20230201Kalich Direct.pdf

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-23-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-23-01
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)

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

Kalich, Di 2
Avista Corporation
one-quarter of the Company’s retail load. 1
In mid-2000 I joined Avista Utilities and accepted my current position assisting the 2
Company in resource analyses, dispatch modeling, resource procurement, integrated resource 3
planning and rate case proceedings. Much of my career has involved resource dispatch 4
modeling of the nature described in this testimony. 5
Q. What is the scope of your testimony in this proceeding? 6
A. My testimony includes documentation of the rationale for key inputs and 7
assumptions driving power supply cost values including loads, natural gas and electricity 8
prices, and a comparison to current levels of authorized power supply expense. I will provide 9
an overview on contract changes since our last filing, including our newly signed Columbia 10
Basin Hydro contract, and discuss Washington State’s new Climate Commitment Act (CCA) 11
and how its limitations on thermal plant carbon emissions affect Idaho costs. Finally, I will 12
identify and explain the proposed pro forma adjustments to test period power supply revenues 13
and expenses, including the Retail Revenue Credit used in the Power Cost Adjustment (PCA). 14
A table of contents for my testimony is below: 15
Description Page 16
I. Introduction 1 17
II. Dispatch Model 3 18
III. Washington Climate Commitment Act (CCA) 8 19
IV. Other Key Modeling Assumptions 14 20
V. Modeling Results 21 21
VI. Overview of Pro Forma Power Supply Adjustment 22 22
VII. Pro Forma Power Supply Adjustment 22 23
VIII. PCA Authorized Values 27 24
25
Q. Are you sponsoring any exhibits in this proceeding? 26
A. Yes. I am sponsoring Confidential Exhibit No. 7, Schedules 1 through 5, as 27
shown in Table No. 1 below. Confidential Schedule 1C and Schedules 2 through 5 are 28

Kalich, Di 3
Avista Corporation
contained within one workbook in my workpapers, with all formulas and links intact for ease 1
of reference. Schedules 1C, 2, 4 and 5 have two exhibits each, one for each rate year. In 2
addition to these schedules, sheets after them in the workbook provide detail and supporting 3
calculations. Information contained in these exhibits were prepared by me or at my direction. 4
Table No. 1 – Confidential Exhibit No. 7 List of Schedules 5
6
II. DISPATCH MODEL 7
Q. Has the Company made any changes to the overall Portfolio Modeling 8
Methodology used in this case as compared to the last general rate case? 9
A. No. We are using the same methodology as our 2021 General Rate Case filing, 10
Case No. AVU-E-21-01, including using Aurora (Model) to optimize Company-owned 11
resource and contract dispatch during each hour of pro forma year. 12
Q. What experience does the Company have using Aurora? 13
A. The Model has been at Avista since April 2002 and used for numerous studies 14
including each of our integrated resource plans and rate filings after 2002. We also use Aurora 15
for various resource evaluations, market forecasting and requests-for-proposal evaluations. 16
Q. Please briefly describe how the Model is used in this case. 17
A. The Company uses the Model with “input prices”. Using input prices instead 18
of Aurora-generated prices allows the Model to optimize against prices input by Avista for 19
electricity and natural gas that reflect market conditions forecast for the rate period. Using 20
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

Kalich, Di 4
Avista Corporation
this method, prices more accurately reflect current forward prices in the wholesale 1
marketplace, the overall modeling process is simplified, and greater transparency is possible. 2
Once prices are input, the Model dispatches resources and contracts against wholesale 3
electric market prices and load obligations to determine net variable costs. When market 4
electricity prices are lower than operating one or more Company resources in each hour or set 5
of hours, wholesale market power purchases displace that generation. Where Avista resources 6
exceed hourly loads, and one or more of those resources cost less to operate than the market 7
price of electricity, the resources are sold into the market, lowering power supply cost for the 8
pro forma period. Once resources are dispatched and market purchases and sales are 9
determined, all costs are summarized into my Confidential Exhibit No. 7, Schedule 2. Market 10
Purchases and Sales, Plant Generation, and Fuel Cost Summary is provided as Confidential 11
Exhibit No. 7, Schedule 4. 12
Q. What are the prices input into the Model? 13
A. Forward electricity and natural gas prices use the one-month average of 14
Intercontinental Exchange (ICE) prices from October 3, 2022 through November 1, 2022, the 15
date range up to the point where Avista began modeling its costs for this case.1 Table No. 2 16
below details the prices input into the Model affecting our resources. 17

