20210129Thackston 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]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-21-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-21-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND ) DIRECT TESTIMONY
NATURAL GAS SERVICE TO ELECTRIC ) OF
AND NATURAL GAS CUSTOMERS IN THE ) JASON R. THACKSTON
STATE OF IDAHO )
)

FOR AVISTA CORPORATION

(ELECTRIC AND NATURAL GAS)

Thackston, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, employer and business address. 2
A. My name is Jason R. Thackston. I am employed as the Senior Vice President 3
of Energy Resources and Environmental Compliance Officer at Avista Corporation, located 4
at 1411 East Mission Avenue, Spokane, Washington. 5
Q. Would you briefly describe your educational and professional 6
background? 7
A. Yes. I graduated from Whitworth University in 1992 with a Bachelor of Arts 8
in International Studies and an emphasis in Business Management and a Master of Business 9
Administration from Gonzaga University in 2000. I joined the Company in 1996 as a 10
Corporate Treasury Analyst. I have held several different positions at Avista, including roles 11
in Finance and Accounting, Internal Audit, Risk Management, Power Supply, and Gas 12
Supply. I was appointed Vice President of Finance in June 2009 and have since held the roles 13
of Vice President of Energy Delivery and Vice President of Customer Solutions before 14
assuming my current role in January 2013. The Energy Resources group is primarily 15
responsible for producing or procuring the electricity and natural gas to serve our customers’ 16
needs, including the construction, operation, and maintenance of our generation facilities and 17
the optimization of those electric and natural gas facilities for the benefit of our customers. 18
The Energy Resources group also includes environmental affairs, including compliance with, 19
and management of, the licenses issued by the Federal Energy Regulatory Commission 20
authorizing the Company to operate its hydroelectric facilities. 21
Q. What is the scope of your testimony in this proceeding? 22
A. My testimony provides an overview of the Company’s 100% Clean Electricity 23

Thackston, Di 2
Avista Corporation
goal by 2045, carbon neutral electricity supply by the end of 2027, and why it is important to 1
our Company. I will also provide an overview of Avista’s resource planning and power supply 2
operations. This overview includes summaries of the Company’s current and future resource 3
plans, as well as an overview of the Company’s Energy Resources Risk Policy. I will address 4
the generation-related capital projects included in the Company’s Two-Year Rate Plan filed 5
in this case, including capital additions associated with the Company’s investment in Colstrip 6
Unit Nos. 3 and 4 for the periods 2020 through August 2023. My testimony will conclude 7
with a discussion of the Rattlesnake Flat Wind Power Purchase Agreement. 8
A table of contents for my testimony is as follows: 9
Description Page 10
I. Introduction 1 11
II. Clean Electricity and Natural Gas Goals 3 12
III. Resource Planning and Power Operations 6 13
IV. Overview of 2020 – 2023 Non-Colstrip Generating Projects 11 14
V. Colstrip Generating Capital Projects 29 15
VI. Rattlesnake Flat Wind Power Purchase Agreement 56 16
17
Q. Are you sponsoring any exhibits? 18
A. Yes. I am sponsoring Exhibit No. 7, Schedules 1 – 9. Exhibit No. 7, Schedule 19
1 is Avista’s 2020 Electric Integrated Resource Plan and Appendices. Exhibit No. 7, Schedule 20
2C is Avista’s Energy Resources Risk Policy. Exhibit No. 7, Schedule 3 contains Avista 21
Utilities Generation Infrastructure Plan. Exhibit No. 7, Schedule 4 includes the capital 22
business cases for the generation capital projects discussed later in my testimony. Exhibit No. 23
7, Schedule 5 provides additional documentation about the capital projects at Colstrip. Exhibit 24
No. 7, Schedule 6C contains the 2018 Renewable RFP Report and Documentation. Exhibit 25
No. 7, Schedule 7C includes the Rattlesnake Wind Power Purchase Agreement and Exhibit 26

Thackston, Di 3
Avista Corporation
No. 7, Schedule 8C includes the Board documentation concerning the Rattlesnake Flat Wind 1
Power Purchase Agreement, and Exhibit No. 7, Schedule 9 includes the 2017 IRP. 2
3
II. CLEAN ELECTRICITY AND NATURAL GAS GOALS 4
Q. Would you provide an update to the Company’s 100% clean electricity 5
goal by 2045, and carbon neutral electricity supply by the end of 2027? 6
A. Yes, the announcement made by Avista in April 2019 bolsters our long-7
standing history of, and well-established approach to, providing clean, reliable and affordable 8
energy to the customers and communities we serve. We believe that the 100 percent clean 9
electricity goal is an important step forward in caring for our environment while continuing 10
to meet the energy needs of our customers and communities today and well into the 11
future. Since Avista’s founding on clean, renewable hydro power in 1889, we’ve served our 12
customers with an electric generation resource mix that is more than half renewable, allowing 13
us to keep our carbon emissions among the lowest in the nation. 14
Further, the Company has always been committed to balancing reliability and 15
affordability while maintaining responsibility for our environmental footprint, and our actions 16
demonstrate these values. Just in the last five years, we’ve implemented three renewable 17
energy projects on behalf of our customers. Our Community Solar project in Spokane Valley, 18
Solar Select project in Lind, and the Rattlesnake Flat Wind project in Adams County, 19
discussed later in my testimony, together have allowed us to add to the clean electricity we 20
already provide, meet the energy needs of our customers without increasing their bills and 21
drive economic vitality in these communities. 22
Q. Why did Avista declare an electric carbon neutral? 23

Thackston, Di 4
Avista Corporation
A. We have seen a growing focus on clean electricity generation at the national, 1
regional, and local levels. Our customers, communities and governments of all levels 2
increasingly express an interest in knowing how Avista is positioned on this topic. While we 3
have a strong and long track record related to clean electric generation, we felt it was time to 4
be clear about our path forward for all of our customers in Idaho, not just those we serve in 5
Washington. Reaching this goal, of course, will require further improvements in technology 6
and a reduction in their associated cost of clean electric generation and energy storage, as well 7
as regulatory support. Going forward, we will track progress through our Integrated Resource 8
Plan. 9
Q. What does carbon neutral mean and what percent of Avista’s load is 10
actually served with renewables? 11
A. Carbon neutral means achieving an overall net-carbon footprint by meeting our 12
customers’ annual electric needs through either utilizing non-carbon emitting resources or 13
investing in or acquiring carbon offsets to net-out emissions created from carbon emitting 14
resources. An example of a carbon offset is acquiring renewable energy credits from a 15
renewable energy resource. Currently, over 60 percent of Avista’s customers’ annual electric 16
need is already served from clean, non-carbon emitting resources. 17
Q. What is the impact of this clean energy goal on Colstrip? 18
A. Colstrip has been an important source of generation in the region and for 19
Avista’s customers for over 35 years. It is available to serve our customers when the wind 20
isn’t blowing, the sun isn’t shining, or there isn’t enough water flowing down the rivers to 21
generate enough electricity to meet our customers’ energy needs. Colstrip will no longer be 22
used to serve Washington customers after 2025 to comply with CETA. As described below 23

Thackston, Di 5
Avista Corporation
in the IRP section of my testimony, modeling for the 2020 IRP indicated that Colstrip will 1
also no longer be economically beneficial to serve Idaho customers after 2025 as well. 2
However, it is important to note that the Company will continue to have a contractual 3
obligation to pay for past, ongoing, and future costs associated with the generation of this 4
output based on the joint ownership agreement. We continue to work with our five co-owners 5
related to the future operation of Colstrip Units 3 and 4. 6
Q. How does natural gas fit with the Company’s clean energy goal? 7
A. Natural gas has been a key energy choice for Avista’s customers for nearly 70 8
years. It is an affordable and less expensive heating option for customers, especially for many 9
large commercial and industrial customers who rely on it to run their business, provide jobs 10
for their employees and serve their communities. Natural gas is one of the cleanest burning 11
fuels and is an essential part of reducing carbon emissions, particularly when used directly by 12
customers in their homes rather than used to generate electricity to meet the same need. 13
Compared to wood, heating oil and other fuels, natural gas improves air quality. Additionally, 14
the use of compressed natural gas (CNG) to fuel vehicles reduces carb on emissions in the 15
transportation sector, which is a leading contributor of emissions. Avista consistently engages 16
customers to educate them about natural gas efficiency and offers natural gas energy 17
efficiency programs that also support lower emissions. In short, direct use of natural gas is 18
efficient, creates less environmental impact than other fuels, and is an affordable option for 19
customers. 20
Even though natural gas creates less environmental impact than other fuels, the 21
Company recognizes the opportunity to implement strategies that will further improve its 22
environmental impact by reducing the carbon emissions associated with the direct use of 23

Thackston, Di 6
Avista Corporation
natural gas. Examples of carbon emissions reduction strategies include the following: 1
• Diversify or transition from fossil fuel-based natural gas to renewable natural gas; 2
• Reduce natural gas consumption via conservation, energy efficiency and new 3
technologies; and 4
• Purchase carbon offsets as necessary. 5
6
Achieving carbon emission reductions for the natural gas system will involve various 7
pathways. The initial primary pathways include renewable natural gas (RNG), energy 8
efficiency, customer voluntary RNG and carbon offset programs. 9
Q. How does energy efficiency play a role in this clean energy plan? 10
A. Energy efficiency has been an important piece of our energy resource puzzle 11
for over 40 years, and we will continue to partner with our customers to use electricity and 12
natural gas more efficiently through our own customer education, outreach and economic 13
incentive programs, as well as regionally through participation in the Northwest Energy 14
Efficiency Alliance. Energy efficiency continues to be an effective option to lower customers’ 15
energy use, reduce our need to build additional generation, and further reduce the carbon 16
intensity of our local economy. 17
18
III. RESOURCE PLANNING AND POWER OPERATIONS 19
Q. Would you please provide a summary of Avista's power supply operations 20
and acquisition of new resources? 21
A. Yes. Avista uses a combination of owned and contracted-for resources to serve 22
its load requirements. The Power Supply Department (Power Supply) is responsible for 23
dispatch decisions related to those resources for which the Company has dispatch rights. 24
Power Supply monitors and routinely studies capacity and energy resource needs. Short-and 25

Thackston, Di 7
Avista Corporation
medium-term wholesale transactions are used to economically balance resources with load 1
requirements. The Integrated Resource Plan (IRP) generally guides longer-term resource 2
decisions such as the acquisition of new generation resources, upgrades to existing resources, 3
demand-side management (DSM), demand response, energy storage, and long-term contract 4
purchases. Resource acquisitions typically include a Request for Proposals (RFP) and/or other 5
market due diligence processes. 6
Q. Please summarize Avista’s load and resource position. 7
A. Avista’s 2020 IRP shows forecasted annual energy and capacity deficits 8
beginning in 2026. The deficits are a result of the expiration of the Lancaster power purchase 9
agreement and the expected elimination of Colstrip from the Company’s resource portfolio. 10
The capacity and energy load/resource positions are shown on pages 7-4 and 7-5 of Exhibit 11
No. 7, Schedule 1. The 2021 Electric IRP is currently being developed, the draft IRP was 12
released on January 4, 2021 for public comment and is scheduled to be filed with the 13
Commission on April 1, 2021. 14
Q. How does Avista plan to meet future energy and capacity needs? 15
A. The Preferred Resource Strategy (PRS) in the 2020 Electric IRP guides the 16
Company’s resource acquisitions, subject to any additional legislative or regulatory 17
requirements. The IRP provides details about future resource needs, specific resource costs, 18
resource-operating characteristics, and scenarios used for evaluating the mix and timing of 19
resources included in the PRS. The IRP represents the preferred plan at a point in time; 20
however, Avista continuously evaluates different resource options to meet current a nd future 21
load obligations, especially in light of new legislation and market opportunities. Avista’s 22
2020 IRP included as Exhibit No. 7, Schedule 1, was filed with the Commission on February 23

Thackston, Di 8
Avista Corporation
Resource Type Year Capability (MW)
Montana wind 2022 100
NW wind 2022-2023 200
Kettle Falls upgrade 2026 12
Colstrip 3 & 4 exits portfolio 2026 -222
Rathdrum CT 1 & 2 upgrades 2026 24
Long-duration pumped hydro 2026 175
Lancaster PPA expires 2026 -257
Post Falls upgrade 2027 8
Montana wind 2027 200
Mid-Columbia hydro 2031 75
Northeast CTs retires 2035 -55
Long Lake 2nd powerhouse 2035 68
Liquid-air storage (16 hours) 2036-2041 100
Wind (including PPA renewals) 2041-2043 300
Lithium-ion storage (4 hour) 2042-2045 300
Solar w/ storage (4 hours) 2044 55
4-hr Storage for Solar 2044 50

Supply-side resource net total (MW) 1,133
Supply-side additions through 2045 (MW) 1,667
Demand Response through 2045 (MW) 112
Energy Efficiency through 2045 (aMW) 187

28, 2020 in Case No. AVU-E-19-01 and acknowledged in Order No. 34814. 1
Avista’s 2020 PRS includes 1,133 MW of net supply-side resources which includes 2
the addition of 1,667 MWs of new wind, pumped hydro, battery storage, solar and plant 3
upgrades as well as the loss of 534 MWs of coal and natural gas-fired resources from the 4
Company’s resource portfolio. The PRS also includes 112 MW of demand response and 187 5
aMW of new energy efficiency through 2045. The timing and type of these resources included 6
in the PRS for the 2020 IRP are provided in Table No. 1 below. 7
Table No. 1: 2020 Electric IRP Preferred Resource Strategy 8
9
10
11
12
13
14
15
16
17
18
Q. What are some of the major changes in the draft 2021 IRP from the 2020 19
IRP? 20
A. The major changes in the draft 2021 IRP include changes in the following 21
areas: capacity and energy position, energy efficiency and demand response, supply -side 22
resource options, market analysis and the portfolio optimization analysis. Capacity and 23

