
4 Current Authorized Power Supply Expense effective 9/l/23 $ 177,585 $ 61,214
5 Actual 12ME 6/30/24 Test Period Power Supply Expense $ 170,474 $ 60,135
6 Proposed 2025-2026 Pro Forma Power Supply Expense $ 206,857 $ 73,476
Proposed 2025-2026 Expense versus 12ME 6/30/24 Test Period $ 36,383 $ 13,341
7 Proposed 2025-2026 Expense Change from Current Authorized $ 29,272 $ 12,262
8 (1)Excludes Transmission-see Company witness Mr.Dillon and Adjustment 3.00T.
(2)Allocated based on ROO Current Production/Transmission Ratio of 35.52%
9 (3)Adjusted for current weather normalized loads.
10 The net effect of adjustments to the test year power supply expense is an increase in
11 2025-2026 of$36.383 million on a system basis, an increase of$13.341 million for Idaho in
12 RY1.9 This value is provided to Company witness Ms. Schultz for her testimony. Overall,
13 however, the increase in net power supply expense, as compared to what is authorized in
14 current base rates, is $29.272 million, or $12.262 million Idaho share in RY L
15 Net power supply expense in RY2 rises by a further$26.771 million, or$9.509 million
16 Idaho share, as shown in Table No. 11 below:
17 Table No. 11 —Rate Year 2 Net Power Supply Expense (System and Idaho-Share)
18
RY 2 Idaho
Measure SystenO Allocation
19 ($000s) ($000s)
Proposed 2026-2027 Pro Forma Power Supply Expense $ 233,628 $ 82,985
20 Less:Proposed 2025-2026 Pro Forma Power Supply Expense $ 206,857 $ 73,476
Net Increase in Net Power Supply Expense $ 26,771 $ 9,509
21 (1)Excludes Transmission-see Company Witness Mr.Dillon and adjustment 3.00T.
22 (2)Allocated based on ROO Current Production/Transmission Ratio of 35.52%
(3)Adjusted for current weather normalized loads.
9 Assumes current Production/Transmission(P/T)ratio of 64.48%/35.52%for Washington/Idaho.
Kalich, Di 17
Avista Corporation

I VI. PRO FORMA POWER SUPPLY ADJUSTMENT
2 Q. Please identify specific power supply cost items not already covered in
3 your testimony and the total adjustments being proposed.
4 A. Exhibit No. 8, Schedule 2 identifies non-Model power supply expense and
5 revenue items for power purchases and sales, fuel expenses,transmission expenses, and other
6 miscellaneous power supply expenses and revenues.
7 Q. What is the basis for the adjustments to the test period power supply
8 revenues and expenses?
9 A. The purpose of test period adjustments is normalization of power supply
10 expenses for expected (i.e., average) weather and median hydroelectricity generation, to
11 reflect current forward natural gas and electric prices, and include other known and
12 measurable changes for the pro forma period.
13 Q. Please describe each adjustment.
14 A. Exhibit No. 8, Schedule 3 provides a brief description of each adjustment line
15 item of the pro forma. Detailed work papers demonstrate actual and pro forma revenues and
16 expenses.
17 Q. How are long-term power contracts included in the pro forma?
18 A. The Model tabulates the value of all long-term physical power contracts as part
19 of its algorithms.
20 Q. How are term transactions accounted for in the pro forma?
21 A. The Company's Energy Resource Risk Policy, sponsored by Mr. Kinney
22 within Exhibit No. 6, Schedule 2C, allows the Company to enter term transactions lessening
23 power supply expense volatility. Our Risk Management Policy enables term transactions out
Kalich, Di 18
Avista Corporation

I as far as three years. The Company takes power and natural gas positions into the future,
2 using both physical and financial arrangements, in the forward markets; many of these
3 transactions can fall within the pro forma period.
4 Where some or all physical or financial contract terms exist within the pro forma
5 period, such costs are included in the Model.10 Financial contracts only affect power supply
6 expenses based on the difference between their price and the market value of power. Physical
7 contracts also account for expected energy deliveries by increasing (for sales) or decreasing
8 (for purchases) our net load obligations.
9 The Model in its current instance cannot value natural gas contracts. They are instead
10 valued outside of the model at their delivery basin. The valuation uses the same natural gas
11 price as used in the Model. The pro forma value of our natural gas purchases may be found
12 in my work papers.l 1
13 Q. How are thermal fuel expenses for non-natural gas resources determined
14 in the pro forma?
15 A. Non-gas fuel is procured for Colstrip (coal)through end of 2025 and the Kettle
16 Falls Generating Station (wood waste). In its fuel supply contract, the coal price for Colstrip
17 is dependent on the volume purchased each year. Pro forma period consumption levels are
18 used to define the contract fuel price; the calculation is provided in workpapers.12 After the
19 Model dispatches the plant, our coal supply contract prices are applied to that dispatch.
20 Hog fuel (i.e.,waste wood) fuel prices at the Kettle Falls Generating Station are based
21 on contracts we have with fuel suppliers supporting our existing inventory. Expected Model
10 Financial contracts include only costs in the Model. Physical contracts include both costs and delivered energy.
ii See Kalich electronic workpapers,tab`Conf Fuel Costs'of spreadsheet"Exhibit No.8-Schedules 1C-5.xlsx."
iz See worksheet"Conf Colstrip Fuel Model"in the spreadsheet version of my Exhibit No. 8.
Kalich, Di 19
Avista Corporation

I dispatch is priced using budgeted prices from our fuel supply contracts. Fuel cost calculations
2 for the Kettle Falls Generation Station are in my workpapers.13
3 Q. What changes in transmission expenses are in the pro forma compared to
4 the test-year and the expense in current base rates?
5 A. Firm transmission contracts are required to deliver power from generation to
6 loads and markets, deliver power from markets to load, meet resource adequacy requirements
7 and ensure reliability requirements for the electric system. In addition to Company-owned
8 point to point or network transmission, the Company has long-term transmission contracts
9 and network transmission rights primarily with Bonneville Power Administration. Bonneville
10 Power Administration transmission costs included in the pro forma include transmission rates
11 filed within its BP-26 general rate case. The Company has updated the transmission pro forma
12 expense to reflect additional transmission for Columbia Basin Hydro and Clearwater Wind
13 contracts. Finally, Network Transmission expense (also called "borderline wheeling") is
14 based on a five-year use average priced at current rates.
15 Q. Please explain how natural gas transportation contracts are included in
16 the pro forma.
17 A. The value of our firm natural gas transportation contracts from AECO to our
18 power plants are discussed earlier in my testimony. Contracted costs for the two-year rate
19 period are included in the pro forma.
20 Q. Please summarize your proposed pro forma power supply expense that is
21 provided to Ms. Schultz for the Company's electric Pro Forma Study.
22 A. The net effect of my adjustments to the test year power supply expense is an
is See worksheet see"Kettle and Colstrip Fuel 2019-2023.xlsx".
Kalich, Di 20
Avista Corporation