1 A trading month contains approximately 20 trading days.

Kalich, Di 5
Avista Corporation
Period
AECO
($/dth)
Malin
($/dth)
Mid-C
LLH
($MWh)
Mid-C
HLH
($/MWh)Period
AECO
($/dth)
Malin
($/dth)
Mid-C
LLH
($MWh)
Mid-C
HLH
($/MWh)
Sep-23 3.016 4.691 72.84 167.17 Sep-24 2.900 4.099 69.81 127.59
Oct-23 3.135 4.541 62.61 86.23 Oct-24 3.027 4.034 51.16 71.64
Nov-23 3.633 5.387 68.75 93.70 Nov-24 3.422 4.622 55.65 77.66
Dec-23 3.967 6.091 78.36 108.18 Dec-24 3.725 5.430 66.80 95.19
Jan-24 4.043 6.205 69.74 105.11 Jan-25 3.817 5.395 79.47 93.23
Feb-24 4.015 5.873 62.10 91.35 Feb-25 3.758 5.328 70.02 80.17
Mar-24 3.559 4.820 50.85 73.81 Mar-25 3.447 4.701 57.94 65.97
Apr-24 2.943 3.797 38.12 47.19 Apr-25 3.175 3.812 34.13 44.65
May-24 2.804 3.708 32.71 45.03 May-25 2.977 3.711 29.11 42.36
Jun-24 2.827 3.793 31.30 45.26 Jun-25 3.018 3.842 28.68 43.85
Jul-24 2.844 4.103 72.15 135.02 Jul-25 3.081 3.974 81.54 119.46
Aug-24 2.855 4.144 84.38 155.11 Aug-25 3.106 4.012 92.50 133.17
RY1 Avg 3.303 4.763 60.33 96.10 RY2 Avg 3.288 4.413 59.73 82.91
Table No. 2 – Monthly Forward Prices at Key Trading Hubs 1
2
3
4
5
6
7
8
9
10
Market prices in the Model are shaped hourly for electricity and daily for natural gas 11
based on test year actuals, reflecting how these spot markets are anticipated to trade in the pro 12
forma year. For example, if the Mid-Columbia (Mid-C) electricity price in the first hour of 13
the test year is ninety percent of the average of all hourly prices in the first month of the test 14
year, then the price input in the Model for that hour is equal to ninety percent of the forward 15
price for the matching calendar month. Similar math is performed for natural gas, but because 16
the spot market for natural gas is traded in daily blocks the shape is daily using the daily gas 17
price test year shapes. Backup for the price calculations is included in my workpapers.2 18
Q. How does the Company model hydro in this case? 19
A. A single year of median monthly values is extracted from the 80-year water 20
record. The following box and whisker graph below depicts the monthly distribution and 21
variability of the 80-year record and median values for our largest hydroelectric resource, 22

2 See Kalich workpaper “NaturalGas_Elec_Prices_2023_1132022.xlsx”.

Kalich, Di 6
Avista Corporation
Noxon Rapids, on the Clark Fork River. Supporting data for the chart, as well as similar data 1
and charts for our other hydro plants and Mid-C contracts are presented in my workpapers.3 2
Chart No. 1 – Monthly Median Water at Noxon Rapids4 3
4
5
6
7
8
9
10
11
12
13
14
15
Q. How does the Model operate Company-controlled hydroelectricity 16
generation resources? 17
A. To reflect the flexibility of Company hydroelectricity resources, Avista 18
develops individual operations logic for each river system. This separation ensures the 19
flexibility inherent in these resources is credited to customers in the pro forma exercise using 20
generation profiles for each river system closely matching the latest five-year average. 21

3 See Kalich workpaper “Hydro History.xlsx”.
4 White line represents the median of the monthly variation. The solid blue box depicts the 25th-75th percentile,
while the horizontal lines at either ends represent the entire of variability excluding outliers.

Kalich, Di 7
Avista Corporation
Q. Please compare the operating statistics from the Model to recent historical 1
hydroelectricity plant operations. 2
A. Over the pro forma period the Model generates 66% of Clark Fork generation 3
during on-peak hours, approximating the five-year average of on-peak generation. Since on-4
peak hours represent only 57% of the year, this demonstrates a substantial shift to the more 5
valuable on-peak hours. Avista ensures this historical shaping for each river system is 6
reflected in each month. Data supporting these calculations are in my workpapers. 7
Q. How are reserves modeled? 8
A. Due to limitations, Avista does not implicitly represent reserves in the Model. 9
Instead, we employ two methods to reflect these obligations. As explained above, the first 10
method is using five-year hydro shaping to reflect the operations of our hydro plants over time 11
based on how they are impacted (de-optimized) to provide reserves. The second method is 12
limiting the dispatch of our Northeast and Rathdrum gas plants, just as we do in actual 13
operations. I discuss the impacts reserves place on our thermal fleet later in testimony. 14
Q. How is the Company valuing its firm natural gas transportation contracts 15
in circumstances when they are not needed to fuel generation facilities? 16
A. When our natural gas plants consume fuel in quantities below our 17
transportation rights, we reduce pro forma power supply costs by the surplus transportation 18
valued at the difference in natural gas prices at the AECO and Malin hubs (i.e., we optimize 19
the remaining transportation resource for the benefit of our customers given AECO natural 20
gas is typically less expensive than natural gas at Malin). 21

Kalich, Di 8
Avista Corporation
III. WASHINGTON CLIMATE COMMITMENT ACT (CCA) 1
Q. Please describe the new Washington Climate Commitment Act (CCA). 2
A. During its 2021 legislative session, the Washington legislature passed, and the 3
Governor approved, the Climate Commitment Act (CCA). The CCA is effectively a “cap-4
and-trade” program, with a goal to eliminate economy-wide carbon emissions by 95 percent 5
by 2050. Its provisions start January 1, 2023. All electric utilities must secure enough 6
allowances to cover the carbon emissions of imported power and generation from sources 7
emitting 25,000 metric tons or more annually. Specific to Avista, the new law covers carbon 8
emissions generated by the following: 9
• Washington situs-based thermal plants (except Kettle Falls Generating Station 10
and Northeast Combustion Turbine as their annual emissions fall below the 11
25,000 metric ton threshold), 12
• Washington’s multi-jurisdictional share of thermal plants located outside of 13
Washington State, 14
• Carbon-emitting thermal generation imported into Washington, and 15
• All non-specified electricity imported into Washington.5 16
The Department of Ecology distributes no-cost carbon allowances for sources above 17
used to serve Washington electric retail customer load. A true up is performed annually to 18
mitigate poor hydro conditions when expected thermal plants, and/or imports, would 19
presumably be needed to make up for the lost emissions-free hydro energy. To avoid paying 20
twice (or double counting) for carbon emissions already regulated by Washington State’s 2019 21

5 The Kettle Falls biomass facility, and its small gas-fired turbine are exempt from the CCA law because their
historical emissions during the 2015-2019 period fell below 25,000 tons of carbon.