Thackston, Di 9
Avista Corporation
energy position changes include an increase in the summer planning margin from 14 percent 1
to 16 percent, an increase in market availability from 250 MW to 330 MW for the 5 percent 2
Loss of Load Probability analysis, and assumed retirements of the Northeast Combustion 3
Turbine in 2035 and Boulder Park in 2040. The energy efficiency and demand response 4
changes include the Utility Cost Test for Idaho program selection, a social cost of carbon for 5
Washington customers only, and the inclusion of estimated energy savings from demand 6
response programs in the portfolio analysis. The supply-side resource option changes include 7
several new resource types being modeled such as several different energy storage options 8
and hydrogen fuel cells and turbines, the use of levelized rather than annual energy and 9
capacity costs, as well as several changes to the modeling of the social cost of carbon . The 10
major market analysis changes include the use of the Aurora supplied database for most non-11
Avista inputs; the use of the Aurora capacity expansion logic for meeting clean energy 12
policies; and a new natural gas price forecast using blended forwards, price forecasts from 13
two consulting firms and the Energy Information Administration. Finally, the portfolio 14
optimization analysis changes include a 24-year resource portfolio from 2022 to 2045 and 15
portfolio optimization that allows selection of resources for either state or for the system. All 16
of the major changes are described in greater detail in the 2021 draft IRP. 17
Q. Would you please provide a high-level summary of Avista’s risk 18
management program for energy resources? 19
A. Yes. Avista Utilities uses several techniques to manage the risks associated 20
with serving customers and managing Company-owned and controlled resources. The Energy 21
Resources Risk Policy, which is attached as Exhibit No. 7, Schedule 2C, provides general 22
guidance to manage the Company’s energy risk exposure relating to electric power and natural 23

Thackston, Di 10
Avista Corporation
gas resources over the long-term (more than 41 months), the short-term (monthly and 1
quarterly periods up to approximately 41 months), and the immediate term (present month). 2
The Energy Resources Risk Policy is not a specific procurement plan for buying or 3
selling power or natural gas at any particular time, but is a guideline used by management 4
when making procurement decisions for electric power and natural gas as fuel for electric 5
generation. The policy considers several factors, including the variability associated with 6
loads, hydroelectric generation, planned and forced outages, and electric power and natural 7
gas prices in the decision-making process. 8
Avista aims to develop or acquire long-term energy resources based on the current 9
IRP’s Preferred Resource Strategy, while taking advantage of competitive opportunities to 10
satisfy electric resource supply needs in the long-term. Electric power and natural gas fuel 11
transactions in the immediate term are driven by a combination of factors that incorporate 12
both economics and operations, including near-term market conditions (price and liquidity), 13
generation economics, project license requirements, load and ge neration variability and 14
availability, reliability considerations, and other near-term operational factors. 15
For the short-term timeframe, the Company’s Energy Resources Risk Policy guides 16
its approach to hedging financially-open forward positions. A financially-open forward 17
period position may be the result of either a short position situation, for which the Company 18
has not yet purchased the fixed-price fuel to generate, or alternatively has not purchased fixed-19
price electric power from the market, to meet projected average load for the forward period. 20
Or it may be a long position, for which Avista has generation above its expected average load 21
needs, and has not yet made a fixed-price sale of that surplus to the market in order to balance 22
resources and loads. 23

Thackston, Di 11
Avista Corporation
The Company employs an Electric Hedging Plan to guide power supply position 1
management in the short-term period. The Risk Policy Electric Hedging Plan is essentially a 2
price diversification approach employing a layering strategy for forward purchases and sales 3
of either natural gas fuel for generation or electric power in order to approach a generally 4
balanced financial position against expected load as forward periods draw nearer. 5
Q. Would you please provide an update concerning Avista’s involvement 6
with the Western Energy Imbalance Market? 7
A. Yes, as previously discussed with the Commission, Avista has chosen to 8
participate in the CAISO Western Energy Imbalance Market (EIM) beginning in March 2022. 9
Company witness Mr. Kinney provides details about Avista’s participation in the EIM and the 10
expenses required for joining and participating in the EIM. 11
12
IV. OVERVIEW OF 2020 – AUGUST 2023 13
NON-COLSTRIP GENERATION CAPITAL PROJECTS 14
15
Q. Please discuss the capital investments you sponsor included in the 16
Company’s Two-Year Rate Plan. 17
A. As discussed by Company witnesses Ms. Schultz and Ms. Andrews, Avista’s 18
capital witnesses, including myself, describe the capital projects included in the Company’s 19
proposed Two-Year Rate Plan, reflecting pro forma capital additions for the period between 20
January 1, 2020 and August 31, 2023. For the generation projects, my testimony and Exhibit 21
No. 7, Schedules 3 and 4 provide an overview of the need for the investments made and detail 22
how those projects benefit our customers. 23
Q. Please describe the capital planning process that Generation Production 24

Thackston, Di 12
Avista Corporation
and Substation Support conducts before generation capital projects are submitted to the 1
Capital Planning Group (described by Company witness Mr. Thies). 2
A. The capital planning process in Generation Production and Substation Support 3
(GPSS) consists of a long-range forecast, a five-year forecast, and an execution 4
plan. Descriptions of each phase of the planning process follow. The Company’s long-range 5
forecasting uses the Maximo enterprise asset management software as the central repository 6
for projects and their associated elements. Projects can be added to the long-range forecast 7
database in several ways: 8
• Informal project requests; 9
• Input from asset life cycle, condition, needs assessment; 10
• Periodic reports from Maximo of open corrective maintenance work orders; 11
• Periodic reports from Maximo of scheduled preventive maintenance work orders; 12
• Annual maintenance requirements; 13
• Regulatory mandates; 14
• Project change requests, drop ins, budget changes, etc.; 15
• Formal project request applications; and 16
• Efficiency and IRP-related upgrades. 17
18
The GPSS management team meets twice every year to review the long-range forecast, 19
confirm that it is up-to-date and to close completed projects. New projects are highlighted 20
and noted. The impact of each additional project is reviewed. Any disagreement in the 21
priority of projects is discussed until a solution is found. 22
The GPSS management team participates in an annual workshop in preparation for the 23
budget cycle to prioritize the projects included in the five-year horizon. The team utilizes a 24
formal ranking matrix to ensure that the projects are prioritized consistently. 25
As projects for the next year are assigned, any capacity or budget constraints are 26
identified and project schedules are adjusted accordingly by the GPSS Management 27

Thackston, Di 13
Avista Corporation
Team. GPSS management and key stakeholders meet monthly at the Generation Coordination 1
Meeting, the GPSS coordinated-team meeting, and specific Program or Project Steering 2
Committee Meetings to discuss the progress of projects and any proposed changes to the 3
execution plan. Adjustments and consensus take place at these meetings. 4
Q. Company witness Mr. Thies identifies and briefly explains the six 5
“Investment Drivers” or classifications of Avista’s infrastructure projects and 6
programs. How then do these “drivers” translate to the capital expenditures that are 7
occurring in the Company’s generation area? 8
A. The Company’s six Investment Drivers are briefly described as follows: 9
1. Customer Requested – Respond to customer requests for new service or 10
service enhancements required for connecting new distribution customers or 11
large transmission-direct customers. This driver is generally not applicable to 12
Generation. 13
14
2. Mandatory and Compliance – These investment drivers are compelled by 15
regulation or contract and are generally beyond the Company’s control as they 16
are a direct result of compliance with laws, regulations and agreements, 17
including projects related to dam safety upgrades, public safety, air and water 18
quality, and equipment essential to legally operating within the interconnected 19
grid among others. 20
21
3. Failed Plant and Operations – This investment driver includes the 22
replacement of equipment that is damaged or fails due to an accident, or normal 23
wearing out requiring periodic replacement. The large, massive rotating 24
equipment and associated support machinery used for electric generation can 25
experience sudden mechanical failures or electrical insulation breakdowns 26
even with the benefit of ongoing maintenance and preventive maintenance 27
programs. 28
29
4. Asset Condition – Replace infrastructure assets or portions of assets at the end 30
of their functional service life based on asset condition due to age, 31
obsolescence and parts availability, and degradation of the asset. This category 32
includes replacement of critical parts requiring replacement prior to failure, as 33

Thackston, Di 14
Avista Corporation
well as replacing or overhauling older equipment to bring it up to meet current 1
codes and standards. 2
3
5. Customer Service Quality and Reliability – Meet our customers’ 4
expectations for quality and reliability of service, as well as increasing the 5
reliability of operating assets. 6
7
6. Performance and Capacity – Programs and projects to address system 8
performance and capacity issues so Company assets can co ntinue to satisfy 9
business needs and meet performance standards to support the interconnected 10
grid and to ensure the ability to participate in the regional wholesale energy 11
market. 12
13
The primary investment drivers for generation projects include Mandatory and 14
Compliance, Failed Plant and Operation, Asset Condition, Customer Service Quality and 15
Reliability, and Performance and Capacity. Exhibit No. 7, Schedule 3 – Avista Utilities 16
Generation Infrastructure Plan contains additional details, more thorough discussions and 17
specific examples concerning each of the six investment drivers, as well as overviews of the 18
planned capital and maintenance investments from 2020 through 2024. The main drivers for 19
each of the major generation-related capital investments in my testimony are discussed below. 20
Q. For the capital additions in the 2020 through 2023 timeframe, for which 21
you are responsible, is the Company seeking to include all of those investments in general 22
rates in this case? 23
A. Yes. The Company is providing more detailed information in testimony and 24
exhibits related to the projects completed over the proposed Two-Year rate Plan beginning 25
January 1, 2020 through August 31, 2023. Details about the generation-related capital projects 26
over the period included in this case are discussed below. Table No. 2 below provides the 27
system cost of each generation capital project included in this case for the 2020 through 28

Thackston, Di 15
Avista Corporation
Business Case Name 2020 2021 2022 2023(1)
Mandatory and Compliance
Cabinet Gorge Dam Fishway $ 122 - $ 63,203 -
Clark Fork Settlement Agreement 1,041 6,471 6,073 2,978
Spokane River License Implementation 935 1,660 587 373
Hydro Safety Minor Blanket - 50 50 33
Long Lake Stability Enhancement - 3,249 - -
KF_Ash Landfill Expansion - - 499 -
Failed Plant and Operations
Base Load Thermal Program 2,178 2,764 2,899 1,610
CS2 Single Phase Transformer 2,849 18,801 - -
Nine Mile Rehabilitation (24)63 - -
Peaking Generation Business Case 299 450 450 113
Asset Condition
Base Load Hydro 652 1,025 1,195 683
Cabinet Gorge 15 kV Bus Replacement 964 - - -
Cabinet Gorge Automation 4,062 3 - -
Cabinet Gorge Gantry Crane Replacement(2)(1,003)- - -
Colstrip 3&4 Capital Projects 7,089 8,106 3,410 3,745
Generation DC Supplied System Update 209 250 233 150
Little Falls Plant Upgrade 474 1,451 - -
Long Lake Plant Upgrade 87 1,331 - -
Regulating Hydro 1,373 2,390 2,160 666
Cabinet Gorge Unit 3 Protection & Control Upgrade - 2,818 - -
Cabinet Gorge Unit 4 Protection & Control Upgrade - 2,832 - -
Post Falls Landing and Crane Pad Development - 3,308 - -
HMI Control Software - 2,200 1,500 1,000
Generation Masonry Building Rehabilitation - - 700 700
KF_Fuel Yard Equipment Replacement - - 23,240 -
Customer Service Quality and Reliability
Automation Replacement 405 419 300 -
Misc. accrual reversals, corrections or additional TTP (92)- - -
Total Planned Generation Capital Projects $ 21,619 $ 59,640 $ 106,500 $ 12,051
(1) Includes system pro forma capital for the period of January 1, 2023 through August 31, 2023.
(2) Accounting correction made in September 2020. See Company witness Ms. Schultz direct testimony.
Generation Capital Projects (System) In $(000's)
August 2023 period. Additional details about specific generation capital projects associated 1
with Colstrip Units 3 and 4 are covered in a later section of my testimony. 2
Table No. 2: 2020 through 2023 Non-Colstrip Major Generation Capital Projects 3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Q. Would you please explain the generation capital projects included in this 22
case for 2020 through 2023? 23

Thackston, Di 16
Avista Corporation
A. Yes. The capital projects include generation capital investments grouped as 1
Mandatory and Compliance, Failed Plant and Operations, Asset Condition, and the Customer 2
Service Quality and Reliability investment categories. Brief descriptions of each project, the 3
reasons for the projects, and the timing of the decisions fo llow. Additional details can be 4
found in Exhibit No. 7, Schedule 4 – Generation and Environmental Capital Project Business 5
Cases. 6
Mandatory and Compliance Generation Capital Projects 7
Cabinet Gorge Dam Fishway ($122,000 in 2020, $63,203,000 in 2022) 8
The Clark Fork Settlement Agreement (CFSA) and FERC License require Avista to 9
implement the Native Salmonid Restoration Plan (NSRP), which includes a step -wise 10
approach to investigating, designing and implementing fish passage at the Clark Fork Project. 11
Fish passage is intended to restore connectivity of native salmonid species in the lower Clark 12
Fork watersheds. During relicensing the U.S. Fish & Wildlife Service (USFWS) reserved its 13
authority to require fish passage at both Noxon Rapids and Cabinet Gorge dams, in order to 14
pursue the NSRP collaboratively. Those efforts, including involvement of Native American 15
tribes and state agencies, as well as other stakeholders, continued over 15 years for the current 16
project. 17
18
Clark Fork Settlement Agreement ($1,041,000 in 2020, $6,471,000 in 2021, $6,073,000 in 19
2022, $2,978,000 in 2023) 20
The ongoing operation of the Clark Fork Project is guided by the Clark Fork Settlement 21
Agreement (CFSA) and FERC License No. 2058, which established the terms of the 45-year 22
license issued to Avista. Imbedded in the License is the requirement to continue to consult 23
agencies, tribes and other stakeholders. In addition, the CFSA and License provide decision-24
making participation for the settlement signatories, resulting in ongoing negotiations on 25
implementing license terms. The CFSA and License also include a number of funding 26
commitments to help achieve long-term resource goals in the Clark Fork and related 27
watersheds. 28
29
Avista is required to develop an annual implementation plan and report, addressing all 30
Protection, Mitigation and Enhancement (PM&E) measures of the License. Implementation 31
of these measures addresses ongoing compliance requirements with Montana and Idaho Clean 32
Water Act requirements, the Endangered Species Act, and state, federal and tribal water 33
quality standards and regulations. License articles also describe operational requirements for 34
items such as minimum flows, reservoir levels, dam and public safety requirements, land use, 35
habitat, fisheries, recreation, land management, wildlife and other natural resources, and 36
related matters. The investment drivers for this project are predominantly Mandatory and 37
Compliance in nature. 38