I increase in 2025-26 of$36.383 million ($206.857 million - $170.474 million) on a system
2 basis, and a $13.341 million Idaho allocation. Overall, however, the increase in net system
3 power supply expense in 2025-26, as compared to what is authorized in current base rates, is
4 $29.272 million. The increase in net power supply expense in 2025-26 for Idaho share is
5 $12.262 million. For Rate Year 2, net power supply expense increases further by $26.771
6 million ($206.857 million to $233.628 million) on a system basis, and $9.509 million Idaho
7 allocation.
8 VII. PCA AUTHORIZED VALUES
9 Q. What is Avista's proposed authorized power supply expense and revenue
10 for the PCA?
11 A. The proposed authorized level of annual system net power supply expense and
12 revenues is $169.375 million for the pro forma. This is the sum of FERC Accounts 555
13 (Purchased Power),557(Other Expenses),501 (Thermal Fuel),547(Fuel), 565 (Transmission
14 of Electricity by Others, 537 (Montana Invasive Species), less Account 447 (Sale for Resale)
15 and 456 (Other Electric Revenue). It also includes transmission revenue discussed by
16 Company witness Mr. Dillon.
17 Q. What is the level of retail sales and the proposed Load Change Adjustment
18 Rate for the PCA over the Two-Year Rate Plan?
19 A. The proposed authorized level of retail sales to be used in the PCA is year
20 ending June 30, 2024, weather-adjusted Idaho retail sales. The proposed Load Change
21 Adjustment Rate, which is the energy related portion of the average production and
22 transmission cost, is $25.48/MWh for RY1, pro forma period September 1, 2025-August 31,
23 2026. For RY2,the proposed Load Change Adjustment Rate is $27.12/MWh,which includes
Kalich, Di 21
Avista Corporation

I the impact of production and transmission costs for RY2 as pro formed by Ms. Schultz.
2 The proposed authorized PCA power supply expense and revenue, transmission
3 expense and revenue, REC revenues, Load Change Adjustment Rate and retail sales over the
4 Two-Year Rate Plan are shown in Exhibit No. 8, Schedule 5.
5 Q. Does this conclude your pre-filed direct testimony?
6 A. Yes, it does.
Kalich, Di 22
Avista Corporation

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
DAVID.MEYER@AVIS TACORP.COM
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-25-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND ) EXHIBIT NO. 8
NATURAL GAS SERVICE TO ELECTRIC ) OF
AND NATURAL GAS CUSTOMERS IN THE ) CLINT G. KALICH
STATE OF IDAHO )
FOR AVISTA CORPORATION
(ELECTRIC ONLY)

CONFIDENTIAL subject to Attorney's Certificate of Confidentiality
Dispatch Model Results
Pages 1 of 8
Exhibit No. 8
Case No. AVU-E-25-01
C. Kalich, Avista
Schedule 1, Page 1 of 1

Avista Corp.
Power Supply Pro Forma - Idaho Jurisdiction
System Numbers - 12ME June 2024 Actual vs. 09/25 - 08/26 Pro Forma RY1
Test Year Load
($000)
Line 12 Mo-Ending 9/1/25-8/31/26
No. 6/30/2024 Adjustment Pro Forma
1 555 PURCHASED POWER
2 Short-Term Market 96,589 -83,108 13,481
3 Chelan PUD 26,311 29,230 55,541
4 Douglas PUD 2,584 -897 1,687
5 Grant PUD 34,102 -2,245 31,857
6 Columbia Basin Hydro 946 17,003 17,949
7 Lancaster PPA 29,934 1,207 31,141
8 Small Power 1,267 1,030 2,297
9 Spokane-Upriver 2,491 1,573 4,064
10 Spokane Waste-to-Energy 6,176 -249 5,927
11 Palouse Wind 20,500 2,448 22,948
12 Clearwater Wind 0 12,984 12,984
13 Rattlesnake Flat Wind 11,368 71 11,439
14 Adams-Neilson Solar 0 0 0
15 Clearwater(Idaho only) 2,390 -2,390 0
16 WPM Ancillary Services(reconciling item) 1,161 -1,161 0
17 Non-Mon.Accruals(reconciling item) 11 -11 0
18 Total Account 555 235,830 -24,517 211,313
19
20 557 OTHER EXPENSES
21 Miscellaneous Transaction Fees 873 85 958
22 Other Resource Costs 3,009 -3,009 0
23 Natural Gas Fuel Purchases 26,048 -26,048 0
24 Total Account 557 29,930 -28,972 958
25
26 501 THERMAL FUEL EXPENSE
27 Kettle Falls-Wood Fuel 10,562 -1,458 9,104
28 Colstrip-Fuel Cost 30,571 -23,963 6,608
29 Total Account 501 41,133 -25,421 15,712
30
31 547 OTHER FUEL EXPENSE
32 Coyote Springs 2 Combined Cycle Combustion Turbine 53,295 -28,179 25,116
33 Lancaster Combined Cycle Combustion Turbine 40,532 -4,671 35,861
34 TC Energy Pipeline 0 11,873 11,873
35 Williams Northwest Pipeline 0 327 327
36 Rathdrum Combustion Turbine 35,307 -8,275 27,032
37 Northeast Combustion Turbine 15 -15 0
38 Boulder Park Engines 2,426 1,063 3,489
39 Kettle Falls Combustion Turbine 1,581 -486 1,095
40 Total Account 547 133,156 -28,365 104,791
41
42 565 TRANSMISSION OF ELECTRICITY BY OTHERS
43 Short-term Purchases 602 -602 0
44 BPA Point-to-Point/NT 14,511 3,786 18,297
45 BPA Townsend to Garrison 1,447 -25 1,422
46 Columbia Basin Hydro 0 3,365 3,365
47 Avista on BPA Borderline/Network 1,742 207 1,949
48 Kootenai for Worley 56 1 57
49 Sagle for Northern Lights 146 -12 134
50 Northwestern 540 5,714 6,254
51 Portland General Electric John Day to COB -98 1,543 1,445
52 Total Account 565 18,946 13,976 32,922
53
54 407 Regulatory Debits(reconciling item)
55 Total Account 407.434 Incremental EIM O&M 380 -380 0
56
57 537 MT Invasive Species
58 Total Account 537 777 3 780
59
60 ITOTAL EXPENSE 460,152 -93,674 366,477
Exhibit No.8
Case No.AVU-E-25-01
C. Kalich,Avista
Schedule 2, Page 1 of 4