Kalich, Di 9
Avista Corporation
Clean Energy Transformation Act (CETA)6, allowances covering Washington retail load are 1
distributed by the state at no cost. 2
Q. What do you mean by double-counting? 3
A. By our understanding, electric utilities were included in the CCA law to enable 4
linkage with the California cap-and-trade law. Yet already CETA requires all generation 5
serving Washington electric customers to be carbon neutral by 2030 and carbon free by 2045. 6
In other words, absent CCA, Washington’s retail load would be on a rapid trajectory to 7
reduced carbon intensity and elimination. Washington customers would pay for the shift away 8
from carbon-emitting resources. Absent no-cost allowances under CCA, Washington retail 9
electric customers would essentially be paying for their carbon emissions reduction twice. 10
Q. Is the new CCA law broader than CETA? 11
A. The CCA is a bit broader than CETA for electric utilities in that all significant 12
emissions in the state are to be reduced, not just those serving Washington retail electric load. 13
The CCA also regulates the carbon emission of resources imported into Washington State, 14
placing a cost on all emitting generation sold at the Northwest’s primary, if not near-exclusive, 15
Mid-C trading hub. 16
Q. Will the impacts of the CCA affect Idaho customers? 17
A. Yes, certain incremental costs of CCA for Idaho load should be borne by Idaho 18
customers and are included in this case. First, Idaho load served by Washington State-sited 19
plants emitting above the law’s 25,000 metric ton annual threshold (i.e., Boulder Park) will 20
incur a share of the costs to comply with the CCA. Second, any surplus thermal generation 21
imported for sale at the Mid-C from our Lancaster, Rathdrum and Coyote Springs 2, and 22

6 RCW 70A.45.020.

Kalich, Di 10
Avista Corporation
Colstrip, will incur a compliance cost. That surplus generation sold at the Mid-C is a benefit 1
to our customers, albeit now facing an additional CCA compliance cost. 2
Q. How have CCA effects been allocated between Idaho and Washington? 3
A. As with other production and transmission system costs, Avista has and will 4
allocate all these costs based on a Production/Transmission Ratio (PT Ratio) between 5
Washington and Idaho, or approximately 65.53% to Washington and 34.47% to Idaho. 6
Q. How does the CCA impact power supply costs modeled in this proceeding? 7
A. First it is important to explain that final CCA rules were released only this past 8
October 2022, and all regulated entities are working to comprehend its complete impacts. The 9
regulatory entity responsible for enacting the law is the Washington State Department of 10
Ecology (Ecology)7. Ecology has not yet provided detailed descriptions or examples to help 11
entities like Avista calculate compliance costs. As a result, Avista must approximate power 12
supply impacts based on its understanding of the law and associated rules which are not 13
understood with certainty. Though uncertainty exists, the larger aspects are understood at this 14
time. 15
Q. What is the expected cost of the emission allowances, and how much is 16
included in proforma power supply expense in this case? 17
A. Emission allowance prices for carbon dioxide equivalents are defined by 18
auction, with a cap and floor set by Ecology. In 2022, Ecology forecasted emission auction 19
prices affecting the two-year rate period of this case is shown in Table No. 3: 20
Table No. 3 – CO2 Equivalents Price per Metric Ton 21
Year 2023 2024 2025 Rate Year
1 Average
Rate Year 2
Average
Price per metric ton CO2 $67.93 $67.68 $73.74 $67.81 $70.71

7 WAC 173-446-010

Kalich, Di 11
Avista Corporation
As explained earlier in testimony, Idaho is affected by CCA as it pertains to the 1
operations of Boulder Park, as well as outside-Washington plant output sold at the Mid-C. 2
Modeling results in average carbon emissions of 51,306 metric tons per year over the Two-3
Year Rate Plan (system) for Boulder Park. Sales of imported power sold at the Mid-C from 4
outside-Washington thermal plants generate a total of 1.04 million metric tons of carbon in 5
Rate Year 1 (system). Rate Year 2 emissions are 1.19 million metric tons, again on a system 6
basis. This equates on a system basis to $70.5 million and $84.1 million in rate years one and 7
two, respectively, for CCA compliance. 8
Q. Does Modeling consider the cost of carbon allowances in resource 9
dispatch? 10
A. Yes. Aurora dispatches thermal plants for off-system sales of power only when 11
the value exceeds the cost of fuel, variable operation and maintenance costs and projected cost 12
of carbon allowances for power generated in or otherwise imported into Washington State for 13
sale at the Mid-C. 14
Q. How do you reflect carbon allowances in the Aurora modeling? 15
A. The allowance level is based on a forecast of actual emissions from Avista’s 16
existing system portfolio of resources under average water conditions. For each metric ton of 17
carbon, Idaho is responsible for its PT load-ratio share, or 34.47%. CCA carbon allowance 18
compliance is therefore modeled in Aurora such that each thermal plant must overcome in its 19
dispatch the Idaho share of the assumed carbon allowance price, or about $23.87 per metric 20
ton.8 This means plants dispatch to lower customer costs only when their operating costs, 21
including CCA carbon allowance costs, are below the market value of power. 22

8 $69.26/ton average price over 2 rate years * 34.47% P/T ratio (see Schedule 5) = $23.87.