Thackston, Di 17
Avista Corporation
Spokane River License Implementation ($935,000 in 2020, $1,660,000 in 2021, $587,000 1
in 2022, $373,000 in 2023) 2
This capital spending category covers the ongoing implementation of PM&E programs related 3
to the FERC License No. 2545 and several other settlement agreements for the Spokane River 4
Project including the Post Falls, Upper Falls, Monroe Street, Nine Mile and Long Lake dams. 5
These capital projects include items enforceable by FERC, mandatory conditioning agencies, 6
and through settlement agreements. The FERC License defines how Avista operates the 7
Spokane River Project and includes several hundred requirements that must be met to retain 8
this License. The License is issued pursuant to the Federal Power Act and it embodies 9
requirements for a wide range of other laws such as the Clean Water Act, the Endangered 10
Species Act, and the National Historic Preservation Act, among others. These requirements 11
are also expressed through specific license articles relating to fish, terrestrial resources, water 12
quality, recreation, education, cultural, and aesthetic resources at the Spokane River Project. 13
The License incorporates specific funding requirements to a 50-year settlement agreement 14
between local and state agencies, as well as the Coeur d’Alene and Spokane Tribes. The 15
License references our requirements for land management, dam safety, public safety and 16
monitoring requirements, which apply for the term of the License and ensures Avista’s ability 17
to operate the Spokane River Project on behalf of our electric customers within our service 18
territory over the 50-year license term. 19
20
Hydro Safety Minor Blanket ($50,000 in 2021, $50,000 in 2022, $33,000 in 2023) 21
The Hydro Generation Minor Blanket funds periodic capital purchases and projects to ensure 22
public safety at hydro facilities both on and off water, for FERC regulatory and license 23
requirements. The types of projects include barriers and other safety item s like lights, signs 24
and sirens. Section 10(c) of the Federal Power Act authorizes the FERC to establish 25
regulations requiring owners of hydro projects under its jurisdiction to operate and properly 26
maintain such projects for the protection of life, health and property. Title 18, Part 12, Section 27
42 of the Code of Federal Regulations states that, "To the satisfaction of, and within a time 28
specified by the Regional Engineer an applicant, or licensee must install, operate and maintain 29
any signs, lights, sirens, barriers or other safety devices that may reasonably be necessary”. 30
Hydro Public Safety measures includes projects as described in the FERC publication 31
"Guidelines for Public Safety at Hydropower Projects" and as documented in Avista's Hydro 32
Public Safety Plans for each of its hydro facilities. 33
34
Long Lake Stability Enhancement ($3,249,000 in 2021) 35
During a recent FERC annual inspection, the inspector noticed a seeping join t in an airshaft 36
and requested that Avista evaluate the internal plane stability of the intake and spillway dams. 37
The analysis included an evaluation of all loading conditions the dam may experience 38
including full-pool (normal) operations, probable maximum flood (PMF), and seismic 39
conditions. The analysis revealed that Long Lake dam does not meet the internal plane 40
stability minimum safety factor during a PMF event. Avista submitted a preliminary study to 41
the FERC and is waiting for final design before sending the FERC the full scope of the project 42
and timeline to address mitigation for this issue. 43
44

Thackston, Di 18
Avista Corporation
Avista is also currently revising the Spokane River PMF assessment, as well as performing a 1
site-specific seismic hazard assessment, to fully understand what the loading on the facility is 2
and how best to address any mitigation. Both of these studies are in their final stages and/or 3
under the FERC review. Additional investigation of three-dimensional effects of the 4
geometry of the facility is also actively being performed. Avista is developing a mitigation 5
plan to address the stability issues. The current solution is anticipated to provide additional 6
anchoring at the facility as well as potentially adding concrete mass to the dam structures. 7
8
Kettle Falls Ash Landfill Expansion ($499,000 in 2022) 9
The current landfill area for the Kettle Falls Plant is approximately 15 acres nested inside of 10
a 42-acre fenced parcel designated for landfill operations and development. The ash generated 11
from the plant has been stored at the landfill since 1986. The landfill consists of three 12
engineered cells (Phase 1-3). Phases 1 and 2 were closed and covered in 2003 in accordance 13
with WAC regulations. In February 2020, a permit modification request was submitted with 14
the Department of Ecology to increase the slope of the Phase 3 cell from a 4-to-1 to a 3-to-1 15
slope. This request would increase the capacity of the current Phase 3 cell by 110,000 cubic 16
yards. On May 5th, 2020, the Department of Ecology approved the request to increase the 17
Phase 3 slope. Calculations with the newly approved slope and existing air space revealed 18
Phase 3 reaching full capacity in 2025. 19
20
Environmental Information Logistics EIL and Schwyn Environmental Services were hired to 21
assist in the planning and budgeting efforts to create a Landfill Master Plan for current 22
operations, closure of Phase 3, and engineering and design of Phase 4. The creation of the 23
new Phase 4 landfill area creates space for ash disposal at the current rate of nearly 40 -50 24
years of as disposal. The Phase 4 landfill is the lowest cost impact to the customers for 25
disposal of the ash when comparing the costs of disposal into the nearest acceptable landfill. 26
27
Failed Plant and Operations Generation Capital Projects 28
Base Load Thermal Program ($2,178,000 in 2020, $2,764,000 in 2021, $2,899,000 in 2022, 29
$1,610,000 in 2023) 30
Avista’s Base Load Thermal plants include Coyote Springs 2 and the Kettle Falls Generating 31
Station. These two base load plants provide different operational flexibility to serve Avista’s 32
customer’s energy demands. Coyote Springs 2 is a natural gas-fired combined cycle unit 33
which generates 300 MW’s. It is equipped with automation to adjustment unit output to match 34
changing system loads and other types of services necessary to provide a stable electric grid. 35
Kettle Falls is a base load renewable woody biomass resource with the ability to store energy 36
in its fuel supply for long periods of time to optimize energy markets to best serve Avista’s 37
capacity, energy and renewable resource needs. 38
39
Projects for Coyote Springs 2 are identified and prioritized during the Annual Budgeting 40
process, with emergent projects discussed during the Monthly Owners committee meetings 41
between Avista and Coyote Springs management. Some of the projects that fall within this 42
business case are joint projects between Portland General Electric (the plant operator) and 43
Avista. These projects are also reviewed in an owner committee setting during monthly 44

Thackston, Di 19
Avista Corporation
meetings at the plant. Kettle Falls Generation Station projects are identified and prioritized 1
through the plant’s Budget Committee. Both plants utilize the GPSS ranking matrix system 2
to evaluate projects. 3
4
Individual projects which are identified are then reviewed and approved or denied by the Manager 5
of Thermal Operations and Maintenance, specific plant managers and/or GPSS management 6
before they are scheduled and implemented. Some projects completed under this program may 7
require additional financial analysis if they are sufficiently large or if there are several options to 8
meet the objective. These larger projects are reviewed with finance personnel to ensure they are 9
in the best financial interests of our customers. 10
11
Coyote Springs 2 Single Phase Transformer ($2,849,000 in 2020, $18,801,000 in 2021) 12
The purpose of this project is to replace the currently in-service transformer, “T4”, which 13
exhibited unacceptably high gassing levels after only being in service a few months following 14
the failure of its twin after approximately nine years of service. Following a detailed financial 15
analysis, the recommended solution is to replace the existing three-phase dual-wound 16
transformer, T4, with three single phase dual-wound transformers. The financial analysis 17
included a calculation of Customer Internal Rate of Return (CIRR) compared to all possible 18
alternative options. The CIRR of the proposed solution was the highest. This project is 19
expected to increase reliability and reduce power supply expense at Coyote Springs 2. 20
Additional details concerning the history and analysis of this project are provided later in my 21
testimony. 22
23
Nine Mile Rehabilitation (-$24,000 in 2020, $63,000 in 2021) 24
The Nine Mile Redevelopment is a continuing capital project to rehabilitate and modernize 25
the Nine Mile Hydroelectric Dam. Previous components of this project submitted for approval 26
in prior general rate proceedings include the complete upgrades of Nine Mile Units 1 and 2 in 27
2016 and replacement of the Intake Deck and Debris System in 2017. The Sediment Bypass 28
Enhancement, which included improvements to an existing passage for increa sed sediment 29
diversion, and the Cooling Water System to prevent forced outages caused by excessive debris 30
during runoff were completed in 2018. The 2021 capital projects for the Nine Mile 31
Redevelopment include the closeout of this project work. 32
33
Peaking Generation Business Case ($299,000 in 2020, $450,000 in 2021, $450,000 in 2022, 34
$113,000 in 2023) 35
The Peaking Generation program focuses on the ongoing capital maintenance expenditures 36
required to keep Boulder Park, the Rathdrum Combustion Turbines, and the Northeast 37
Combustion Turbines operating at or above their current performance levels. This program 38
plans to keep the operating expenses of these plants as low as possible while ensuring starting 39
and operating reliability by providing funding for specific efforts to allow the plants to 40
accomplish those objectives. Work includes replacement of items identified through asset 41
management decisions and programs necessary to maintain reliable and low operating costs 42
of these plants. The program includes initiatives to meet FERC, NERC and EPA mandated 43
compliance requirements. 44
45

Thackston, Di 20
Avista Corporation
Asset Condition Generation Capital Projects 1
Base Load Hydro ($652,000 in 2020, $1,025,000 in 2021, $1,195,000 in 2022, $683,000 in 2
2023) 3
The Base Load Hydro program covers the ongoing capital maintenance expenditures required 4
to keep the Upper Spokane River Plants (Post Falls, Upper Falls, Monroe Street, and Nine 5
Mile) operating at their current performance levels while meeting FERC and NERC mandated 6
compliance requirements. This program focuses on ways to maintain compliance and reduce 7
overall O&M expenses while maintaining a reasonable level of unit availability. Projects 8
completed under this program include replacement of failed equipment and small capital 9
upgrades to plant facilities. Most of these projects are short in duration, and many are 10
completed in reaction to plant operations issues. 11
12
Cabinet Gorge 15 kV Bus Replacement ($964,000 in 2020) 13
In coordination with the Cabinet Gorge Station Service Project, a replac ement bus was 14
required to ensure that the bus was adequate given the generators and generation step up 15
transformers being used. This required an upgrade of the existing 15 kV bus with a new 4,000 16
Amp segregated bus at Cabinet Gorge. The new configuration will have an increased load 17
rating and the horizontal sections will have an increased load rating and the horizontal sections 18
will be raised five feet to allow for acceptable access to the bus room equipment. The original 19
15 kV bus is underrated by approximately 10 percent based on the load requirements between 20
the generators and the Generation Step-up transformers. In addition, the current configuration 21
prevents access for the installation of new station service equipment in the bus rooms. This 22
access requires the horizontal portion of the bus to be raised five feet. The design allows 23
Avista to build as much of the new station service system as possible while the existing station 24
service equipment remains in service. This construction approach greatly reduces generation 25
unit outages from several months to just a few weeks. In addition, this project removes oil-26
filled equipment from the outdoor powerhouse deck. This requirement is based on the 27
extensive amount of water that the powerhouse deck receives during spill season with the 28
modified spillways now in service for total dissolved gas abatement and it will reduce risk of 29
potential oil spills. 30
31
The B section of the bus was placed into service in November 2020. The A Section of the 32
bus is expected to be completed by November 1, 2021. Design was completed in June 2020 33
and the ordering and receipt of material was completed in August of 2020. The bus outage 34
for the B section began in October of 2020. The bus outage for the A section is expected to 35
take place in September and October of 2021 timeframe. 36
37
Cabinet Gorge Automation ($4,062,000 in 2020, $3,000 in 2021) 38
The Cabinet Gorge Project was designed for base load operation. Today, it is often called on 39
to provide load and to quickly change output in response to the variability of wind and solar 40
generation, to adjust to changing customer loads, and other regulating services needed to 41
balance system load requirements and assure transmission reliability. The controls necessary 42
to respond to these new demands include speed controllers (governors), voltage controls 43
(automatic voltage regulator a.k.a. AVR), primary unit control system (i.e. PLC), and the 44