Avista Corp.
Power Supply Pro Forma - Idaho Jurisdiction
System Numbers - 12ME June 2024 Actual vs. 09/25 - 08/26 Pro Forma RY1
Test Year Load
($000)
Line 12 Mo-Ending 9/1/25-8/31/26
No. 6/30/2024 Adjustment Pro Forma
61
62 447 SALES FOR RESALE
63 Short-Term Market 224,185 -48,788 175,397
64 Nichols Pumping 3,208 -2,132 1,076
65 Sovereign/Kaiser Services 151 -10 141
66 Pend Oreille PUD 498 -25 473
67 Merchant Ancillary Services(reconciling item) 37,818 -37,818 0
68 Total Account 447 265,860 -88,773 177,087
69
70 456 OTHER ELECTRIC REVENUE
71 Non-WA EIA REC(reconciling item-Idaho only) 7,106 -7,106 0
72 Natural Gas Liquids 403 -8 395
73 Surplus AECO to Malin Transportation 16,309 -34,171 -17,862
74 Total Account 456 23,818 -41,285 -17,467
75
76 TOTAL REVENUE 289,678 -130,058 159,620
77
78 TOTAL NET EXPENSE 170,474 36,383 206,857
Exhibit No.8
Case No.AVU-E-25-01
C. Kalich,Avista
Schedule 2, Page 2 of 4

Avista Corp.
Power Supply Pro Forma - Idaho Jurisdiction
System Numbers - 9/25 - 8/26 Pro Forma vs. 09/26 - 08/27 Pro Forma RY2
Test Year Load
($000)
Line 9/1/25-8/31/26 9/1/26-8/31/27
No. Pro Forma Adjustment Pro Forma
1 555 PURCHASED POWER
2 Short-Term Market 13,481 694 14,174
3 Chelan PUD 55,541 8,199 63,740
4 Douglas PUD 1,687 20 1,707
5 Grant PUD 31,857 1,274 33,131
6 Columbia Basin Hydro 17,949 3,669 21,618
7 Lancaster PPA 31,141 306 31,447
8 Small Power 2,297 -284 2,012
9 Spokane-Upriver 4,064 81 4,145
10 Spokane Waste-to-Energy 5,927 39 5,965
11 Palouse Wind 22,948 590 23,537
12 Clearwater Wind 12,984 1,168 14,152
13 Rattlesnake Flats Wind 11,439 63 11,503
14 Adams-Neilson Solar 0 0 1,538
15 Clearwater(Idaho only) 0 0 0
16 WPM Ancillary Services(reconciling item) 0 0 0
17 Non-Mon.Accruals(reconciling item) 0 0 0
18 Total Account 555 211,313 17,357 228,670
19
20 557 OTHER EXPENSES
21 Miscellaneous Transaction Fees 958 0 958
22 Other Resource Costs 0 0 0
23 Natural Gas Fuel Purchases 0 0 0
24 Total Account 557 958 0 958
25
26 501 THERMAL FUEL EXPENSE
27 Kettle Falls-Wood Fuel 9,104 91 9,195
28 Colstrip-Fuel Cost 6,608 -6,608 0
29 Total Account 501 15,712 -6,517 9,195
30
31 547 OTHER FUEL EXPENSE
32 Coyote Springs 2 Combined Cycle Combustion Turbine 25,116 6,386 31,501
33 Lancaster Combined Cycle Combustion Turbine 35,861 3,386 39,247
34 TC Energy Pipeline 11,873 31 11,904
35 Williams Northwest Pipeline 327 15 342
36 Rathdrum Combustion Turbine 27,032 4,424 31,456
37 Northeast Combustion Turbine 0 0 0
38 Boulder Park Engines 3,489 413 3,901
39 Kettle Falls Combustion Turbine 1,095 257 1,352
40 Total Account 547 104,791 14,912 119,703
41
42 565 TRANSMISSION OF ELECTRICITY BY OTHERS
43 Short-term Purchases 0 0 0
44 BPA Point-to-Point/NT 18,297 334 18,632
45 BPA Townsend to Garrison 1,422 0 1,422
46 Columbia Basin Hydro 3,365 832 4,197
47 Avista on BPA Borderline/Network 1,949 25 1,973
48 Kootenai for Worley 57 0 57
49 Sagle for Northern Lights 134 0 134
50 Northwestern 6,254 0 6,254
51 Portland General Electric John Day to COB 1,445 0 1,445
52 Total Account 565 32,922 1,191 34,114
53
54 407 Regulatory Debits
55 407.434 Incremental EIM O&M(reconciling item) 0 0 0
56
57 537 MT Invasive Species
58 Total Montana Invasive Species 780 0 780
59
60 ITOTAL EXPENSE 366,477 26,943 393,421
Exhibit No.8
Case No.AVU-E-25-01
C. Kalich,Avista
Schedule 2, Page 3 of 4

Avista Corp.
Power Supply Pro Forma - Idaho Jurisdiction
System Numbers - 9/25 - 8/26 Pro Forma vs. 09/26 - 08/27 Pro Forma RY2
Test Year Load
($000)
Line 9/1/25-8/31/26 9/1/26-8/31/27
No. Pro Forma Adjustment Pro Forma
61
62 447 SALES FOR RESALE
63 Short-Term Market 175,397 1,861 177,258
64 Nichols Pumping 1,076 -1,076 0
65 Sovereign/Kaiser Services 141 0 141
66 Pend Oreille PUD 473 0 473
67 Merchant Ancillary Services(reconciling item) 0 0 0
68 Total Account 447 177,087 785 177,872
69
70 456 OTHER ELECTRIC REVENUE
71 Non-WA EIA REC(reconciling item-Idaho only) 0 0 0
72 Natural Gas Liquids 395 0 395
73 Surplus AECO to Malin Transportation -17,862 -612 -18,475
74 Total Account 456 -17,467 -612 -18,079
75
76 ITOTAL REVENUE 159,620 172 159,793
77
78 ITOTAL NET EXPENSE 206,857 26,771 233,628
Exhibit No.8
Case No.AVU-E-25-01
C. Kalich,Avista
Schedule 2, Page 4 of 4