Kalich, Di 12
Avista Corporation
Q. As they reside in the State of Washington, why are emissions from 1
Northeast Combustion Turbine and Kettle Falls Generating Station not modeled? 2
A. Northeast’s operating permit only allows operations for 100 hours per year. It 3
therefore doesn’t reach the compliance threshold of the CCA law (25,000 metric tons or more 4
of annual carbon emissions). Because of this operational limit we do not expect the plant to 5
ever exceed the threshold. Further we do not plan to operate it in the pro forma period since 6
it provides vital contingency reserves for the system, as described later in my testimony. The 7
Kettle Falls facility, including both the biomass and combustion turbine units, like Northeast, 8
does not exceed the 25,000 metric ton annual threshold and therefore is exempt from CCA. 9
Q. You show Washington CCA compliance costs $70.5 million and $84.1 10
million in Rate Years One and Two, respectively. These are substantial new costs. Could 11
these costs be lowered by not generating electricity at these plants or selling the power 12
surplus to Idaho and Washington load at a location other than Mid-C? 13
A. While the cost is large, it is more than recovered by the revenues received from 14
thermal dispatch (i.e., reduced market purchases and increased surplus sales). As stated 15
earlier, resources are not dispatched unless their economics result in a favorable benefit for 16
customers. Reducing dispatch therefore would result in higher power supply costs because 17
the savings from reducing carbon emissions would be more than offset by lost sales revenue. 18
All surplus power is priced at the Mid-C, a market we suspect already has higher prices 19
because of the requirement that any imported power to Washington covers the cost of its 20
emissions. Selling power outside of Washington would therefore result in lower revenues 21
than if sold at Mid-C because it would not include the carbon allowance value in its price. 22
We could attempt to model a new location to sell surplus power outside of 23

Kalich, Di 13
Avista Corporation
Washington, but two critical points make doing so unrealistic. First, no liquid Northwest 1
market exists to replace the Mid-C today. Second, any such market would have lower prices 2
reflecting not having to pay for CCA allowances, and almost certainly would generate lower 3
revenues approximating the lost value of CCA carbon emission allowances. The outcome on 4
power supply modeling would therefore result in the same or higher net power supply 5
expenses. 6
Q. On an overall system basis, what is the value of your thermal plants (net 7
of fuel) as compared to the market? 8
A. In this filing the thermal fleet is estimated to generate $402 million net of fuel 9
costs in Rate Year 1, and $346 million more in Rate Year 2,9 for a total two-year value of 10
$749 million. CCA compliance costs are modeled at $145 million for the two-year period, 11
resulting in approximately $600 million net value of customers, or $300 million a year on 12
average. The electronic version of Kalich Exhibit No. 7 includes the calculations for these 13
amounts.10 14
Q. How does its value compare to the last general rate case before this 15
Commission? 16
A. Our 2021 case did not include the impact of CCA. The value of the thermal 17
fleet for customers in that case was approximately $101 million on a system basis, two-thirds 18
below the average annual margin earned in this case and reflective of today’s higher Mid-C 19
market premiums caused at least in part by CCA emission compliance costs.11 This explains 20

9 See “Conf MTM” sheet in file “Confidential Exhibit No. 7 – Sch 1-5 Final.xlsx” for a tabulation of the current
filing’s fleet (including thermal) values.
10 See “Conf MTM” sheet in file “Confidential Exhibit No. 7 – Sch 1-5 Final.xlsx.”
11 See workpaper “Confidential 2021 ID Kalich Exhibit No. 7, Schedule 1C with MTM.xlsx”, sheet “Conf
MTM.”

Kalich, Di 14
Avista Corporation
Month
Test Year
Load
(aMW)
Weather
Adjustment
(aMW)
Modeled
Load
(aMW)
Sep 921.6 5.4 926.9
Oct 944.8 4.4 949.2
Nov 1,067.9 32.7 1,100.6
Dec 1,243.9 -13.1 1,230.8
Jan 1,272.7 -3.9 1,268.8
Feb 1,187.4 -1.0 1,186.5
Mar 1,069.3 21.9 1,091.2
Apr 1,025.9 -34.2 991.7
May 928.2 -15.8 912.4
Jun 925.9 21.8 947.7
Jul 1,175.3 -89.7 1,085.6
Aug 1,055.1 -8.0 1,047.1
Total 1,068.4 -6.8 1,061.6
that even while paying large CCA premiums the thermal fleet is providing much greater value 1
for Idaho customers in this case than in the previous one. 2
3
IV. OTHER KEY MODELING ASSUMPTIONS 4
Q. Are other key modeling assumptions being made by the Company? 5
A. Yes. We make several additional assumptions affecting loads as well as forced 6
and planned maintenance that drive our modeled pro forma costs. 7
Q. What is the Company’s assumption for rate period loads? 8
A. Consistent with prior GRC proceedings, historical loads are weather adjusted. 9
In this filing, test year loads ending June 30, 2022, average 1,068.4 megawatts. This compares 10
to weather normalized proforma loads of 1,061.6 average megawatts. Table No. 4 below 11
details data included in this proceeding. Please see Company witness Mr. Garbarino’s direct 12
testimony for additional information on the weather normalization. 13
Table No. 4 – Proforma Weather Normalized Loads 14
15
16
17
18
19
20
21
22
23