Thackston, Di 21
Avista Corporation
protective relay system. In addition to reducing unplanned outages, these systems will allow 1
Avista to maximize these services for its own assets on behalf of its customers rather than 2
having to procure them from other providers. 3
4
There are several NERC Reliability standards where existing equipment performs at a sub-5
standard level. A few of these standards involve frequency response and voltage control 6
issues, which can lead to unplanned outages. There have been several unit outages associated 7
with the existing control and protection equipment that this project will address. This 8
equipment is at the end of its intended life and is subject to an increased likelihood of forced 9
outages and subsequent loss of revenue and reliability. 10
11
The Cabinet Gorge Automation Project will also provide additional value when Avista joins 12
the EIM in 2022 by helping the unit follow market dispatch signals. The investment drivers 13
for this project includes Asset Condition, and Performance and Capacity. Design was 14
completed in September 2019, followed by construction beginning in September of 2019 and 15
ending in March 2020. 16
17
Cabinet Gorge Gantry Crane Replacement (-$1,003,000 in 2022) 18
This is an accounting correction made in September 2020 that is discussed in Company 19
witness Ms. Schultz’s testimony as referenced in Table 2. 20
21
Colstrip 3 & 4 Capital Projects ($7,089,000 in 2020, $8,106,000 in 2021, $3,410,000 in 22
2022, $3,745,000 in 2023) 23
Avista does not operate the Colstrip facility nor does it prepare the annual capital budget plan. 24
The current operator develops and provides the annual business plan and capital budgets to 25
the owner group every September. They also provide individual project summaries which 26
characterize the work using categories similar in concept to the Avista business case drivers. 27
Avista reviews these individual projects. Some of them are reclassified to O&M if the work 28
does not conform to our own capital policy. Avista does not have a “line item veto” capability 29
for individual projects under the Ownership and Operation Agreement although individual 30
projects can be cancelled or postponed if a sufficient majority of the owners agree. 31
32
Generally, by the subsequent November meeting, the business plan is approved in accordance 33
with the Ownership and Operation Agreement for Units 3 and 4 that six companies are party 34
to. No budget agreement was made during 2020. The amount provided is an estimate taken 35
from the prior year’s forecast. As a result, the final Colstrip capital budget may not exactly 36
match the amount provided above. We will update the Colstrip capital budget numbers when 37
approved. Additional details regarding Colstrip Units 3 and 4 are discussed in the Colstrip 38
Generation Capital section later in this testimony. 39
40
Generation DC Supplied System Update ($209,000 in 2020, $250,000 in 2021, $233,000 41
in 2022, $150,000 in 2023) 42
The Generation DC Supplied System program covers all the generation and control facilities. 43
It is the backbone for supplying power to the protective relays, breakers, controls and 44
communication systems. With NERC requirements being followed and design enhancements 45

Thackston, Di 22
Avista Corporation
being implemented, the DC system is being monitored, tested and continues to remain reliable. 1
Experience shows that we must continually monitor, review and maintain our DC system. 2
The equipment manufacturers provided an estimated life span for the batteries and auxiliary 3
equipment. Some of these estimates have been wrong and some equipment has required early 4
change out due to failing tests or other issues with the equipment. Proven manufacturers are 5
used to improve the reliability and lifespan of this equipment. 6
7
Little Falls Plant Upgrade ($474,000 in 2020, $1,451,000 in 2021) 8
The Little Falls Plant Upgrade Program began in 2012 and is in the final phases of 9
implementation in 2020 and 2021. Only the Plant Sump, Drain Field, and Panel Room 10
Roof/Enclosure for the new controls equipment project components still need to be completed. 11
Septic work was completed in November 2020, sump work is scheduled for completion in 12
June 2021, and the Panel Room/Roof Enclosure in March 2021. The remaining work has very 13
little risk exposure and minimal impact on the plant’s current operations. 14
15
Long Lake Plant Upgrade ($87,000 in 2020, $1,331,000 in 2021) 16
The Long Lake equipment ranged from 20 to more than 100 years old when this project began. 17
We had experienced an increase in forced outages at Long Lake from almost zero occurrences 18
in 2011 and increasing in number every year since then. The increasing number of outages 19
was caused by equipment failures on a number of different pieces of equipment. Long Lake 20
serves Avista’s allocated north electric district providing power to our transmission grid and 21
local distribution power sources. The primary drivers for the Long Lake Plant Upgrade 22
included Performance & Capacity, Asset Condition, and Failed Plant & Operations. The 23
planned course of action was to replace the existing units in kind. 24
25
Currently, the turbines are thrusting too much (a sign of significant wear), including a failure 26
in 2015. The 1990 vintage control system is failing, and only secondary markets can support 27
this equipment. Inspections of other components of the generator show the stator core is 28
"wavy" where the core lamination steel should be straight. The "wave" pattern is a strong 29
indication of higher than expected losses occurring in the generator. 30
31
With the increase in generator output, the output of the generator step up transformer (GSU) 32
has also increased to its rating. The existing GSU's are over 30 years old and operating at the 33
high end of their design temperature, these are now approaching their end of useful life and 34
need to be replaced proactively rather than waiting for a failure to occur. The other major 35
drivers for the program is Station Service disconnect switching safety. 36
37
Regulating Hydro ($1,373,000 in 2020, $2,390,000 in 2021, $2,160,000 in 2022, $666,000 38
in 2023) 39
Avista’s regulating hydro plants have reservoir storage. This storage provides these plants 40
with operational flexibility to support energy supply, provide peaking power, provide 41
continuous and automatic adjustment of output to match the changing system loads, and to 42
supply other types of services necessary for grid stability and to maximize value to Avista and 43
its customers. The regulating plants include the four largest hydro plants on Avista’s system 44
representing more than 950 MW of capacity. These plants include Noxon Rapids and Cabinet 45

Thackston, Di 23
Avista Corporation
Gorge on the Clark Fork River in Montana and Idaho, and Long Lake and Little Falls on the 1
Spokane River. 2
3
This program funds smaller capital expenditures and upgrades required to maintain safe and 4
reliable plant operation to provide customers with low cost, reliable power while ensuring the 5
region has the resources it needs for the Bulk Electric System. Projects completed under this 6
program include replacement of failed equipment and small capital upgrades to plant facilities. 7
The business drivers for the projects in this program is a combination of Asset Condition, 8
Failed (or Failing) Plant, and addressing operational deficiencies. Most of these projects are 9
short in duration, typically well within the budget year, and many address plant operational 10
support issues. Without this funding source, it would be difficult to resolve relatively small 11
projects concerning failed equipment and asset condition in a timely manner. This could 12
jeopardize plant availability and impact the plant’s value to customers and the stability of the 13
grid. 14
15
Cabinet Gorge Unit 3 Protection and Control Upgrade ($2,818,000 in 2021) 16
The Cabinet Gorge Project has retained most of its original equipment from the 1950s which 17
is now at the end of life. This plant was designed for base load operation, but is now called 18
on to not only serve load but to quickly change output in response to the variability of wind 19
and solar generation, to changing customer loads, and other regulating services needed to 20
balance the system load requirement and assure transmission system reliability. 21
22
Meeting these increasing demands for flexibility requires upgrades to protection and control 23
equipment. This equipment includes speed controllers (governors), voltage controls 24
(automatic voltage regulation a.k.a. AVR), primary unit control systems (Programmable 25
Logic Controllers) and the protective relay system all of which serve to increase 26
communications and reaction time for Cabinet Gorge Unit 3. 27
28
Cabinet Gorge Unit 4 Protection and Control Upgrade ($2,832,000 in 2021) 29
The Cabinet Gorge Project has retained most of its original equipment from the 1950s which 30
is now at end of life. This plant was designed for base load operation but is now called on to 31
not only serve load but to quickly change output in response to the variability of wind and 32
solar generation, to changing customer loads, and other regulating services needed to balance 33
the system load requirement and assure transmission system reliability. 34
35
Meeting these increasing demands for flexibility requires upgrades to protection and control 36
equipment. This equipment includes speed controllers (governors), voltage controls 37
(automatic voltage regulation a.k.a. AVR), primary unit control systems (Programmable 38
Logic Controllers) and the protective relay system all of which serve to increase 39
communications and reaction time for Cabinet Gorge Unit 4. 40
41
Post Falls Landing and Crane Pad Development ($3,308,000 in 2021) 42
The property located adjacent to the North Channel of the Post Falls Hydroelectric 43
Development (HED) is being developed by the City of Post Falls for use as a public 44
recreational area. In conjunction with the purchase of the property, the City of Post Falls and 45

Thackston, Di 24
Avista Corporation
Avista agreed to develop the area so it could be utilized by Avista for staging a crane, barges 1
and equipment for maintenance and construction in support of the Post Falls HED. The area 2
will be joint use and when not needed by Avista, the area would be utilized by the City of Post 3
Falls and the public for recreational purposes. 4
5
HMI Control Software ($2,200,000 in 2021, $1,500,000 in 2022, $1,000,000 in 2023) 6
New Human-Machine Interface (HMI) control software is needed to prevent limitations going 7
forward that will introduce security risks. The existing HMI software runs on Windows 7 and 8
Microsoft will no longer support Windows 7 after 2020. Cyber security risks increase if we 9
do not stay current with supported operating systems. Replacing unsupported HMI software 10
allows the Company to upgrade control computers to supported operating systems such as 11
Windows 10 which helps to control cyber security vulnerabilities and other issues associated 12
with unsupported software. 13
14
In addition, developing new control screens on a new software platform will modernize 15
control screens and allow operators to carry out their resp onsibilities more effectively. 16
Control Screens will need to be developed for each generating facility; therefore, a planned 17
approach will allow engineers and technicians to develop screens to coordinate with control 18
upgrades. 19
20
This project addresses concerns with unsupported software, such as cyber security 21
vulnerabilities and general operating issues. Engineering will assist with developing a new 22
server-based architecture and developing and commissioning HMI control screens. 23
24
Generation Masonry Building Rehabilitation ($700,000 in 2022, $700,000 in 2023) 25
Several buildings for Avista's Power Plants are constructed of masonry and are approaching 26
one hundred years in age. These buildings include The Little Falls Power House and Gate 27
Building, The Long Lake Power House, the Nine Mile Power House, The Post Street Building, 28
and The Post Falls Power House and Substation Building. The grout and brick in many cases 29
has begun to fail which is creating a serious personnel and public hazard as bricks become 30
loose in the walls and parapets and can fall to the ground. This safety issue has become 31
critical, especially during the freeze and thaw cycles in the spring. The project funds a 32
comprehensive inspection of each building to create a refurbishment plan which will remedy 33
the issue long term ay each facility. 34
35
Kettle Falls Fuel Yard Equipment Replacement ($23,240,000 in 2022) 36
The Kettle Falls Generating Station was constructed in 1983 to generate power using wood 37
waste from area sawmills that is trucked to the plant with contracted hauling companies. 38
Trucking companies use semi-trucks and 53-foot trailers to transport the material from 39
sawmills to the Kettle Falls plant. 40
41
Washington State increased the legal hauling capacity on the State highways allowing 42
trucking companies to increase the trailer lengths from 48 to 53 feet in 1985. This increase in 43
allowed trailer length and haul weight created efficiencies in transportation of materials but 44
created a deficiency in the Kettle Falls fuel handling system. The current scale is too short 45

Thackston, Di 25
Avista Corporation
for the entire truck and a 53-foot trailer to fit on, thus requiring drivers to lift the tag axle in 1
order to weigh their load. The truck dumpers are not rated to lift the larger payload and 2
physically cannot fit a truck and a fully loaded 53-foot-long trailer. 3
4
An operational work around was developed for the drivers to detach the truck from the longer 5
trailers prior to offloading the wood waste. A contract driver died in 1983 while helping 6
another driver during the disconnecting process. Another contract driver was seriously injured 7
while attempting to manually offload an overloaded truck prior to unloading on the truck 8
dumpers in 2015. 9
10
The Kettle Falls plant has operated for over 35 years and much of the equipment has reached 11
its end of useful life. Many of the fuel yard components are failing and replacement parts are 12
no longer available. The new fuel yard system will provide additional margin needed to assure 13
compliance with visibility and particulate (PM) emission standards. Other equipment 14
deficiencies include a short truck scale, steep conveyor angles that result in equipment 15
downtime during cold weather events, inadequate wood screening, and a failing hammer hog. 16
Key drivers for this project are Safety, Environmental and Failed Plant Assets. 17
18
The new fuel yard equipment will include inbound and outbound scales, two larger capacity 19
truck dumpers, conveyance, disc screen and hammer hog, and an operating building. The new 20
system will be greenfield construction allowing the plant to continue accepting material while 21
construction and commissioning of the new equipment occurs. The new system will eliminate 22
deficiencies with the scaling process, create safer dumping of the trucks with larger capacity 23
dumpers, control fugitive emissions with covered equipment, increase truck turn time, and 24
lower fuel transportation cost. 25
26
Customer Service Quality and Reliability Generation Capital Projects 27
Automation Replacement ($405,000 in 2020, $419,000 in 2021, $300,000 in 2022) 28
The Automation Replacement project systematically replaces the unit and station service 29
control equipment at our generating facilities with a system compatible with Avista’s current 30
control standards for reliability. Upgrading control systems within our generating facilities 31
allows us to continue providing reliable energy. The Distributed Controls Systems (DCS) and 32
Programmable Logic Controllers (PLC) are used to control and monitor Avista’s individual 33
generating units as well as each total generating facility. The DCS and PLC work in this 34
capital program is needed to reduce the higher risk of failure due to the age of the currently 35
installed equipment. The DCSs are no longer supported and spare modules are limited. The 36
modules in service have a high risk of failure as they are over 20 years old. The computer 37
drivers that are needed to communicate to the DCSs are not compatible with the new 38
computers using Windows 10 operating systems. This creates a cyber-security issue. The 39
software needed to view and modify the logic programs only runs on Windows 95 and Avista 40
has a very limited supply of Windows 95 laptops that are also failing as they age. Replacing 41
the aging DCSs and PLCs before they fail will reduce unexpected plant outages that require 42
emergency repair with like equipment. A planned replacement approach allows engineers and 43