Line Avista Corp.
No. Brief Description of Kalich Exhibit No.8,Schedule 3- Power Workpaper
Supply Adjustment
1 N/A
2 Short-Term Market.Term financial and physical contracts,plus hour Term deals.xlsx
spot transactions. Spot market in proforma are results of Aurora
model.
3 Chelan PUD. Rocky Reach and Rock Island contract expense. Aurora-generated-see CGK-1/CGK-2
Ex Tres 12/31/2040.
4 Douglas PUD. Wells Purchase contract expense. Aurora-generated-see CGK-1/CGK-2
Ex ires 12/31/2040.
5 Grant PUD. Priest Rapids and Wanapum contract expense. Aurora-generated-see CGK-1/CGK-2
Expires 12/31/2040.
6 Columbia Basin Hydro. Contracts expense on multiple CBH Aurora-generated-see CGK-1/CGK-2
projects. Expires 12/31/2045.
7 Lancaster PPA. Includes contract costs of capital,operations and Lancaster PPA-workpaper.xlsx(for
maintenance(O&M). Variable O&M based on the generation level PPA energy,capacity&O&M)
determined b Aurora model.
8 Small Power-Summation of small PURPA power contracts;pro Small Power.xlsx and IPC Deer
forma costs are based on 5-year average generation levels and Lake.xlsx
actual pro forma period contract rates.
9 Spokane Upriver. PURPA purchase from City of Spokane;based Upriver Gen and Load.xlsx
on 5-year average of local pumping and generation levels and
priced using actual contract rates.
10 Spokane Waste to Energy. PURPA purchase from City of Spokane; Spokane_Waste_to_Energy.xlsx
based on 5-year average of generation levels and priced using
actual contract rates.
11 'Palouse Wind. Not included- flows through PCA.
12 Clearwater Wind.
13 Rattlesnake Wind. Not included -flows through PCA.
14 Adams-Neilson Solar(Solar Select). Contract purchase based on Represents the net purchase/sale deal
output estimated by facility,as project has been in existence only
since 2018;priced using actual contract rates.
15 Clearwater-Idaho only.
16 WPN Ancillary Services-reconciling item.
17 Non-Monetary Accruals-reconciling item.
18 Total Account 555-with reconciling items. Summarization of Account 555 lines.
19 N/A
20 N/A
21 Miscellaneous Transaction Fees. Expense is 5-year average of Transactions Fees.xlsx
transaction fees for CAISO,brokerage fees for electricity and
natural gas market transactions,and Canadian Merchandise
Processing Fees assessed by the U.S.Government on imported
22 Other Resource Cost. Optional renewable power offset;set to zero Not included in rate period proforma.
in pro forma.
23 Natural Gas Fuel. Purchases to fuel gas-fired generation fleet as Reclassification-please see
part of risk management/hedging policy,but then later re-sold(see acccounts 547/456
line 67,Surplus AECO to Malin Transportation)due to changing
market conditions(i.e.,plant later becomes uneconomic relative to
purchasing electricity from the market). Pro forma expense is zero
because we do not emulate our hedging program in pro forma
modelinq while test year expense is the qains/losses of hedqinq
24 Total Account 557 Summarization of Account 557 lines.
25 N/A
26 N/A
27 Kettle Falls Generation Station. Combined wood fuel and natural Fuel Costs'sheet of this exhibit,Kettle
gas expense. Wood fuel expense is based on Aurora model and Colstrip Fuel 2017-2021.xlsx
generation multiplied by the latest budget fuel price. Natural gas
used for starting the plant is based on 5-year average.
28 Colstrip. Combined coal and fuel oil expense. Coal expense is Fuel Costs'sheet of this exhibit,Kettle
based on fixed and variable costs under a long-term contract. The and Colstrip Fuel 2017-2021.xlsx
variable portion of coal fuel costs is based on generation levels from
the Aurora model. Fuel oil used for starting the plant is based on 5-
year average.
29 Total Account 501. Summarization of Account 501 lines.
30 N/A
31 N/A
32 Coyote Springs 2 Combined Cycle Combustion Turbine. Natural 'Fuel Costs'sheet of this exhibit
gas cost based on Aurora model dispatch priced first at its location,
but then reduced to AECO basin prices where long-term contract
transportation rights exist. See testimony and workpapers for more
detail on this calculation.
Exhibit No.8
Case No.AVU-E-25-01
C.Kalich,Avista Page 1 of 3
Schedule 3,Page 1 of 3