Kalich, Di 15
Avista Corporation
Forced Outage Rate Maintenance Rate
Facility Proforma 2021 Difference Proforma 2021 Difference
Boulder Park 11.4% 5.8% 5.6% 4.7% n/a 4.7%
Colstrip 7.4% 10.4% -2.9% 7.4% 6.5% 0.9%
Coyote Springs 2 5.0% 2.8% 2.2% 16.5% 7.4% 9.1%
Kettle Falls 3.7% 2.2% 1.5% 3.1% 3.5% -0.4%
Kettle Falls CT 6.2% 2.2% 4.0% 15.2% 13.0% 2.2%
Lancaster 1.4% 2.2% -0.8% 5.3% 5.9% -0.6%
Northeast 0.0% 0.9% -0.9% n/a n/a n/a
Rathdrum 1.9% 4.7% -2.8% 4.8% n/a 4.8%

Q. What are the assumed forced outage and planned maintenance rates for 1
the Company’s thermal generation? 2
A. As with previous cases, the most recent five years’ data is used (through 2021) 3
to calculate average forced and planned outage rates at each plant, except for Colstrip 4
maintenance. For Colstrip, eight years is used to reflect two, four-year maintenance cycles at 5
the plant. We believe it is important to include two full maintenance cycles for this plant, and 6
a single cycle was too short to cover the 5-year period used for other plants. Table No. 5 7
below details forced and maintenance outage rates and compares them to what currently exists 8
in rates. 9
Table No. 5 – Five Year Forced and Maintenance Outage Rates, Proforma 2023 and 10
2021 filings 11
12
13
14
15
16
17
18
Q. Are the Rathdrum and Northeast natural gas-fired plants modeled 19
differently in this case than in the past? 20
A. Yes. Rathdrum and Northeast natural gas-fired plants provide most of Avista’s 21
contingency and other operating reserves. Both are high heat rate facilities, meaning they are 22
not expected to run at high levels over a year and their operating margins are relatively low even 23
when operating. Northeast, even if cost-effective to run relative to market prices, is limited to 24
100 hours per year due to Spokane Regional Clean Air Agency regulation. As such, Northeast 25

Kalich, Di 16
Avista Corporation
is assumed to be set aside exclusively to meet operating reserve requirements, consistent with 1
our last general rate case. 2
Northeast, on a stand-alone basis, is not large enough to meet our contingency and 3
operating reserve requirements in April through July when the hydro system generally has 4
limited capacity to supplement these reserves. As such, one Rathdrum unit is typically set aside 5
during this period, even when market conditions show it to be lower cost than buying power 6
from the market. This assumption change provides a modest benefit relative to our last general 7
rate case where we set aside a Rathdrum unit for the entire year. Lost margins, and therefore 8
overall power supply expenses, are lower in this filing by approximately $0.967 million relative 9
to our last general rate case filing. Table No. 6 below details energy and lost margins resulting 10
from modeling changes in this case. 11
Table No. 6 – Northeast and Rathdrum Reserves Set-Aside Lost Margins 12
13
14
15
16
17
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? 21
A. Avista’s participation in the Western Power Pool Reserves Sharing Agreement 22
requires us to carry three percent each of online generation and load as contingency reserves. 23

Kalich, Di 17
Avista Corporation
Our modeled average pro forma generation of approximately 1,100 megawatts (MW) and 1
average pro forma load of 1,062 MW necessitate approximately 70 MW of average contingency 2
reserves. 3
The amount of additional operating reserves are a bit more arbitrary than contingency 4
reserves, as they are not defined by agreement. Yet standard industry (and prudent) practice 5
dictates that utilities should prepare for losing their largest single generator – both with capacity 6
and fuel. For Avista, depending on system conditions, our largest operating generator could be 7
a smaller hydro 75 to 150 MW unit at our Clark Fork Project, or it could be one of our large 8
natural gas plants like Coyote Springs 2, generating up to 300 MW or more. 9
Together, contingency and other reserves range between 74.5 and 405 MW, with an 10
average of 325.3 MW. The combination of Northeast and a single unit at Rathdrum approximate 11
the minimum range and well below the average. We generally supplement Northeast and 12
Rathdrum with hydro unit capability ensuring adequate reserves are held in operations. 13
Q. Please describe any material changes to power contracts since the 2021 14
filing and the impacts on power costs. 15
A. Avista updates all contracts over the pro forma term to account for expiring 16
and new contracts. Table No. 7 below lists all the long-term contracts with material changes 17
in rate year one.12 18

12 Please note this table is intended to illustrate changes to long-term contracts. As such, table will not tie to the
total for 555 Purchase Power in Adjustment 3.00 Power Supply Adjustment.

Kalich, Di 18
Avista Corporation
Table No. 7 – Wholesale Contract Changes 1
2
3
4
5
6
7
Our new Chelan County Public Utilities District contract, as described in detail by 8
Company witness Mr. Kinney, meets a portion of the renewable resource need identified in 9
Avista’s 2020 Integrated Resource Plan. The contract provides an additional 5% slice of 10
Chelan’s Rocky Reach and Rock Island hydro projects starting January 1, 2024. 11
Our contract with Grant County Public Utilities District for an approximate three 12
percent share of its Priest Rapids project has not changed materially from the previous rate 13
case, but its cost is measurably higher. This contract’s price is determined annually based on 14
an auction process held annually by Grant. The auction results in a price reflecting current 15
market prices which have increased significant in recent years. The 2021 monthly contract 16
amounts for the period September 2021 to August 2022 are used to estimate pro forma period 17
deliveries.13 18
Our capacity exchange with Douglas County Public Utility District expires after 19
December 31, 2023. The parties are exploring a renewal of this contract but are far apart on 20
price and did not reach agreement in time for inclusion in our filing. We therefore have 21