Thackston, Di 26
Avista Corporation
technicians to update logic programs more effectively and replace hardware with equipment 1
that meets current standards. 2
3
Avista’s hydro facilities were designed for base load operation but are now increasingly called 4
on to quickly change output in response to the variability of wind and solar generation, to 5
adjust to changing customer loads, and other regulating services needed to balance system 6
load requirements and assure transmission reliability. The controls necessary to respond to 7
these new demands include speed controllers (governors), voltage controls (automatic voltage 8
regulator a.k.a. AVR), primary unit control system (i.e. PLC), and the protective relay system. 9
In addition to reducing unplanned outages, these new systems allow Avista to maximize 10
ancillary services for its own assets on behalf of customers rather than procuring them from 11
other providers. 12
13
Q. Are there any of the above non-Colstrip generation capital projects that 14
you want to provide more background concerning the history and need for the project? 15
A. Yes, I want to provide additional details about the history of and need for the 16
Coyote Springs 2 Transformer Project. Avista has experienced multiple failures of its 17
generator step-up (GSU) transformers at Coyote Springs 2 over its 17 years of operation. Four 18
GSU’s have been placed into service since 2003: two Alstom/Areva units (T1 and T2), which 19
were manufactured in Turkey; and two Siemens units (T3 and T4), which were manufactured 20
in Brazil. All four units were dual low voltage wound (13.8/18 kV) to 500 kV transformers. 21
Most recently, in 2018, after nine years of service, T3 failed in service. The spare transformer, 22
T4, was placed into service later the same year, but after several months of operation it also 23
began exhibiting signs of internal deterioration that would eventually lead to failure. The 24
Coyote Springs 2 generator facility is currently operating without a spare transformer and the 25
in-service transformer, although able to function at near full capacity, is gassing internally and 26
could fail in the same manner as T3. To reduce risk of failure the maximum plant generation 27
output was reduced to keep heating in the windings down per recommendations from a 28
consultant, until such time as the transformer can be replaced. 29

Thackston, Di 27
Avista Corporation
When Avista purchased T3 and T4, we specifically excluded Areva Turkey (the 1
original manufacturer of T1 and T2) as a potential supplier to get a different transformer 2
design and to have the unit manufactured in a different factory to avoid a factory-related 3
systemic deficiency. This was successful in one aspect as the initial forensic analysis of the 4
T3 failure shows a failure in an entirely different location from the failures that were observed 5
in T1 and T2. Nevertheless, given that we have encountered multiple failures of this three-6
phase configuration over the operating lifetime, Avista chose to conduct a detailed financial 7
analysis of multiple options that included an alternate single-phase configuration and also 8
considered a risk element for options that would just continue using the three-phase dual 9
wound configuration. 10
The decision tree below in Illustration No. 1 provides a high-level summary of where 11
we are now regarding the transformer decision at Coyote Springs 2. Element 4 represents a 12
financial analysis we performed to determine the best path forward. Options evaluated 13
included various T3/T4 repair combinations, purchasing of two new dual wound three-phase 14
units, and purchasing new single-phase dual wound units. The financial analysis determined 15
the purchase of single phase dual wound transformers to be the most cost-effective solution 16
for customers. Because of the extraordinarily long lead time associated with ac quiring 17
transformers of this size, Avista has had to keep other options open. In the decision tree below, 18
the bolded green lines represent the chosen path to date. You may note that Element 6 19
presented a choice that could have taken us down a path of repairing T3 or T4 and placing it 20
back into service even though new transformers of a completely different design had been 21
ordered. The reason for maintaining this optionality is the long lead time required for these 22
types of transformers to be built and shipped, and the potential for extremely long outages that 23

Thackston, Di 28
Avista Corporation
T3 Fail
&
T4 gassing
T4 Fail?
YES
NO
Financial
Analysis
3-Phase Interim
Solution?
YES NO
Install T5's in
2021
Purchase New Single Phase
Transformers (T5's)
Forensic
Analysis T3
Store T5
Transformers
Install T5's at
Earliest Economic
Outage Window
Install T5's ASAP
NO
YES
Store T3
1
2
3
4
I
6 7
8
9
New 3-phase
1110a10b
Repair T3, T4 Emergency
Spare
New 3-phase, Repair T3
New 3-phase, T4 Emergency
Spare, T3 scrap
2 New 3-phase units
II
III
IV
V
5
expose the Company to market volatility and higher power supply expense. We are now at a 1
point in time where construction of the new single-phase units is far enough along that we 2
would be able to install them faster than any potential repair and reinstallation of T3/T4. 3
Illustration No. 1: Coyote Springs 2 Transformer Decision Tree 4
5
6
7
8
9
10
11
12
13
This project has two sub-projects. The portion of the overall project that transferred 14
to plant in 2020 included the civil and structural modifications that needed to be made to 15
accommodate the installation of the new transformers, oil containment, and firewall systems. 16
This portion of the work was completed in 2020 to allow the transformers to be installed 17
during the spring of 2021 before summer peak load conditions. The installation of the new 18
transformers is scheduled to be completed by June 30, 2021. Included in Exhibit No. 7, 19
Schedule 4 is the Business Case as well as other documents explaining the need for this 20
project. The investment drivers for this project includes Failed Plant and Operation, Asset 21
Condition, Customer Service Quality and Reliability, and Performance and Capacity. 22
Q. Did Avista consider alternatives to the Coyote Springs 2 Transformer 23

Thackston, Di 29
Avista Corporation
Project? 1
A. Yes, Avista considered multiple alternatives to this project as indicated in the 2
decision tree in Illustration No. 1 above and detailed in the documentation included in Exhibit 3
No. 7, Schedule 4. The Company selected what is considered by our expert consultants to be 4
the premier transformer factory in the world, Siemens’ facility in Austria, to manufacture four 5
(4) single-phase dual wound transformers. These transformers are of a dramatically different 6
design than the previous transformers at Coyote Springs 2. Each single-phase transformer is 7
much lighter (thus much less costly to transport and handle) than the previous three phase 8
transformers because the duty is divided between three units, yet the combined MVA capacity 9
of these single-phase transformers is significantly higher than T1-T4, which provides 10
significant additional operating margin and reliability. Had we chosen to replace T4 with a 11
similar upgraded capacity three-phase unit, it likely would not have fit on the existing 12
transformer pad. 13
Avista believes that the new configuration using individual single-phase transformers 14
will provide long term dependable reliability and reduce the Power Supply expense associated 15
with replacement power for the outages that we have observed over the life of the plant 16
because of the first four transformer failures. Additionally, the new transformers have 17
increased capacity to afford a larger operational margin and will accommodate increased 18
output from the facility if any future plant upgrades are made. 19
20
V. COLSTRIP GENERATION CAPITAL PROJECTS 21
A. Introduction and Summary of Capital Additions 22
Q. Before discussing the operation of and capital additions for Colstrip Units 23

Thackston, Di 30
Avista Corporation
Business Case Name 2020 2021 2022 2023(1)
Asset Condition
Colstrip 3&4 Capital Projects 7,089 8,106 3,410 3,745
Total Planned Colstrip Capital Projects $ 7,089 $ 8,106 $ 3,410 $ 3,745
(1) Includes system pro forma capital for the period of January 1, 2023 through August 31, 2023.
Colstrip Capital Projects (System) In $(000's)
3 and 4, please discuss the purpose of this section of your testimony. 1
A. The following testimony provides additional details concerning the capital 2
spending projects associated with the Company’s ownership interests in Colstrip Units 3 and 3
4, as well as providing details about the capital spending decision process for Colstrip. Table 4
No. 3 shows that planned annual capital expenditures for Colstrip from 2020 through the end 5
of August 2023. 6
Table No. 3: 2020 – 2023 Colstrip Capital Additions 7
8
9
10
11
12
13
Q. Can you provide some background about how Avista makes and manages 14
Colstrip capital decisions? 15
A. Yes. Talen, the plant operator, makes ongoing assessments regarding the 16
conditions of the equipment at the plant during operations, outages and overhauls. Talen uses 17
the information obtained in these assessments to determine when particular components need 18
to be repaired or replaced. This assessment process also includes the solicitation of advice 19
from original equipment manufacturers, equipment vendors, internal and external plant 20
engineers, as well as the plant Owners. Talen produces a budget after consideration of 21
different options and timing for capital projects and presents them to the Project Committee 22
for discussion, additional analysis if necessary, and for voting as directed by the ownership 23

Thackston, Di 31
Avista Corporation
agreement. The approval of capital budgets requires at least 55 percent of the ownership and 1
three members of the Project Committee including the Plant Operator. 2
Avista actively participates in the capital decision-making process at Colstrip and fully 3
exercises its ownership interest in Units 3 and 4. Each year Talen, the plant operator, proposes 4
a set of capital projects for Units 3 and 4, as well as for the plant-in-common. These projects 5
are reviewed by one or more Avista representatives on an individual basis and also as an 6
ownership group. Additionally, Avista and other Company representatives meet with Talen 7
at least every other month to review plant operations including capital projects. Projects may 8
be added or subtracted throughout the year as appropriate based on the operational, 9
environmental and safety requirements of the project. While it is true that the ownership 10
structure and operating agreement for Colstrip do not provide a line item veto of individual 11
capital projects, and Avista only has a small ownership interest preventing it from unilaterally 12
stopping capital projects on its own, the Company nevertheless actively exercises its 13
ownership rights while projects are being discussed. The compensation structure for the plant 14
operator is cost-based and does not include any rate of return based on the capital spending at 15
the plant. There is no economic incentive or justification for the plant operator to spend 16
foolishly or “gold plate” the facility while maintaining and operating the plant. In fact, quite 17
the opposite is true. The plant operator is an independent power producer whose business 18
model requires low plant costs to ensure the plant is competitive in the market, so there is no 19
financial incentive for them to spend needless capital on any projects. The plant operator’s 20
financial interests to minimize costs while meeting all regulations, are the same as all of the 21
Colstrip owners and in turn their customers. 22
Q. What is the overall reason for the on-going capital projects at Colstrip if 23

Thackston, Di 32
Avista Corporation
the plant is not expected to continue to serve Idaho customers beyond 2025 as 1
determined in the 2020 IRP? 2
A. Continued capital projects at Colstrip are necessary to maintain present 3
operational plant output expectations required by the plant owners to meet their anticipated 4
load demands. The Colstrip Generating Station consists of Units 1 and 2 – 333 (MW) that 5
operated from 1975 until their retirement in January 2020, and Units 3 and 4 – 805 MW each 6
operating since 1983 and 1986, currently assumed to operate until 2025 to serve Idaho and 7
Washington customers. An actual retirement date for Units 3 and 4 has not been determined 8
by the collective owners at this time. Despite the ongoing discussion about retirement, 9
Colstrip will continue to meet past, current and future regulatory obligations and 10
environmental compliance requirements while maintaining a reliable and operational facility. 11
This requires a strategic approach to planning and completing certain capital projects in order 12
to meet current and future regulatory goals. Specifically, the entire facility will manage water 13
and waste well beyond the operating life of the units according to the following requirements: 14
• The Site Certificate originally issued including the amended 12(d) stipulation 15
under the Major Facility Siting Act in Montana, Nov. 1975. 16
17
• Federal Coal Combustion Residual (CCR) Rule, 40 Code of Federal Regulations 18
(CFR), April 2015. 19
20
• Administrative Order on Consent (AOC) Regarding Impacts Related to 21
Wastewater Facilities, Montana Department of Environmental Quality (MDEQ) 22
(July 2012), Settlement agreement entered (2016). 23
24
Q. How do the owners of Colstrip address regulatory obligations and 25
environmental compliance requirements? 26
A. The Colstrip owner’s group does not approach its regulatory obligations and 27
environmental compliance requirements through a narrow perspective. The owners’ group, 28

Thackston, Di 33
Avista Corporation
and specifically Avista, must always strategically manage the risk to both our customers and 1
shareholders for the known and possible regulatory obligations at both the federal and state 2
levels, while managing reliability and cost of all of our generating resources. The owners do 3
not take this responsibility lightly and they exercise careful diligence in gathering information 4
at the point in time when strategic decisions must be made. 5
Q. Will projects still need to be completed regardless of when the Plant is shut 6
down? 7
A. Yes. The AOC required an extensive evaluation process that included site 8
characterization, clean-up criteria, risk assessment that resulted in the MDEQ selection of a 9
remedy and remedial action work plans. The draft and finalized documents can be found on 10
the MDEQ website specific to the Plant groundwater clean-up.1 In addition, the AOC actions 11
must also meet Federal CCR requirements and deadlines in the interim while maintaining 12
reliable plant operation. The AOC remedial action work plans and Federal CCR are both 13
regulatory obligations and environmental compliance requirements that must be met 14
regardless of the Plant operational status. Below, I briefly discuss the Colstrip capital projects 15
for the 2020 through August 2023 timeframe. 16
Q. Will the Washington Clean Energy Transformation Act requirement 17
requiring the elimination of energy from Colstrip 3 and 4 serving Washington customers 18
by the end of 2025 impact any of the capital projects in this case and will that law impact 19
the cost of Colstrip for Idaho customers? 20
A. No. As discussed elsewhere in my testimony, the Company is required to meet 21
1 http://deq.mt.gov/DEQAdmin/mfs/ColstripSteamElectricStation

Thackston, Di 34
Avista Corporation
several regulatory obligations and environmental compliance requirements, in addition to 1
maintaining Colstrip as a reliable, operational facility while it is still being used and relied 2
upon to serve customers. This requires a strategic approach to planning and completing 3
certain capital projects in order to meet required deadlines. As such, the owners will continue 4
to make the capital investments necessary to meet these requirements some of which extend 5
beyond the operation of the plant. Put another way, the projects the Owners have undertaken 6
are necessary, irrespective of existing laws or additional legislation. Even though Colstrip 7
will not be able to be used to serve Avista’s Washington customers and it cannot be included 8
in their rates for generation after 2025, the law specifically requires Washington customers to 9
still pay for their portion of the eventual shutdown and remediation costs associated with 10
Avista’s ownership interests in Colstrip Units 3 and 4. 11
Q. Can you provide additional details concerning the main “environmental 12
liabilities” associated with Colstrip that are being managed through these capital 13
projects? 14
A. Yes. The environmental liabilities are managed and considered through 15
Avista’s active management of its ownership share in conjunction with the plant operator. 16
This occurs with the input of Avista employees from GPSS and Environmental Affairs, as 17
Avista actively manages its shares of Colstrip Units 3 and 4, as described above, to ensure 18
that the plant operator is complying with all relevant state and federal environmental 19
regulations. The projects and costs needed for current and expected future compliance then 20
feed into the economic models used for the IRP. The environmental liability areas covered 21
for Colstrip include the following areas: 22
1. Coal supply: Coal mine reclamation is ongoing and Avista’s share of reclamation 23