Line Avista Corp.
No. Brief Description of Kalich Exhibit No.B,Schedule 3- Power Workpaper
SuDDIv Adjustment
33 Lancaster Combined Cycle Combustion Turbine. Natural gas cost 'Fuel Costs'sheet of this exhibit
based on Aurora model dispatch priced first at its location,but then
reduced to AECO basin prices where long-term contract
transportation rights exist. See testimony and workpapers for more
detail on this calculation.
34 TC Energy Pipleline. Costs related to firm natural gas pipeline Thermal Budget
capacity on TC Energy pipeline between AECO and Kingsgate. Sep2025thruAug2027.xlsx
Used for our Lancaster and Coyote Springs 2 plants. Variable
charges are billed at tariffed rates based on the 5-year average
generation.
35 Williams Northwest Pipeline. Costs related to use of the Williams 'Fuel Costs'sheet of this exhibit
Northwest pipeline. Used for our Boulder Park,Northeast,and
Kettle Falls CT plants. Charges are billed at tariffed rates based on
the 5-year average generation.
36 Rathdrum Combustion Turbine. Natural gas cost based on Aurora 'Fuel Costs'sheet of this exhibit
model dispatch priced first at its location,but then reduced to AECO
basin prices where long-term contract transportation rights exist.
See testimony and workpapers for more detail on this calculation.
37 Northeast Combustion Turbine. Natural gas cost based on Aurora 'Fuel Costs'sheet of this exhibit
model dispatch priced first at its location,but then reduced to AECO
basin prices where long-term contract transportation rights exist.
See testimony and workpapers for more detail on this calculation.
38 Boulder Park Engines. Natural gas cost based on Aurora model 'Fuel Costs'sheet of this exhibit
dispatch priced first at its location,but then reduced to AECO basin
prices where long-term contract transportation rights exist. See
testimony and workpapers for more detail on this calculation.
39 Kettle Falls Combustion Turbine. Natural gas cost based on Aurora 'Fuel Costs'sheet of this exhibit
model dispatch priced first at its location,but then reduced to AECO
basin prices where long-term contract transportation rights exist.
See testimony and workpapers for more detail on this calculation.
40 ITotal Account 547 Summarization of Account 547 lines.
41 1 N/A
42 N/A
43 Short-Term Purchases. Set to zero in proforma reflecting additional Not included in rate period pro forma
50 MW long-term Point-to-Point contract purchase from BPA for
Co vote S rin s 2 accounted for in line 48.
44 BPA Point-to-Point/NT. Proforma expense is based on contracted 565 Transmission Expense.xlsx
capacity at tariffed rate. For Colstrip,Coyote Springs 2, Columbia
Basin Hydro and Lancasterincludes additional 50 MW contract for
Coyote Springs 2.
45 BPA Townsend to Garrison. Fixed fee contract with BPA for 565 Transmission Expense.xlsx
transmission of Colstrip power from Townsend to Garrison.
46 Avista on BPA Borderlines. Purchase for serving Avista load in 3rd- 565 Transmission Expense.xlsx
party service area. 5-year average of actual expense priced at
proforma year tariffed rate.
47 Columbia Basin Hydro transmission 565 Transmission Expense.xlsx
48 Kootenai for Worley. Purchase for serving Avista load in 3rd-party 565 Transmission Expense.xlsx
service area. Pro forma expense is based on contracted capacity at
tariffed rate.
49 Sagle for Northern Lights. Purchase for serving Avista load in 3rd- 565 Transmission Expense.xlsx
party service area. Pro forma expense is based on contracted
caDacitv at tariffed rate.
50 Northwestern. Purchase on Northwestern for Colstrip generation 565 Transmission Expense.xlsx
above 196-MW BPA Townsend to Garrison contract and Clearwater
III generation.Also includes an annual fee that expires 9/1/2029.
51 Portland General Electric John Day to COB. Purchase of Southern 565 Transmission Expense.xlsx
Interntie rights from John Day substation to California-Oregon
border. Proforma expense priced at pro forma year tariffed rate.
52 Total Account 565. Summarization of Account 565 lines
53 N/A
54 N/A
55 407.434 Incremental EIM O&M(reconciling item
56 N/A
57 Montana Invasive Species.
58 Total Account 537.
59 N/A
60 Total Expense-Sum of Accounts 555,557,501,547,565.
61 N/A
Exhibit No.8
Case No.AVU-E-25-01
C.Kalich,Avista Page 2 of 3
Schedule 3,Page 2 of 3

Line Avista Corp.
No. Brief Description of Kalich Exhibit No.B,Schedule 3- Power Workpaper
SuDDIv Adjustment
62 N/A
63 Short-Term Market. Term financial and physical contracts,plus Aurora-generated-see CGK-1/CGK-2
hourly spot transactions. Spot market in pro forma are results of
Aurora model.
64 Nichols Pumping. Sale of energy for water pumping loads of Aurora-generated-see CGK-1/CGK-2
Colstrip Units 3 and 4;contract price is Mid-C index less
$0.50/MWh. Lower revenue due to reduction in pumping load with
closure of Units 1&2.
65 Sovereign/Kaiser Services. Sale of balancing area services to 447 Sovereign and POPUD.xlsx
Kaiser's Trentwood plant. Based on 5-year average.
66 Pend Oreille PUD. Sale of balancing area services to Pend Oreille 447 Sovereign and POPUD.xlsx
PUD.Based on TY since 5-year average overstates due to loss of
large industrial customers. Contract expires 9/30/2026.
67 Merchant Ancillary Services-reconciling item.
68 Total Account 447-with reconciling items. Summarization of Account 447 lines
69 N/A
70 N/A
71 Non-WA EIA REC Revenue. Idaho share of REC sales. These are Not included in rate period proforma.
not included in base power supply expenses and are tracked and Included in annual REC filing.
rebated annually in WA and goes through the base for ID.
72 Natural Gas Liquids. Liquids rebates from natural gas purchased at Natural Gas Liquids.xlsx
AECO;5-year average.
73 Surplus AECO to Malin Transportation. Test year value includes 'Fuel Costs'and'Gas Contracts MTM'
resale of purchases made to fuel gas-fired generation fleet as part sheets of this exhibit
of risk management/hedging policy(see line 20,Natural Gas Fuel
Purchases)due to changing market conditions(i.e.,plant later
becomes uneconomic relative to purchasing electricity from the
market). Pro forma value reflects only revenue received from
buying AECO gas and selling it at Malin using firm transportation
,rights surplus to Avista gas plant use.
74 Total Account 456. Summarization of Account 456 lines
75 N/A
76 Total Revenue-Sum of Accounts 447,456.
77 N/A
78 Total Net Expense-Total expense minus total revenue.
Exhibit No.8
Case No.AVU-E-25-01
C.Kalich,Avista Page 3 of 3
Schedule 3,Page 3 of 3