13 The 2022 rates from Grant County PUD were provided to the Company after the preparation of this rate case
and therefore, weren’t incorporated into the modeling of this case. These updates will be incorporated when the
Company updates costs prior to rates going into effect.
Line
No.2023 aMW 2021 aMW Change
1 Chelan PUD 92.9 53.5 39.4
2 Grant PUD 38.1 38.5 (0.5)
3 Douglas Exchange (4.6) (2.8) (1.8)
4 Douglas PUD 14.3 11.0 3.2
5 Columbia Basin Hydro 2.4 - 2.4
6 Lancaster
7 Other 12.8 14.1 (1.3)
Total Contracts 155.8 114.4 41.4
Contracts

Kalich, Di 19
Avista Corporation
eliminated this contract from the pro forma after 2023. If this situation changes during the 1
pendency of the case, Avista will update accordingly. 2
Besides the exchange, Avista separately contracts with Douglas for approximately 3% 3
of its Wells Dam output. This contract includes a fixed-price capacity charge, as well as an 4
agreed-upon energy charge, both changing annually. 5
A new contract with Columbia Basin Hydro Power executed in December 2022 6
provides new hydro capacity and energy for Avista. As a product of irrigation operations, the 7
generation profile meets Avista’s increasing summer load requirements. While only the 8
Russell D. Smith, E.B.C. 4.6, Summer Falls Development and P.E.C 66.0 Development 9
projects contribute during the pro forma period, the list below contains all projects. 10
• March 1, 2023, for the Russell D. Smith (P.E.C. 22.7) Development – 6.1 MW 11
• May 1, 2023, for the E.B.C. 4.6 Development – 2.2 MW 12
• January 1, 2025, for the Summer Falls Development – 92 MW 13
• March 1, 2025, for the P.E.C. 66.0 Development – 2.4 MW 14
• October 1, 2025, for the Quincy Chute Development – 9.4 MW 15
• January 1, 2027, for the Main Canal Development – 26 MW 16
• September 1, 2030, for the P.E.C. Headworks Development – 6 MW 17
18
The Columbia Basin Hydro (CBH) contract was evaluated as part of Avista’ 2022 19
Request for Proposals (RFP) process. A full accounting and reporting for CBH will be 20
sponsored in testimony in our next Idaho general rate case, once all resources procured as part 21
of the RFP process are under contract. 22
There is no material change in the Lancaster contract during the pro forma period. Its 23
increase from the 2021 case is a function of annual price appreciation agreed to in the original 24
contract. 25
Q. What contracts are included in the “Other” line item in Table No. 7 26
above? 27

Kalich, Di 20
Avista Corporation
A. The Other category in Table No. 7 is comprised of several small PURPA 1
contracts, as well as three larger PURPA contracts. The primary increase in the category since 2
the 2021 case relates to renewal of three contracts: Stimson Lumber, City of Spokane Upriver 3
Dam, and City of Spokane Waste-to-Energy Facility. 4
Q. Are there contracts not included in the Model? 5
A. Yes. The mark-to-market value of all forward natural gas and power positions 6
with contract durations falling within the pro forma period have been included, but outside of 7
Aurora production cost modeling. 8
Q. Are the Palouse and Rattlesnake Wind Farms included in the proforma? 9
A. No. Consistent with recent Commission orders Avista has not included these 10
facilities in the pro forma power supply adjustment. The impacts of these resources will flow 11
to customers as presently occurs via the PCA. 12
Q. How is the Adams-Neilson Solar project treated in this filing? 13
A. This facility serves our Washington State Solar Select program. Self-electing 14
customers consume its entire output to serve their retail loads. In the Model we show the 15
Adams-Neilson resource and an offsetting sale at its contract price, thereby netting to its 16
impact on power supply expense to zero. 17
Q. How is the Company proposing that California EIM benefits be included 18
in pro forma power expenses? 19
A. Avista is not including EIM benefits in the pro forma, as we began participating 20
in the EIM only this past March 1, 2022, and increased operating experience is necessary to 21
fairly determine an EIM value for the proforma. In our 2021 general rate case, the Parties 22
agreed, and the Commission approved, to track EIM expenses associated, beginning at “go-23

Kalich, Di 21
Avista Corporation
live” March 1, 2022, up to the benefits received. Any expenses above this amount are deferred 1
and subject to prudency determination later. To this point expenses have not exceeded 2
benefits for any period. The Company filed a compliance filing as required in Order No. 3
35606 in the 2022 PCA Annual Filing, in October 2022 that documented the calculations 4
associated with the benefit determination. Avista proposes to continue this process until such 5
time as enough historical information is available to make an informed decision as to 6
alternative methods for tracking. Therefore, revenues above expenses will therefore pass 7
through the PCA. 8
9
V. MODELING RESULTS 10
Q. Please summarize the results from power supply modeling. 11
A. The Model tracks our portfolio during each hour of the pro forma study. Many 12
of the modeling results are shared earlier in my testimony. Overall fuel costs and generation 13
for each resource are calculated and summarized in Confidential Exhibit No. 7, Confidential 14
Schedules 1 and 2. Market sales and purchases, and their revenues and costs, are determined 15
as well and shown in Table No. 8 below, on a system basis: 16