Thackston, Di 35
Avista Corporation
costs are paid for as the coal is purchased. The Company has no additional costs 1
or legal requirements beyond this cost which has already occurred. The mine 2
owners are responsible for the actual reclamation. 3
4
2. Mercury controls: The current mercury abatement controls will continue to be used 5
as long as the plant is in operation. There are no additional mercury controls 6
expected to meet new requirements from the federal or state levels at this time. 7
8
3. Regional Haze: The combination of SmartBurn and regional plant closures place 9
Colstrip Units 3 and 4 within the glide path and selective catalytic reduction is not 10
expected to be required, but could still be made a requirement under the Regional 11
Haze Program if the plant were to run longer than currently anticipated based on 12
the economic analysis in the IRP. 13
14
4. CCR and water management: Please refer to this section later in my testimony 15
describing the need for required ongoing capital spending on CCR and water 16
management. 17
Q. Describe Avista/Talen’s project management process that was used to 18
manage the Colstrip capital projects. 19
A. Avista does not manage the projects at Colstrip directly. Talen as contract 20
operator, manages all of the projects. They use Primavera as a software solution to keep 21
projects on budget and on schedule. Talen employs a number of Project Management 22
Professionals and engineers who may be assigned to manage projects depending on 23
complexity. Budget to Actual reports are issued to Avista by Talen on a monthly basis. 24
Q. Please continue with a description of the Colstrip projects impacting the 25
Two-Year Rate Plan in this case. 26
A. Below, I briefly discuss the Colstrip capital projects for the 2020 through 27
August 2023 timeframe. Many of these projects span over multiple years as described below. 28
The cost status of each individual project, as well as descriptions of the projects, are included 29
in the summary reports contained in Exhibit No. 7, Schedule 5. 30

Thackston, Di 36
Avista Corporation
Q. Please describe the Separate Overfire Air Bucket Replacements Project. 1
A. The overfire air system is a critical component used to manage the coal 2
combustion process by providing a means to control the combustion by lengthening the 3
combustion resulting in less air being combusted to create the same heat for production 4
purposes. By this process, lower NOx levels are achieved while the fuel is still fully consumed 5
to manage other constituents of the combustion process. The ability to control the combustion 6
in the boiler is essential to managing the NOx emissions from the unit. In addition, proper 7
combustion management is required to also manage opacity, PM emissions, and other 8
elements and properties that result when coal is burned. Collectively, there are several 9
components needed to allow the coal to combust as clean as possible, achieve low NOx 10
emissions, and still provide the energy needed to produce the power from the unit. The 11
separated overfire air (SOFA) elements are one of these components. 12
SOFA buckets are essential to meeting environmental compliance by helping control 13
the combustion process. To maintain equipment function and help provide for NOx emission 14
and opacity control, the separated overfire buckets (and the top overfire buckets (TOFA)) need 15
to be replaced every four years during a unit overhaul. Overfire buckets warp with heat 16
exposure over an extended time in service, which causes buckets to bind up in the boiler and 17
restrict movement during unit operation. Through inspection during overhaul, the buckets on 18
Unit 4 were found to be at the end of their life. The SOFA buckets were replaced during the 19
2020 overhaul. Part of the work included in the 2020 overhaul was the erecting of scaffolding 20
in the boiler. The process of replacing buckets is most economical with a scaffold in place as 21
this allows for an effective and cohesive removal of buckets, easier access to make repairs to 22
support material, testing of movement, and alignment of all emission control components 23

Thackston, Di 37
Avista Corporation
associated with the boiler corners at the same time. Complete failure of the buckets was highly 1
probable if they were not replaced during the Unit 4 2020 outage. SOFA buckets are a portion 2
of the NOx control system and need to be in good working order for combustion optimization 3
and PM, opacity, and NOx control. Not performing this work would have resulted in a high 4
risk that environmental compliance (NOx, PM, Opacity) could not be met possibly resulting 5
in fines from the MDEQ for violating emissions standards. In addition to consequences from 6
the resulting non-compliance situation, the Unit would need to be run at reduced load or be 7
placed offline until new buckets were purchased and installed. 8
The lead time to obtain SOFA buckets is three to four months. The new Overfire 9
Buckets were purchased in early 2020 so they would be available for planners to incorporate 10
into the 2020 Unit 4 Overhaul work. Due to concerns with COVID-19, the Unit 4 Overhaul 11
effort was rescheduled to mid-September 2020 and included the installation of the Overfire 12
Buckets. Work began in September 2020 and was placed in service after the 2020 scheduled 13
Unit 4 maintenance outage. The investment drivers for this project include Asset Condition, 14
Customer Service Quality and Reliability, and Performance and Capacity. 15
Q. Please describe the New Brake/Shear/Electric Shop/CaBr2 System 16
Building Project. 17
A. With the shutdown of Colstrip Units 1 and 2 in January 2020, several items 18
need to be addressed that affect the near term continued operation of Units 3 and 4. One of 19
these items is the bulk storage and transfer system for the Calcium Bromide (CaBr2) used for 20
mercury abatement in Units 3 and 4. The existing bulk storage and transfer system is housed 21
alongside the Condensate system in Units 1 and 2. With the demolition and removal of Units 22
1 and 2, that location will no longer be a serviceable location. This project is required to 23

Thackston, Di 38
Avista Corporation
support the mercury abatement system. The Calcium Bromide (CaBR2) solution is injected 1
into the scrubber slurry which reacts with the mercury and oxidizes it in the flue gas which 2
can then be captured by the plant’s existing scrubber equipment. This system is required to 3
meet EPA Mercury and Air Toxic Standards, commonly referred to as MATS. 4
A new building will be erected on the East side of Unit 4, just south of the existing 5
Hydrazine building. It will share a common wall with Unit 4. The new building will house 6
the CaBR2 Bulk tank and transfer pumps in one end of the building in an enclosed space with 7
tank containment built into the foundation. The other end of the new building will house the 8
electric shop work area and an area where the existing brake and shear will be placed. The 9
electric shop and the brake and shear area will be serviced by an electric overhead crane. 10
These work areas are also currently within the Unit 1 and 2 footprint and are required for near 11
term continued operation of Units 3 and 4. The investment drivers for this project include 12
Asset Condition, Regulatory and Mandatory, Customer Service Quality and Reliability, and 13
Performance and Capacity. 14
Talen considered other alternatives including erecting different buildings to house the 15
brake and shear equipment, a separate building to house the electric shop, and the CaBr2 16
building. Conceptually, each building would be smaller than the single building being 17
proposed. The alternatives turned out to be an estimated three times more expensive to 18
construct the individual buildings rather than the single larger building. In addition, no 19
alternate space was found where the Brake and Shear Equipment or the Electric shop could 20
be reasonably located. The CaBr2 system must be moved so that it can continue to function 21
because of the environmental permit requirements for the mercury abatement. Finally, there 22
was consideration of not erecting the building to include the Brake and Shear equipment and 23

Thackston, Di 39
Avista Corporation
the Electric Shop. Without this space, the work performed there would need to be contracted 1
out, likely to the Billings area, which could cause delays in maintenance and corrective actions 2
for Units 3 and 4 as well as increase expenses. Additionally, work areas for the electrical 3
work would still be required to be set up throughout the plant on an ad hoc basis that would 4
reduce efficiencies provided by a central electrical work location as well as increase access 5
hazards throughout the plant. 6
Q. Please describe the Capture Well Treatment System Project. 7
A. By way of background, the Water Management System and Coal Combustion 8
Residual are essentially a building block set of projects that support the same strategic goal of 9
meeting our regulatory obligations and environmental compliance requirements under the 10
AOC with the MDEQ and EPA rules on Coal Combustion Residuals (CCR). These 11
requirements result in several multi-year capital projects that will likely extend out through 12
2024 to address groundwater quality at the Colstrip site. 13
A simple process description begins with raw water being piped from the Yellowstone 14
River to Castle Rock Lake and ultimately to holding tanks at the plant site. This water is used 15
in boilers, cooling towers and scrubber systems. Fly ash from the scrubber system is 16
transported to the plants which then removes the excess water and deposits paste into disposal 17
cells. Once the water is clear, it is ultimately recirculated back to the plant for reuse. All 18
water is either reused or lost through evaporation because Colstrip is a zero-discharge facility. 19
Throughout the years, some water has been lost through seepage from the ponds that has 20
contaminated the groundwater on the Colstrip site. The AOC is the primary Montana 21
regulatory mechanism to address the groundwater contamination. This is a multi-year project 22
due to the complexity and inter-related nature of the ponds. 23

Thackston, Di 40
Avista Corporation
Due to the significant amount of work required to meet these environmental 1
regulations, this project has and will continue to have Capital Projects in each year from 2020 2
through the close of the Plant. The overall handling of the closed loop water system at Colstrip 3
is subject to these two Environmental Must Do requirements. 4
The Colstrip Wastewater AOC requires specific actions by the plant to remediate 5
impacted groundwater at the Plant Site. MDEQ approved actions requires treatment of the 6
capture well water as part of the cleanup of impacted groundwater at the Plant Site. This 7
project provides funding for a two-year design/construction schedule to implement a 8
groundwater capture treatment system in accordance with the requirements identified in the 9
Colstrip Wastewater AOC Plant Site Remedy as approved by MDEQ. The construction 10
schedule meets the requirements of the approved MDEQ remediation for the plant site 11
groundwater capture wells. 12
The MDEQ approved remedy for remediation also includes fresh-water injection into 13
the plant water system. To implement this remedy, fresh-water injection wells will be 14
installed, and additional capture wells developed this year as required by this approved 15
remedy. Once the remediation injection wells are operating at full capacity, we expect the 16
total capture rate to be approximately 500 gpm. At this full capacity rate, we will fill the 17
Groundwater Capture Storage Pond in about two years. The two-year design and construction 18
schedule proposed with this project will meet the remediation requirements as approved by 19
MDEQ. 20
This project also includes the design and construction of a new Brine Concentrator, 21
steam supply, and a Crystallizer. The steam supply unit will provide capacity for this 22
groundwater capture treatment system and the other groundwater capture treatment systems 23

Thackston, Di 41
Avista Corporation
(currently in service) when all four units cease operation. In addition, this steam supply unit 1
is capable of supplying steam heating to Units 3 and 4 if both Units are off during winter 2
months. Project engineering started in late 2019, with design in January 2020 and construction 3
installation completion in 2021. The investment drivers for this project includes Mandatory 4
and Compliance, Asset Condition, and Performance and Capacity. This system is required 5
for the overall water handling requirements for the Colstrip site as directed by MDEQ under 6
the AOC. Costs have been adjudicated between the Unit 1 and 2 Owners and the Unit 3 and 7
4 Owners for this project. 8
Q. Please describe the Unit 3 Auxiliary Transformer Project. 9
A. The auxiliary transformer provides the necessary power to run the mills, 10
induced draft (ID) and forced draft (FD) fans, and other critical loads necessary to support the 11
generation of steam to power the turbines. These are very large loads – enough load to serve 12
a small town in many cases. In addition, other miscellaneous loads needed to run the unit are 13
provided by this source. An auxiliary transformer is used rather than using the grid as a source 14
in that it can be tapped directly from the output of the generator, saving considerable system 15
losses if the power is sourced through the transmission system. Using the grid for this load 16
would expose the plant and these critical loads to possible failures due to line faults, storms, 17
“driver hits pole” incidents, and other risks. 18
Unit 3’s auxiliary transformer is original equipment and has been in service over 36 19
years and it has been subject to several through faults due to in-plant electrical failures. The 20
load tap changers (LTCs) on Unit 3's Auxiliary transformer have experienced internal arcing 21
failure, oil leakage and controls failures in the last five years. The furanic compound testing 22
of the in-service transformer oil shows insulation aging concerns. Recently, the 13.8 kV load 23

Thackston, Di 42
Avista Corporation
tap changer failed, and troubleshooting indicated failed components on a control board. The 1
failure was repaired by removing a control board from the failed Unit 4 auxiliary transformer 2
and installing it in the Unit 3 auxiliary transformer. The auxiliary transformer for Unit 4 had 3
failed in service previously (a year earlier). As a stop gap measure, a configuration was made 4
with the transmission lines, the unit starting transformers, and station service bus to back feed 5
the auxiliary load (normally served by the auxiliary transformer) through this arrangement. 6
The resulting configuration results in substantial system losses. In addition, it would require 7
a significant de-rate on the operating unit in order to start the other unit if it had been shut 8
down for any reason. This placed the entire plant at risk of losing this key startup transformer. 9
The startup transformers were not designed for this heavy continual loading condition. There 10
was discussion to serve Unit 3 continuously with this configuration. Also, attempts were 11
made to locate a used or a rebuilt transformer, but the unique configuration of the 1,000 MVA 12
rating at the 26kV/13.8kV/4160 winding with load tap changer on both lower voltage 13
windings is very rare. No other suitable units were located. 14
The new transformer was ordered in 2019 and delivered so that it is on site if the old 15
auxiliary transfer fails. Installation of the transformer will coincide with the four-year outage 16
plan for Unit 3. This outage is currently planned for a window of 56 days starting in early 17
May of 2021, with in-service date in June 2021. The investment drivers for this project 18
includes Failed Plant and Operation, Asset Condition, Customer Service Quality and 19
Reliability, and Performance and Capacity. 20
Q. Please describe the Unit 3 Turbine Generator Base Overhaul Project. 21
A. This project entails a series of refurbishments and replacements of parts of the 22
turbine controls to assure they will function properly to provide the output control for a variety 23