Avista Corp.
Market Purchases and Sales,Plant Generation and Fuel Cost Summary
Idaho Normalized September 2025-August 2026
720 744 720 744 744 672 744 720 744 720 744 744
Total Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 Jul-26 Aug-26
Market Sales-Dollars $175,397,280 $21,401,220 $9,697,600 $20,727,530 $20,480,490 $2,820,160 $15,820,770 $11,190,690 $12,987,680 $15,509,730 $18,031,480 $16,861,560 $9,868,370
Market Sales-MWh (3,266,774) -334,960 -144,723 -275,528 -217,803 -78,397 -163,421 -202,627 -326,271 -506,025 -546,992 -288,154 -181,873
Average Market Sales Price-$/MWh -$53.69 -$63.89 -$67.01 -$75.23 -$94.03 -$35.97 -$96.81 -$55.23 -$39.81 -$30.65 -$32.96 -$58.52 -$54.26
Market Purchases-Dollars $13,480,630 $0 $871,760 $59,390 $720 $6,320,130 $554,700 $256,590 $4,600 $0 $0 $51,170 $5,361,570
Market Purchases-MWh 124,797 0 23,135 2,977 7 58,890 14,796 9,774 341 0 0 607 14,270
Average Market Purchase Price-$/MWh $108.02 $0.00 $37.68 $19.95 $102.86 $107.32 $37.49 $26.25 $13.49 $0.00 $0.00 $84.30 $375.72
Net Market Purchases(Sales)MWh -3,141,977 -334,960 -121,588 -272,551 -217,796 -19,507 -148,625 -192,853 -325,930 -506,025 -546,992 -287,547 -167,603
Net Market Purchases(Sales)aMW -358.7 -465 -163 -379 -293 -26 -221 -259 -453 -680 -760 -386 -225
Average Sale and Purchase Price-$/MWh $47.74 -$63.89 -$52.58 -$74.21 -$94.03 $25.49 -$85.66 -$51.48 -$39.75 -$30.65 -$32.96 -$58.22 -$22.98
Colstrip MWh 344,208 142,536 0 140,838 60,834 0 0 0 0 0 0 0 0
Colstrip Fuel Cost$/MWh $19.20 $22.02 $0.00 $17.08 $17.21 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00
Colstrip Fuel Cost $6,607,933 $3,138,378 $17,243 $2,405,206 $1,047,106 $0 $0 $0 $0 $0 $0 $0 $0
Kettle Falls MWh 285,640 29,991 26,446 31,158 33,587 20,982 29,329 27,390 12,887 2,474 9,769 29,372 32,255
Kettle Falls Fuel Cost$/MWh $31.87 $31.67 $31.99 $31.47 $31.23 $32.39 $31.45 $31.75 $33.67 $40.98 $33.87 $31.56 $31.44
Kettle Falls Fuel Cost $9,104,438 $949,853 $846,023 $980,473 $1,049,063 $679,663 $922,483 $869,703 $433,873 $101,373 $330,873 $926,933 $1,014,123
Coyote Springs MWh 1,855,388 190,503 126,416 202,064 216,533 162,702 176,153 157,286 101,535 37,587 102,251 190,031 192,327
Coyote Springs Fuel Cost$/MWh $13.54 $12.73 $15.04 $16.06 $11.13 $6.99 $11.72 $15.85 $16.49 $15.47 $17.00 $14.68 $13.81
Coyote Springs Fuel Cost $25,115,607 $2,424,212 $1,901,020 $3,244,924 $2,410,620 $1,137,577 $2,063,906 $2,493,104 $1,674,662 $581,396 $1,738,510 $2,789,344 $2,656,330
Lancaster MWh 1,780,436 166,488 171,775 168,816 186,687 138,691 155,653 163,202 120,674 97,723 77,139 165,925 167,663
Lancaster Fuel Cost$/MWh $20.14 $15.85 $14.18 $17.89 $25.75 $29.02 $26.31 $20.96 $17.82 $17.76 $18.57 $18.66 $17.92
Lancaster Fuel Cost $35,860,938 $2,638,375 $2,435,411 $3,019,298 $4,806,784 $4,024,539 $4,095,876 $3,419,974 $2,150,965 $1,735,958 $1,432,818 $3,095,781 $3,005,160
Boulder Park MWh 132,082 12,836 13,228 12,132 15,231 6,118 12,637 9,254 8,213 6,452 6,834 13,877 15,270
Boulder Park Fuel Cost$/MWh $26.41 $20.13 $19.04 $27.64 $35.88 $44.84 $33.50 $26.39 $21.87 $22.18 $23.22 $23.50 $22.73
Boulder Park Fuel Cost $3,488,617 $258,395 $251,857 $335,284 $546,446 $274,351 $423,328 $244,257 $179,604 $143,132 $158,685 $326,149 $347,129
Kettle Falls CT MWh 33,650 3,210 3,309 3,287 4,492 1,013 3,673 2,602 1,902 1,333 1,006 3,736 4,087
Kettle Falls CT Fuel Cost$/MWh $32.53 $24.89 $22.58 $31.95 $41.61 $74.79 $40.18 $32.18 $25.42 $26.92 $28.60 $29.50 $28.83
Kettle Falls CT Fuel Cost $1,094,670 $79,882 $74,716 $105,014 $186,905 $75,763 $147,581 $83,740 $48,348 $35,891 $28,773 $110,223 $117,833
Rathdrum MWh 776,635 89,509 84,418 79,815 104,349 37,126 94,567 78,774 32,521 19,345 13,242 44,593 98,376
Rathdrum Fuel Cost$/MWh $34.81 $26.45 $24.18 $34.99 $45.50 $59.02 $42.63 $33.86 $28.02 $29.07 $29.69 $30.92 $29.96
Rathdrum Fuel Cost $27,031,693 $2,367,296 $2,041,222 $2,793,083 $4,747,457 $2,191,101 $4,031,165 $2,667,379 $911,123 $562,315 $393,109 $1,379,011 $2,947,434
Northeast MWh 0 0 0 0 0 0 0 0 0 0 0 0 0
Northeast Fuel Cost$/MWh #D IVIO!
Northeast Fuel Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Fuel Expense $108,303,896 $11,856,391 $7,567,493 $12,883,282 $14,794,381 $8,382,996 $11,684,339 $9,778,157 $5,398,575 $3,160,064 $4,082,767 $8,627,441 $10,088,010
Net Fuel and Purchase Expense -$53,612,754
Exhibit No.8 Page 1 of 2
Case No.AVU-E-25-01
C.Kalich,Avista
Schedule 4,Page 1 of 2