Kalich, Di 22
Avista Corporation
Item RY1 RY2 2021 GRC RY1 Delta RY2 Delta
aMW aMW aMW aMW aMW
Market Purchases 11.3 6.3 13.0 (1.7)(6.7)
Market Sales (285.0)(327.5)(300.0)15.0 (27.5)
Net (273.6)(321.2)(287.0)13.4 (34.2)
$/MWh $/MWh $/MWh $/MWh $/MWh
Market Purchases $48.15 $42.01 $28.12 $20.03 $13.89
Market Sales ($82.57)($74.89)($30.54)($52.03)($44.35)
Net ($77.59)($72.69)($28.11)($49.48)($44.58)
($000)($000)($000)($000)($000)
Market Purchases 4,781 2,315 3,201 1,580 (885)
Market Sales (206,685)(214,869)(80,255)(126,430)(134,614)
Net (201,904)(212,554)(77,055)(124,850)(135,499)
Table No. 8 – System Balancing Sales & Purchases 1
2
3
4
5
6
7
8
9
Market transactions, combined with other resource and contract revenues and 10
expenses not accounted for directly in the Model (e.g., fixed costs), determine the net power 11
supply expense. 12
13
VI. OVERVIEW OF PRO FORMA POWER SUPPLY ADJUSTMENT 14
Q. Please provide an overview of the pro forma power supply adjustment. 15
A. The pro forma power supply adjustment determines revenues and expenses 16
associated with dispatch of Company resources and contract rights, as determined by the 17
Model’s simulation for the pro forma rate period under normal weather and median hydro 18
generation conditions. Further adjustments are made to reflect contract changes between the 19
historical test period and the pro forma period. Table No. 9 below shows total net power 20
supply expense during the test period and the pro forma period. For information purposes 21
only, the power supply expense currently in base retail rates, based on a test year ending June 22

Kalich, Di 23
Avista Corporation
30, 2022 versus the pro forma period, is shown.14 1
Table No. 9 – Rate Year 1 Net Power Supply Expense (System and Idaho-Share) 2
3
4
5
6
7
8
9
10
The net effect of adjustments to the test year power supply expense is a decrease in 11
2023-2024 of $2.030 million ($181.060 million - $179.012 million) on a system basis and a 12
decrease of $0.70 million Idaho allocation.15 This value is provided to Company witness Ms. 13
Schultz for her testimony. Overall, however, the increase in net power supply expense, as 14
compared to what is authorized in current base rates, is $29.751 million, or $10.255 million 15
Idaho share for Rate Year 1. The increase in net power supply expense in Rate Year 2 is 16
$13.208 million ($192.238 million - $179.030 million), or $4.553 million Idaho share, as 17
shown in Table No. 10 below: 18

14 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.
15 Assumes 2021 Production/Transmission (P/T) ratio of 65.53% / 34.47% for Washington / Idaho.
Measure
RY 1
System(1)
Idaho
Allocation (2)
($000s)($000s)
Current Authorized Power Supply Expense effective 10/1/21 149,279$ 51,456$
Actual 12ME 6/30/22 Test Period Power Supply Expense 181,060$ 62,412$
Proposed 2023-2024 Pro Forma Power Supply Expense 179,030$ 61,712$
Proposed 2023-2024 Expense versus 12ME 6/30/22 Test Period (2,030)$ (700)$
Proposed 2023-2024 Expense Change from Current Authorized 29,751$ 10,255$
(2) Allocated based on ROO Current Production/Transmission Ratio of 34.47%
(3) Adjusted for current weather normalized loads.
(1) Excludes Transmission - see Company witness Mr. Dillon and Adjustment 3.00T. Includes load and settlement
adjustment.

Kalich, Di 24
Avista Corporation
Measure
RY 2
System(1)
Idaho
Allocation (2)
($000s)($000s)
Proposed 2024-2025 Pro Forma Power Supply Expense 192,238$ 66,265$
Less: Proposed 2023-2024 Pro Forma Power Supply Expense 179,030$ 61,712$
Net Increase in Net Power Supply Expense 13,208$ 4,553$
(2) Allocated based on ROO Current Production/Transmission Ratio of 34.47%
(3) Adjusted for current weather normalized loads.
(1) Excludes Transmission - see Company Witness Mr. Dillon and adjustment 3.00T. Includes load and settlement
adjustment.
Table No. 10 – Rate Year 2 Net Power Supply Expense (System and Idaho-Share) 1
2
3
4
5
6
7
8
VII. PRO FORMA POWER SUPPLY ADJUSTMENT 9
Q. Please identify specific power supply cost items not already covered in 10
your testimony and the total adjustments being proposed. 11
A. Confidential Exhibit No. 7, Schedule 2 identifies non-Model power supply 12
expense and revenue items. These relate to power purchases and sales, fuel expenses, 13
transmission expenses, and other miscellaneous power supply expenses and revenues. 14
Q. What is the basis for the adjustments to the test period power supply 15
revenues and expenses? 16
A. The purpose of test period adjustments is normalization of power supply 17
expenses for expected (i.e., average) weather and median hydroelectricity generation, to 18
reflect current forward natural gas prices, and include other known and measurable changes 19
for the pro forma period. 20
Q. Please describe each adjustment. 21
A. Confidential Exhibit No. 7, Schedule 3 provides a brief description of each 22
adjustment line item of the pro forma. Detailed work papers demonstrate actual and pro forma 23

Kalich, Di 25
Avista Corporation
revenues and expenses. 1
Q. How are long-term power contracts included in the pro forma? 2
A. The Model tabulates the value of all long-term physical power contracts within. 3
Q. How are term transactions accounted for in the pro forma? 4
A. The Company’s Risk Management Policy, sponsored by Mr. Kinney within 5
Exhibit No. 6, Schedule 2C, allows the Company to enter term transactions lessening power 6
supply expense volatility. Our Risk Management Policy enables term transactions out as far 7
as three years. The Company takes power and natural gas positions into the future, using both 8
physical and financial arrangements, in the forward markets; many of these transactions can 9
fall within the pro forma period. 10
Where some or all of a physical or financial contract term exists within the pro forma 11
period, its costs are included in the Model.16 Financial contracts only affect power supply 12
expenses based on the difference between their price and the market value of power. Physical 13
contracts also account for expected energy deliveries by increasing (for sales) or decreasing 14
(for purchases) our net load obligations. 15
The Model in its current instance cannot value natural gas contracts. They are instead 16
valued outside of the model at their delivery basin. The valuation uses the same natural gas 17
price as used in the Model. The pro forma value of our natural gas purchases may be found 18
in my work papers.17 19
Q. How are thermal fuel expenses for non-natural gas resources determined 20
in the pro forma? 21

16 Financial contracts include only costs in the Model. Physical contracts include both costs and delivered energy.
17 See Kalich electronic workpapers, tab ‘Conf Fuel Costs’ of spreadsheet “Confidential Exhibit No. 7 -
Schedules 1C-5.xlsx.”