Thackston, Di 43
Avista Corporation
of items including indirectly managing emissions levels (by managing the output of the 1
turbine, it provides means to make adjustments to the combustion process that can affect 2
emissions), controlling the turbine output and response to system conditions, and as a safety 3
system to prevent turbine over speed. 4
This project has planned work in two years. The first year (2020 commitment) is to 5
rebuild the turbine control valves that are removed from Unit 4 in 2020. This work is 6
associated with shipping the removed valves to have them completely refurbished and 7
prepared so they can be installed as part of the overhaul for Unit 3 scheduled in 2021. This 8
rebuild is to assure the control valves will perform as they are crucial for turbine control and 9
over speed protection. 10
The 2021 work includes the mobilization of labor, the high velocity oil flush, bearing 11
work as required, general open and close on the generator, throttle valve pinned seat 12
installation, governor valves, turbine control valves, reheat stop valve routine rebuilds, 13
contractor overhead (site support staff, project management, contract engineering support, 14
office/clerical help, etc.), scaffolding, insulation, tool use, general steam chest maintenance, 15
non-destructive evaluation (NDE) testing and maintenance of the bolts and studs on the valves 16
and steam chest and other assigned duties. This maintenance is performed every overhaul to 17
ensure proper operation and reliability of the turbine/generator. This work would coincide 18
with the four-year outage plan for Unit 3. This is currently planned for a window of 56 days 19
starting in early May 2021, with in-service date in June 2021. The investment drivers for this 20
project includes Asset Condition, Customer Service Quality and Reliability, and Performance 21
and Capacity. 22
Q. Please describe the Unit 4 Intermediate Pressure Turbine Overhaul 23

Thackston, Di 44
Avista Corporation
Project. 1
A. This project was originally approved as part of the 2018 budget as a three-year 2
project with completion in 2020. There was consideration given to ordering replacement 3
turbine blades and rings to replace the damaged ones on the first three stages. Because of the 4
extent of the damage observed in the inspection, it was determined to proceed with the 5
replacement of the complete turbine blades, rings, and inner cylinder. The basis for the original 6
2018 approval was to address reliability concerns associated with the condition of the IP 7
turbine blades and rings. Illustration Nos. 2 and 3 below show the current condition causing 8
the concerns with this equipment and the need for its replacement. 9
Illustration No. 2: Gouges in Unit 4 RS Generator Blower Stationary Blade Casting 10
11
12
13
14
15
16
17
18
19
20
21
22

Thackston, Di 45
Avista Corporation
Illustration No. 3: Unit 4 Governor UH Blade Ring 1 Row 1 Typical FOD to Blades 1
2
3
4
5
6
7
8
9
10
11
12
As briefly discussed above, some consideration was given to only replacing the 13
damaged components or doing nothing. When the decision was made, it was determined that 14
replacing the entire turbine blade, ring and rotor sections would best address plant reliability 15
and it would be less expensive to replace rather than repair due to the extensive field work 16
necessary to repair in contrast to the shop work to replace the components. 17
This project entails disassembling the Intermediate Pressure (IP) Turbine and 18
replacing the turbine rotor, stationary blades (blade rings), and the inner cylinder with new 19
equipment. The current outer cylinder will be re-used. Blade rows 1-3 and blade rings on 20
both sides of the existing IP Turbine have moderate to severe trailing edge erosion and some 21
blunt leading edges. The inlet flow guide is out of round due to thermal distortion and the 22
inner cylinder bolting hardware is starting to bottom out. The initial rows of the turbine have 23

Thackston, Di 46
Avista Corporation
had shroud repairs to mitigate shroud lifting. This work coincided with the four-year outage 1
plan for Unit 4. This outage started in mid-September 2020 with the decision to shift the 2
outage from spring to fall due to the COVID-19 issues and was completed in November 2020. 3
The investment drivers for this project include Asset Condition, Customer Service Quality 4
and Reliability, and Performance and Capacity. 5
Q. Please describe the Unit 4 Low Pressure Turbine Overhaul Project. 6
A. Previous Unit 4 inspections found modest damage to the low-pressure turbine. 7
The damage was due to several influences including some debris strike damage, erosion on 8
the blade due to normal operation, and some minor cracking due to age and wear. If this 9
damage was not addressed in a routine way, it could cause a major failure and extended 10
unplanned outage in the future. The scope of this capital project is to perform base 11
maintenance on the Low Pressure (LP) Turbine associated with the overhaul on Colstrip Unit 12
4. The work included General NDE, cleaning, blade and seal inspections and repairs as 13
needed. This work was done during an overhaul to ensure proper operation and reliability of 14
the LP Turbine. Long established industry practices have demonstrated the prudence of 15
performing this type of work during a planned maintenance event to avoid the risk of a major 16
unplanned failure in the future. The LP Turbine Overhaul Project is planned work driven by 17
manufacturer’s recommendations, the results of ongoing inspections, and needed work 18
discovered when the unit is opened up for its planned overhaul. This work coincides with the 19
four-year outage plan for Unit 4. Due to concerns from COVID-19, the spring outage was 20
delayed until fall 2020. This work began in mid-September 2020 and was completed in 21
November 2020. During the maintenance inspection, cracking was found on a low-pressure 22
blade that will require replacement. The investment drivers for this project includes Asset 23

Thackston, Di 47
Avista Corporation
Condition, and Performance and Capacity. 1
Q. Please describe the Unit 4 Turbine Generator Base Overhaul Project. 2
A. This project includes a series of refurbishments and replacement of parts of the 3
turbine controls to assure they will function properly to provide the output control for a variety 4
of items including indirectly managing emissions levels (by managing the output of the 5
turbine, it provides a means to make adjustments to the combustion process that can affect 6
emissions), controlling the turbine output and response to system conditions, and as a safety 7
system to prevent turbine over speed. The Unit 4 Generator Base Overhaul Project includes 8
the mobilization of labor; high velocity oil flush; bearing work as required; general open and 9
close on the generator; throttle valve pinned seat installation; governor valves, turbine valves, 10
and reheat stop valve routine rebuilds; contractor overhead (site support staff, project 11
management, contract engineering support, office/clerical help, etc.); scaffolding; insulation; 12
tool use; general steam chest maintenance; NDE testing and maintenance of the bolts and 13
studs on the valves and steam chest; and other assigned duties. This maintenance project is 14
performed every overhaul to ensure proper operation and reliability of the turbine/generator. 15
This work will installs a rebuilt turbine valve system that was removed from Unit 3 16
when it was overhauled in 2017. This project work coincides with the four-year outage plan 17
for Unit 4. With the decision to shift the outage from spring to fall due to the COVID-19 18
issues, this work began in mid-September 2020 and was completed in November 2020. The 19
investment drivers for this project includes Asset Condition, and Performance and Capacity. 20
Q. Please describe the Unit 4 Boiler Bucket Burner and Auxiliary Air 21
Replacement Project. 22
A. A critical component of the NOx control system are the Burner Buckets and 23

Thackston, Di 48
Avista Corporation
Separated Overfire Buckets
Auxiliary Air Tips. In order to meet environmental emission targets, these elements must 1
perform at a certain level. To maintain equipment function and to provide for NOx emission 2
and opacity control, buckets (separated overfire air (SOFA), top overfire air (TOFA), and 3
Burner) need to be replaced every four years during the unit overhaul. Buckets warp with 4
heat exposure over an extended time, which causes the buckets to bind up in the boiler and 5
restrict movement during unit operation (see Illustration No. 4). Through inspection during 6
overhaul, the buckets are generally found to be at the end of their useful life within three to 7
four years. The elements being replaced here are part of the combustion system. An optimal 8
performing system compliments other emission controls to minimize all emissions from the 9
plant. This project allows the plant to continue to operate within its permitted levels of 10
emissions. 11
Illustration No. 4: Separated Overfire Buckets 12
13
14
15
16
17
18
19
20
21
22
23

Thackston, Di 49
Avista Corporation
Burner buckets/Aux Air tips are scheduled to be replaced on a four-year plan during 1
an overhaul. Scheduling replacement of these components during an overhaul allows physical 2
access to all buckets (SOFA, TOFA, and Burner) while a scaffold is installed in the boiler. 3
The preventative maintenance process of replacing buckets is most economical with the use 4
of a scaffold as this allows for an effective and cohesive removal of buckets, repairs to support 5
material, testing of movement, and alignment of all emission components associated with the 6
boiler corners at the same time. Burner buckets/Aux Air Tips are a portion of the SmartBurn 7
NOx control system and need to be in good repair for combustion optimization, and particulate 8
matter and NOx control. The work for this project was completed during the Unit 4 major 9
planned outage that began in mid-September 2020 and ended in November 2020. The 10
schedule had shifted from spring to fall due to the decision to delay the outage due to COVID-11
19 concerns. The investment drivers for this project includes Mandatory and Compliance, 12
Failed Plant and Operation, Asset Condition, Reliability, and Performance and Capacity. 13
Q. Please describe the Unit 4 Auxiliary Transformer Project. 14
A. In 2018, the Unit 4 Auxiliary transformer developed high levels of gassing in 15
routine oil sampling indicating internal problems. Specifically, high levels of acetylene. 16
When the transformer was opened for inspection, damage to the tap changer and into the 17
transformer winding was discovered. The damage was unrepairable, so it was determined that 18
the most cost-effective solution was to place an order for a new transformer and replace the 19
out of service unit. The failed auxiliary transformer was original plant equipment and had 36 20
years of service. As a stop gap measure, a configuration was made with the transmission lines, 21
the unit starting transformers, and station service bus to back feed the auxiliary load (normally 22
served by the auxiliary transformer) through this arrangement. The resulting configuration 23

Thackston, Di 50
Avista Corporation
results in significant system losses. In addition, it would require a significant de -rate on the 1
operating unit in order to start the other unit if it had been shut down for any reason. This 2
configuration placed the entire plant at some risk of losing these key start up transformers as 3
well. The startup transformers were not designed for this heavy continual loading condition. 4
There was discussion to serve Unit 3 with this configuration. 5
The auxiliary transformer provides the necessary power to run the mills, ID and FD 6
fans, and other critical loads necessary to support the generation of steam to power the 7
turbines. These are very large loads, large enough load to serve a small town in many cases. 8
In addition, other miscellaneous loads needed to run the unit are also provided by this source. 9
An auxiliary transformer is used rather than using the grid as a source in that it can be tapped 10
directly from the output of the generator, saving considerable system losses if the power is 11
sourced through the transmission system. If the grid was used as a source of power for this 12
load, it would expose the plant and these critical loads to a variety of possible failures due to 13
line faults, storms, “driver hits pole” scenario, and other risks. The alternatives for this project 14
were described above. A new auxiliary transformer was the best solution because it reduced 15
exposure to possible grid faults or problems, prevented the use of equipment (i.e. startup 16
transformers) in a manner for which they were not designed, reduced in system losses, 17
increases unit reliability, and reduces wear on the LTC’s. 18
Attempts were made to locate a used or rebuilt transf ormer, but the unique 19
configuration of the 1,000 MVA rating at the 26kV/13.8kV/4160 winding with load tap 20
changer on both lower voltage windings is very rare. No other units were located. Inquiries 21
were also made to assess if repair of the failed transformer was an option, but vendor quotes 22
indicated it was far more expensive to attempt to repair the unit than to just replace it. The 23

Thackston, Di 51
Avista Corporation
chosen alternative was determined to mitigate risk as a reliability must do project. The order 1
was placed for the transformer in 2019 and the Unit 4 Auxiliary transformer arrived on site in 2
April 2020. Because of concerns with the COVID-19 Pandemic, a small outage of three weeks 3
was taken in May 2020 to inspect Unit 4 in advance of the major overhaul outage rescheduled 4
to September 2020. During this three-week outage, the Unit 4 Auxiliary transformer was 5
installed and was placed into service. The investment drivers for this project includes Failed 6
Plant and Operation, Asset Condition, and Performance and Capacity. 7
Q. Please describe the Unit 4 Air Preheater Basket Replacement Project. 8
A. The air pre-heater system is a key to overall boiler efficiency. This system 9
extracts heat from the flue gas and transfers it to the boiler make up air before the fire. It takes 10
less heat using hot air to reach operating temperatures within the boiler than colder air. This 11
process improves the cost effectiveness of the overall system. The condition of the baskets is 12
poor, they are falling apart and clogging the APH causing high differential pressure through 13
the APH which causes more workload on the ID fans. The current design has shown to cause 14
erosion and damage to additional baskets. The recommended replacement is with redesigned 15
baskets. 16
The Unit 4 Air Preheater Basket Replacement project is to replace major sections of 17
the air heat transfer baskets on the B Air Preheater (APH). Because of the arrangement of the 18
baskets, they wear on the inner rows and some have caused damaged to the intermediate 19
baskets. The wear on the baskets has caused the hot end baskets to fall apart and drop onto 20
the top of the hot intermediate baskets. This has resulted in plugging with the APH that cannot 21
be mitigated with a high-pressure wash. The only way to restore full function of the APH is 22

Thackston, Di 52
Avista Corporation
to replace the damaged APH baskets. Illustrations No. 5 and No. 6 show the damaged 1
condition of the baskets. 2
Illustration No. 5: Unit 4 Air Preheater Basket Condition 3
4
5
6
7
8
9
10
11
12
13
Illustration No. 6: Unit 4 Air Preheater Basket Condition 14
15
16
17
18
19
20
21
22
23