Avista Corp.
Market Purchases and Sales,Plant Generation and Fuel Cost Summary
Idaho Normalized September 2026-August 2027
720 744 720 744 744 672 744 720 744 720 744 744
Total Sep-26 Oct-26 Nov-26 Dec-26 Jan-27 Feb-27 Mar-27 Apr-27 May-27 Jun-27 Jul-27 Aug-27
Market Sales-Dollars $177,268,230 $15,521,460 $11,525,840 $14,244,020 $17,649,940 $3,823,190 $13,647,060 $14,947,330 $11,681,340 $17,437,830 $18,036,590 $22,817,630 $15,926,000
Market Sales-MWh (3,123,382) -238,792 -177,167 -184,794 -190,718 -52,381 -143,842 -229,211 -312,965 -509,192 -551,374 -320,602 -212,344
Average Market Sales Price-$/MWh -$56.75 -$65.00 -$65.06 -$77.08 -$92.54 -$72.99 -$94.88 -$65.21 -$37.32 -$34.25 -$32.71 -$71.17 -$75.00
Market Purchases-Dollars $14,174,410 $6,240 $19,530 $129,490 $18,120 $6,841,150 $958,890 $258,550 $29,060 $0 $0 $75,330 $5,838,050
Market Purchases-MWh 156,577 151 395 4,929 152 100,545 24,365 7,524 1,848 0 0 828 15,840
Average Market Purchase Price-$/MWh $90.53 $41.32 $49.44 $26.27 $119.21 $68.04 $39.36 $34.36 $15.73 $0.00 $0.00 $90.98 $368.56
Net Market Purchases(Sales)MWh -2,966,805 -238,641 -176,772 -179,865 -190,566 48,164 -119,477 -221,687 -311,117 -509,192 -551,374 -319,774 -196,504
Net Market Purchases(Sales)aMW -338.7 -331 -238 -250 -256 65 -178 -298 -432 -684 -766 -430 -264
Average Sale and Purchase Price-$/MWh $49.72 -$64.93 -$64.80 -$74.40 -$92.38 $19.73 -$75.43 -$62.05 -$37.01 -$34.25 -$32.71 -$70.75 -$44.21
Colstrip MWh 0 0 0 0 0 0 0 0 0 0 0 0 0
Colstrip Fuel Cost$/MWh #DIV/O! #DIV/O! #DIV/01 #DIV/O! #DIV/01 #DIV/O! #DIV/O! #DIV/O! #DIV/O! #DIV/O! #DIV/01 #DIV/O! #DIV/01
Colstrip Fuel Cost $6,607,933 $3,138,378 $17,243 $2,405,206 $1,047,106 $0 $0 $0 $0 $0 $0 $0 $0
Kettle Falls MWh 292,116 31,710 30,380 31,378 33,587 16,940 29,142 30,444 12,035 2,588 8,443 32,303 33,166
Kettle Falls Fuel Cost$/MWh $31.17 $29.95 $27.85 $31.25 $31.23 $40.12 $31.65 $28.57 $36.05 $39.17 $39.19 $28.69 $30.58
Kettle Falls Fuel Cost $9,104,438 $949,853 $846,023 $980,473 $1,049,063 $679,663 $922,483 $869,703 $433,873 $101,373 $330,873 $926,933 $1,014,123
Coyote Springs MWh 1,830,368 190,628 126,674 197,213 209,213 151,007 173,668 159,372 99,061 38,268 100,956 191,981 192,327
Coyote Springs Fuel Cost$/MWh $13.72 $12.72 $15.01 $16.45 $11.52 $7.53 $11.88 $15.64 $16.91 $15.19 $17.22 $14.53 $13.81
Coyote Springs Fuel Cost $25,115,607 $2,424,212 $1,901,020 $3,244,924 $2,410,620 $1,137,577 $2,063,906 $2,493,104 $1,674,662 $581,396 $1,738,510 $2,789,344 $2,656,330
Lancaster MWh 1,720,454 166,488 174,784 167,423 182,243 100,013 153,457 166,432 114,086 92,310 69,753 166,531 166,934
Lancaster Fuel Cost$/MWh $20.84 $15.85 $13.93 $18.03 $26.38 $40.24 $26.69 $20.55 $18.85 $18.81 $20.54 $18.59 $18.00
Lancaster Fuel Cost $35,860,938 $2,638,375 $2,435,411 $3,019,298 $4,806,784 $4,024,539 $4,095,876 $3,419,974 $2,150,965 $1,735,958 $1,432,818 $3,095,781 $3,005,160
Boulder Park MWh 134,923 13,834 14,427 13,359 15,816 4,820 11,613 10,559 6,637 6,682 5,812 15,356 16,008
Boulder Park Fuel Cost$/MWh $25.86 $18.68 $17.46 $25.10 $34.55 $56.92 $36.45 $23.13 $27.06 $21.42 $27.30 $21.24 $21.68
Boulder Park Fuel Cost $3,488,617 $258,395 $251,857 $335,284 $546,446 $274,351 $423,328 $244,257 $179,604 $143,132 $158,685 $326,149 $347,129
Kettle Falls CT MWh 37,787 3,630 4,548 4,052 4,711 1,276 3,375 3,666 882 1,269 605 4,646 5,127
Kettle Falls CT Fuel Cost$/MWh $28.97 $22.01 $16.43 $25.92 $39.67 $59.38 $43.73 $22.84 $54.82 $28.28 $47.56 $23.72 $22.98
Kettle Falls CT Fuel Cost $1,094,670 $79,882 $74,716 $105,014 $186,905 $75,763 $147,581 $83,740 $48,348 $35,891 $28,773 $110,223 $117,833
Rathdrum MWh 812,063 96,628 94,712 86,898 111,408 31,430 80,224 98,492 22,389 18,545 15,488 50,687 105,162
Rathdrum Fuel Cost$/MWh $33.29 $24.50 $21.55 $32.14 $42.61 $69.71 $50.25 $27.08 $40.70 $30.32 $25.38 $27.21 $28.03
Rathdrum Fuel Cost $27,031,693 $2,367,296 $2,041,222 $2,793,083 $4,747,457 $2,191,101 $4,031,165 $2,667,379 $911,123 $562,315 $393,109 $1,379,011 $2,947,434
Northeast MWh 0 0 0 0 0 0 0 0 0 0 0 0 0
Northeast Fuel Cost$/MWh #DIV/0I
Northeast Fuel Cost $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Fuel Expense $108,303,896 $11,856,391 $7,567,493 $12,883,282 $14,794,381 $8,382,996 $11,684,339 $9,778,157 $5,398,575 $3,160,064 $4,082,767 $8,627,441 $10,088,010
Net Fuel and Purchase Expense -$54,779,924
Exhibit No.8 Page 2 of 2
Case No.AVU-E-25-01
C.Kalich,Avista
Schedule 4,Page 2 of 2