Kalich, Di 26
Avista Corporation
A. Non-gas fuel is procured for Colstrip (coal) and the Kettle Falls Generating 1
Station (wood waste). In its fuel supply contract, the coal price for Colstrip is dependent on 2
the volume purchased each year. Pro forma period consumption levels are used to define the 3
contract fuel price; the calculation is provided in workpapers.18 After the Model dispatches 4
the plant, our coal supply contract prices are applied to that dispatch. 5
Hog fuel (i.e., waste wood) fuel prices at the Kettle Falls Generating Station are based 6
on multiple contracts we have with fuel suppliers supporting our existing inventory. Its fuel 7
price is determined in an approach like Colstrip. Expected Model dispatch is priced using 8
budgeted prices from our fuel supply contracts. Fuel cost calculations for the Kettle Falls 9
Generation Station are in my workpapers.19 10
Q. What changes in transmission expense are in the pro forma compared to 11
the test-year and the expense in current base rates? 12
A. Firm transmission contracts are required to deliver power from generation to 13
loads and markets, deliver power from markets to load, meet resource adequacy requirements 14
and ensure reliability requirements for the electric system. In addition to Company-owned 15
point to point or network transmission, the Company has long-term transmission contracts 16
and network transmission rights primarily with Bonneville Power Administration. Bonneville 17
Power Administration transmission costs included in the pro forma reflect current contract 18
pricing from its general rate case TC-2021. We believe there will be no transmission price 19
changes for years 2023 and 2024. The Company has updated the transmission pro forma 20
expense to reflect additional transmission for our new Columbia Basin Hydro contracts. 21
Finally, Network Transmission expense (also called “borderline wheeling”) is based on a five-22

18 See worksheet “Conf Colstrip Fuel Model” in the spreadsheet version of my Exhibit No. 7.
19 See worksheet see “Kettle and Colstrip Fuel 2017-2021.xlsx”.

Kalich, Di 27
Avista Corporation
year use average priced at current rates. 1
Q. Please explain how natural gas transportation contracts are included in 2
the pro forma. 3
A. The value of our firm natural gas transportation contracts from AECO to our 4
power plants are discussed earlier in my testimony. Contracted costs for the two-year rate 5
period are included in the pro forma. 6
Q. Please summarize your proposed pro forma power supply expense that is 7
provided to Ms. Schultz for the Company’s electric Pro Forma Study. 8
A. The net effect of my adjustments to the test year power supply expense is a 9
decrease in 2023-24 of $2.030 million ($181.060 million - $179.030 million) on a system 10
basis, and a $0.70 million Idaho allocation. Overall, however, the increase in net power supply 11
expense in 2023-24, as compared to what is authorized in current base rates, is $10.255 million 12
(Idaho share). The increase in net power supply expense in 2024-25 is $4.553 million (Idaho 13
share).20 14
VIII. PCA AUTHORIZED VALUES 15
Q. What is Avista’s proposed authorized power supply expense and revenue 16
for the PCA? 17
A. The proposed authorized level of annual system net power supply expense and 18
revenues is $179.0 million for the pro forma. This is the sum of FERC Accounts 555 19
(Purchased Power), 557 (Other Expenses), 501 (Thermal Fuel), 547 (Fuel), 565 (Transmission 20
of Electricity by Others, 537 (Montana Invasive Species), less Account 447 (Sale for Resale) 21

20 In addition to the proposed pro forma net power supply revenue and expense amounts discussed above and
included by Ms. Schultz within PF Adjustment 3.00P, PF Adjustment 3.00P also includes generation O&M
expenses of $121,000 related to the Western Regional Adequacy Program (“WRAP”), as discussed and
supported by Mr. Kinney.

Kalich, Di 28
Avista Corporation
and 456 (Other Electric Revenue). It also includes transmission revenue discussed by 1
Company witness Mr. Dillon. 2
Q. What is the level of retail sales and the proposed Load Change Adjustment 3
Rate for the PCA over the Two-Year Rate Plan? 4
A. The proposed authorized level of retail sales to be used in the PCA is year 5
ending June 30, 2022 weather adjusted Idaho retail sales. The proposed Load Change 6
Adjustment Rate, which is the energy related portion of the average production and 7
transmission cost, is $25.23/MWh for Rate Year 1, pro forma period September 1, 2023-8
August 31, 2024. For Rate Year 2, the proposed Load Change Adjustment Rate is 9
$26.54/MWh, which includes the impact of production and transmission costs for Rate Year 10
2 as pro formed by Ms. Schultz. 11
The proposed authorized PCA power supply expense and revenue, transmission 12
expense and revenue, REC revenues, Load Change Adjustment Rate and retail sales over the 13
Two-Year Rate Plan are shown in Exhibit No. 7, Schedule 5. 14
Q. Does this conclude your pre-filed direct testimony? 15
A. Yes, it does. 16