Avista Corp
PCA Authorized Expense and Retail Sales(Annual)
Based on Pro forma 9/1/2025-8/31/2026
7/1/2023-6/30/2024 Historic Normalized Loads
PCA Authorized Power Supply Expense-System Numbers(1)
Total Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Auc
Account 555-Purchased Power $211,312,948 $14,301,640 $15,722,221 $13,839,062 $14,217,056 $23,434,130 $16,763,089 $16,391,163 $18,407,293 $18,695,475 $18,213,573 $18,260,115 $23,068,133
Account 501-Thermal Fuel $15,712,371 $4,088,231 $863,266 $3,385,680 $2,096,169 $679,663 $922,483 $869,703 $433,873 $101,373 $330,873 $926,933 $1,014,123
Account 537-MT Invasive Species $780,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000
Account 547-Natural Gas Fuel $104,791,114 $8,781,685 $7,732,236 $10,509,812 $13,732,592 $8,712,646 $11,748,648 $9,927,317 $5,970,843 $4,074,001 $4,753,424 $8,735,538 $10,112,369
Account 557-Other Expenses $958,465 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872
Account 565-Transmission Expense $32,922,334 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528 $2,743,528
Account 456-Other Revenue $17,467,020 $1,337,159 $1,088,750 $1,263,554 $2,162,511 $3,582,523 $1,723,440 $1,121,053 $589,881 $1,040,209 $994,579 $1,252,789 $1,310,571
Account 447-Sale for Resale -$177,087,369 -$21,692,234 -$9,959,264 -$21,032,734 -$20,903,544 -$2,871,304 -$15,871,914 -$11,241,834 -$13,038,824 -$15,560,874 -$18,082,624 -$16,912,704 -$9,919,514
Power Supply Expense $206,856,883 $9,704,882 $18,335,610 $10,853,774 $14,193,185 $36,426,058 $18,174,146 $19,955,802 $15,251,466 $11,238,584 $9,098,224 $15,151,071 $28,474,082
Account 456-Transmission Revenue(2) -$37,482,160 -$3,099,146 -$3,125,305 -$2,986,534 -$3,189,458 -$3,183,581 -$3,191,635 -$3,172,317 -$3,771,567 -$2,633,999 -$2,846,226 -$3,400,571 -$2,881,821
Total Authorized Expense $169,374,723 $6,605,736 $15,210,305 $7,867,239 $11,003,727 $33,242,478 $14,982,511 $16,783,485 $11,479,899 $8,604,585 $6,251,998 $11,750,500 $25,5 22,260
Idaho Only(no adjustment for Directly assigned) $60,161,902 $2,346,357 $5,402,700 $2,794,443 $3,908,524 $11,807,728 $5,321,788 $5,961,494 $4,077,660 $3,056,348 $2,220,710 $4,173,778 $9,090,371
PCA Authorized Idaho Retail Sales(3)
Total Idaho Retail Sales,MWh 3,082,930 304,450 275,917 276,088 250,222 227,023 225,845 256,211 254,893 218,497 235,421 260,464 297,899
RY1 Load Change Adjustment Rate(4) $25.48/MWh
RY2 Load Change Adjustment Rate(4) $27.12/MWh
(1)Multiply number by ROO current production/transmission allocation ratio of 35.52
(2)Transmission Revenue as discussed by Company witness Mr.Dillon.
(3)Note totals may vary slightly from adjustment due to rounding.
(4)Twelve months ended June 30,2024 normalized monthly retail sales.
Exhibit No.8
Case No.AVU-E-25-01
C.Kalich,Avista
Schedule 5,Page 1 of 2

Avista Corp
PCA Authorized Expense and Retail Sales(Annual)
Based on Pro forma 9/1/2026-8/31/2027
7/1/2023-6/30/2024 Historic Normalized Loads
PCA Authorized Power Supply Expense-System Numbers(1)
Total Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Auc
Account 555-Purchased Power $228,670,118 $17,087,840 $17,730,101 $16,818,352 $16,384,736 $24,203,900 $17,234,009 $16,995,443 $19,303,893 $19,461,075 $19,402,103 $19,427,795 $24,620,873
Account 501-Thermal Fuel $9,194,994 $990,245 $954,075 $981,415 $1,044,955 $541,375 $911,995 $959,095 $398,355 $89,495 $279,305 $1,010,875 $1,033,805
Account 537-MT Invasive Species $780,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000 $65,000
Account 547-Natural Gas Fuel $119,703,277 $9,936,460 $9,477,325 $12,472,150 $15,801,413 $11,636,552 $12,795,937 $11,437,768 $5,927,486 $4,384,082 $5,235,641 $9,510,271 $11,088,193
Account 557-Other Expenses $958,465 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872 $79,872
Account 565-Transmission Expense $34,113,744 $2,842,812 $2,842,812 $2,842,812 $2,842,812 $2,842,812 $2,842,812 $2,842,812 $2,842,812 $2,842,812 $2,942,812 $2,842,812 $2,842,812
Account 456-Other Revenue $18,079,276 $1,176,201 $1,094,022 $1,558,211 $2,047,492 $3,233,162 $1,900,262 $1,102,734 $929,471 $1,540,573 $1,289,595 $1,105,487 $1,102,067
Account 447-Sale for Resale -$177,871,959 -$15,572,604 -$11,576,984 -$14,295,164 -$17,701,084 -$3,874,334 -$13,698,204 -$14,998,474 -$11,732,484 -$17,488,974 -$18,087,734 -$22,868,774 -$15,977,144
Power Supply Expense $233,627,915 $16,605,826 $20,666,223 $20,522,648 $20,565,196 $38,728,339 $22,131,683 $18,484,250 $17,814,404 $10,973,934 $11,106,594 $11,173,338 $24,855,478
Account 456-Transmission Revenue(2) -$38,969,317 -$3,437,487 -$3,326,229 -$3,187,458 -$3,390,382 -$3,109,672 -$3,117,726 -$3,036,946 -$3,636,196 -$2,875,150 -$3,087,377 -$3,641,722 -$3,122,972
Total Authorized Expense $194,658,597 $13,168,339 $17,339,994 $17,335,190 $17,174,815 $35,618,668 $19,013,957 $15,447,304 $14,178,208 $8,098,784 $8,019,217 $7,531,616 $21,7 22,505
Idaho Only(no adjustment for Directly assigned) $69,142,734 $4,677,394 $6,159,166 $6,157,459 $6,100,494 $12,651,751 $6,753,758 $5,486,883 $5,036,100 $2,876,688 $2,848,426 $2,675,230 $7,719,386
PCA Authorized Idaho Retail Sales(3)
Total Idaho Retail Sales,MWh 3,082,930 304,450 275,917 276,088 250,222 227,023 225,945 256,211 254,893 218,497 235,421 260,464 297,899
RY1 Load Change Adjustment Rate(4) $25.48/MWh
RY2 Load Change Adjustment Rate(4) $27.12/MWh
(1)Multiply number by ROO current production/transmission allocation ratio of 35.52
(2)Transmission Revenue as discussed by Company witness Mr.Dillon.
(3)Note totals may vary slightly from adjustment due to rounding.
(4)Twelve months ended June 30,2024 normalized monthly retail sales.
Exhibit No.8
Case No.AVU-E-25-01
C.Kalich,Avista
Schedule 5,Page 2 of 2