Thackston, Di 53
Avista Corporation
As this is a replacement of elements of an existing system required for the efficient 1
and reliable operation of the unit, there are few options. Choosing to continue to run in their 2
current condition would result in a continual failure of the system and the degradation of the 3
ability to preheat air for the combustion process, resulting in a significant decrease in unit 4
performance. Removing the Air Preheater is not a viable option as this is a critical element in 5
the heat cycle process and unit performance would significantly change, thereby increasing 6
the operating expense of the plant and subsequently increasing cost to customers. 7
The replacement option was chosen as it restores normal operating condition to the 8
unit without penalty or significant risk of failure after the overhaul work is completed. 9
Removal and installation of baskets and seals is most effective while done during an overhaul. 10
An overhaul of an air preheater is a systematic process which involves repair of numerous 11
sections of the air preheater as a whole, removal and replacement of baskets, repair of supports 12
as well as removal of ash and other debris. If forced to replace baskets after the overhaul, cost 13
would include about 24 days of lost generation, additional material required to move new and 14
old baskets, cleaning prior to installation and removal, additional staffing, and equipment 15
rental. 16
This is a reliability must do project. These baskets need to be replaced in order to 17
maintain equipment operation, reliability and efficiency. This work was performed during the 18
2020 Unit 4 overhaul outage that began in mid-September 2020 and completed in November 19
2020. The original schedule had shifted from spring to fall due to the decision to delay the 20
outage due to COVID-19 concerns. The investment drivers for this project includes Failed 21
Plant and Operation, Asset Condition, Customer Service Quality and Reliability, and 22
Performance and Capacity. 23

Thackston, Di 54
Avista Corporation
Q. Please describe the Unit 4 Cooling Tower Fill Project. 1
A. The Cooling Tower Fill has been in place for over ten years and is over its 2
recommended life span. Cooling Tower Fill (“Fill”) is typically replaced every 10 years, per 3
the manufacturer’s recommendations. The Fill is becoming brittle, as expected with 4
increasing age; and additionally, the Fill has been subjected to additional breakage due to 5
structural failures in the Cooling Tower structure. As these structural members fail due to 6
normal age and wear, it causes those parts of the Fill material that those members supported 7
to also fail and the brittle remnants of the failed cooling tower cause the circulating water 8
system to plug up. This causes plugging at the screens and throughout the system, resulting 9
in very high condenser back pressure which can lead to unit outages. 10
This project replaces 90 percent of the Fill and 50 percent of the piping and nozzles, 11
in conjunction with the structural maintenance to replace those failed members during the 12
2020 overhaul. New Fill material will be installed over these new members that will help 13
restore the Cooling Tower function. This is a partial retrofit intended to allow reasonable 14
operation until a similar project will be done at the next overhaul outage in four years. 15
Additionally, the Fill will need to be removed to replace the structural beams which will cause 16
further degradation and breakage, resulting in reliability issues. The Unit 4 Cooling Tower 17
Fill was replaced during in the 2020 scheduled overhaul outage in November 2020. The 18
investment drivers for this project includes Asset Condition, Customer Service Quality and 19
Reliability, and Performance and Capacity. 20
Q. Please describe the Install New Capture Wells at Effluent Holding Pond 21
Project. 22
A. This project provides for additional capture wells to be installed at the Unit 3 23

Thackston, Di 55
Avista Corporation
and 4 Effluent Holding Pond (EHP) to capture water that seeps from the ponds into the ground. 1
These wells collect this water to keep it from moving off the site. As required by the Colstrip 2
Wastewater AOC, this project provides for additional capture wells to be installed at the Units 3
3 and 4 EHP to meet the remedy evaluation activities identified in Alternative 4 of the Units 4
3 and 4 Remedy Evaluation Report. Remedial activities are required under the AOC to 5
mitigate impacted groundwater related to the Units 3 and 4 EHP. The Remedy Evaluation 6
Report was approved by MDEQ and the Remedial Design/Remedial Action Report for Units 7
3 and 4 is currently under review. Alternative 4 identified the installation of 23 new vertical 8
wells and 2 new horizontal wells in 2020 to meet the cleanup criteria in the time frame 9
identified by MDEQ under the AOC. 10
Q. Please describe the Design and Install in situ Flushing System EHP 11
Project. 12
A. This project provides for installation of 46 freshwater injection wells to be 13
installed at the Unit 3 and 4 EHP to promote capture of water that seeps from the ponds into 14
the ground. These wells inject fresh water into the ground to promote flows into the capture 15
wells at the edge of the property near the EHP. This project is another part of the groundwater 16
capture system. As required by the Colstrip Wastewater AOC, which dictates how water on 17
the site is to be remediated, this project provides for design and installation of in-situ flushing 18
wells to be installed at the Unit 3 and 4 EHP to meet the remedy evaluation activities identified 19
in Alternative 4 of the Units 3 and 4 Remedy Evaluation Report. Remedial activities are 20
required under the AOC to mitigate impacted groundwater related to the Unit 3 and 4 EHP. 21
The Remedy Evaluation Report has been approved by the MDEQ and the Remedial 22
Design/Remedial Action Report for Units 3 and 4 is currently under review. Alternative 4 23

Thackston, Di 56
Avista Corporation
identified the installation of 46 vertical injection wells in 2020 to provide clean flushing water 1
to meet the cleanup criteria in the time frame identified by MDEQ under the AOC. The work 2
on the In-Situ Flushing Well System item consists of design efforts in 2020 and installation 3
in 2021. 4
Q. Please describe the Design/Build Dry Waste Disposal System Project. 5
A. This project provides for installation of a “non-liquid” disposal system for Coal 6
Combustion Residue (CCR) material created by the operation of Units 3 and 4. This capital 7
project is required as part of the AOC which dictates how water on the site is to be remediated. 8
The Colstrip Wastewater AOC requires pond closure and remediation activities to address 9
impacted groundwater at the Units 3 and 4 Effluent Holding Pond (EHP) area. Litigation on 10
the AOC resulted in a Settlement that requires a "non-liquid" disposal system for CCR 11
material generated by Units 3 and 4 at the EHP no later than July 1, 2022. This project designs 12
and builds that "non-liquid" disposal system stipulated by the AOC and AOC Settlement 13
requirements. Design efforts began in 2020 and construction will start in 2021 with estimated 14
completion in mid-2022. The investment driver for this project is Mandatory and Compliance. 15
16
VI. RATTLESNAKE FLAT WIND POWER PURCHASE AGREEMENT 17
Q. Please explain the Rattlesnake Flat Wind Power Purchase Agreement and 18
what was the need for that resource? 19
A. The Rattlesnake Flat Wind Power Purchase Agreement (Rattlesnake Wind 20
PPA) is a 20-year agreement to purchase all of the generation output and all environmental 21
benefits associated with the 144 MW Rattlesnake Flat Wind project. Avista’s acquisition of 22
the Rattlesnake Flat Wind project began with the goal of acquiring renewable energy at a price 23

Thackston, Di 57
Avista Corporation
less than Avista’s 2017 IRP avoided cost as filed with the IPUC on August 31, 2017 and 1
acknowledged in Case No AVU-E-17-08, Order No. 33971 on January 31, 2018. Any long-2
term resource acquisition below these avoided costs is in the best interest of customers for two 3
reasons. First, the expected cost is less than the forecast price of power at the time of the 4
acquisition. Second, the price is fixed (known) as compared to the electric market that could 5
change over time due to many factors that are often out of the Company’s control. 6
Avista issued a renewable RFP in June 2018 to attempt to secure low cost renewable 7
generation based on expiring tax breaks and indicative developer pricing. A full summary of 8
the RFP process and justifications for signing the Rattlesnake PPA is provided as Exhibit No. 9
7, Schedule 6C – 2018 Renewable RFP Report. 10
Q. Please briefly describe the Rattlesnake Flat Wind Project. 11
A. The Rattlesnake Flat Wind Project consists of 50 Siemens S-129 2.9 MW wind 12
turbines that are located on 20,000 acres about 12 miles southeast of Lind, Washington with 13
a total capacity 160.45 MWs nameplate capacity “clipped” to 144 MWs of maximum delivery 14
based on the interconnection contract with Avista. The project is directly connected to the 15
Avista electric system and began commercial operation in December 2020. 16
Q. Can you provide a simplified timeline of events leading up to the execution 17
of the Rattlesnake Flat Wind PPA? 18
A. Yes. The following list is a timeline of the major events leading up to the 19
execution of the Rattlesnake Flat Wind PPA: 20
• 2014 to 2017: Company received unsolicited indicative bids for wind projects with 21
increasingly attractive pricing. 22
• First Quarter 2018: Lower indicative bid pricing received from potential developers. 23
• March 2018 – Initiated renewable RFP process internally. 24

Thackston, Di 58
Avista Corporation
• March 2018: Retained Black & Veatch as an Independent Evaluator for the RFP. 1
• May 2018: Outreach with Idaho Commission staff and intervenors. 2
• June 6, 2018: Phase I - RFP released. 3
• June 21, 2018: RFP Phase I bid opening and conference call with Commission Staff, 4
among others. 5
• June 29, 2020: Phase II – Shortlist identified, eight bidders. 6
• July 9, 2018: Conference Call – RFP short list update and presentation to Idaho 7
Commission Staff. 8
• July 23, 2018 to August 15, 2018: Questions and clarifications with Phase II bidders. 9
• August 16, 2018: Phase 2 – Requested price refresh from Phase II bidders. 10
• August 24, 2018: Received price refresh. 11
• September 12, 2018: Selected Rattlesnake Flat Wind Project as the preferred project. 12
• September 19, 2018: Notified Commission Staff of the winning RFP selection. 13
• September 2018 – February 2019: Contract negotiations. 14
• March 7, 2019: Signed contract with Clearway Energy for the Rattlesnake Flat 144 15
MW wind project - See Exhibit No. 7, Schedule 7C 16
17
Q. Can you provide some background regarding why the Company initiated 18
an RFP for renewable resources in 2018. 19
A. Yes. Avista began the 2018 RFP process with the goal of acquiring renewable 20
energy below the avoided cost identified in the 2017 IRP ($31.87 per MWh for wind and 21
$29.90 per MWh for solar, page 11-19 of the 2017 IRP). Obtaining this new, long-term 22
renewable resource would be in the best interests of customers because the cost would be 23
below the forecast price of power at the time of the acquisition and it would be at a known 24
price thereby eliminating the variations inherent in shorter term market purchases. 25
The spring of 2018 was seen as an opportune time for the Company to request and 26
evaluate renewable market options. Indicators for the timing of this RFP included the 27
expiration of the Production Tax Credit (PTC) in 2020, indicative pricing and developer 28
activity, competition for preferred projects and locations, technology advancements and 29

Thackston, Di 59
Avista Corporation
competition for least cost resources. The PTC was lowering prices as compared to price 1
quotes after 2020. The $23/MWh PTC was scheduled to be reduced or expire in 2020, as well 2
as the investment tax credit (ITC) in 20222. The $23/MWh PTC value is significant as it 3
represents approximately 44 percent of the cost of the selected project for the first 10 years. 4
Pricing was expected to increase after tax credits expired. Developer activity along with 5
industry market insights provided Avista opportunities to observe and analyze changes in 6
renewable energy technology and pricing. Indicative and actual pricing for renewables in the 7
west at that time suggested renewable resources were competitive in the wholesale market. In 8
fact, pricing provided to Avista during 2017 and early 2018 showed falling renewable prices. 9
With advances of machine technologies and the sun-setting of tax credits, pricing for 10
renewables had never been lower. Indications were pricing could increase if tax credit 11
opportunities were not fully captured. A more detailed discussion of the background for 12
initiating the 2018 Renewables RFP is available in Exhibit No 7, Schedule 6C – 2018 13
Renewable RFP Report. 14
Q. At the time of the 2018 Renewables RFP, please explain how the Company 15
determined that a new resource was necessary. 16
A. The 2018 RFP for renewables was issued in June 2018 to leverage beneficial 17
pricing including tax breaks going away and developer pricing. Although this RFP was held 18
prior to the Company’s announcement of its clean energy goals discussed earlier in my 19
testimony, the RFP provided an opportunity for the Company to evaluate a transition to a 20
cleaner resource portfolio at a lower cost. The Preferred Resource Strategy identified in the 21
2 The Investment Tax Credit (ITC) was modified by the IRS to include certain projects completed by 2024 on
June 22, 2018, subsequent to the issuance of the RFP.

Thackston, Di 60
Avista Corporation
2017 Integrated Resource Planning process only included the Solar Select renewable resource. 1
The other new resources identified in that IRP included natural gas peakers, upgrades to 2
existing facilities, energy efficiency, demand response and some distribution efficiencies. As 3
discussed in the 2017 IRP, Avista relies on market purchases to meet a small portion of its 4
energy and capacity needs. If Avista could replace these market purchases with a known 5
lower cost resource, then it is in the best interest of its customers to do so. 6
Q. How did the Company determine the amount and type of resource 7
needed? 8
A. The Company’s energy, capacity and REC needs were used as inputs to the 9
development of the Preferred Resource Strategy (PRS). The PRS is developed using a 10
proprietary linear programming model called PRiSM. The PRiSM model helps select the PRS 11
and uses: 12
1. Load deficits (energy and capacity); 13
2. RPS requirements; 14
3. Avista’s existing portfolio’s costs (loads and resources) and operating margins 15
(resources); 16
4. Fixed operating costs, return on capital, interest and taxes for each resource 17
option; 18
5. Generation levels for existing resources and new resource options; and 19
6. Carbon emissions levels for existing resources and new resource options. 20
21
Additional details about the development of the PRS and the PRiSM model used to decide on 22
the acquisition of Rattlesnake Flat Wind can be found in Chapter 11 of the 2017 IRP (Exhibit 23
No. 7, Schedule 9). 24
Q. Is this resource consistent with the 2017 Preferred Resource Strategy in 25
the Company’s 2017 IRP? 26

Thackston, Di 61
Avista Corporation
A. Yes, the 2018 RFP for renewables was consistent with the 2017 Preferred 1
Resource Strategy by considering acquiring additional resources if the resource has a lower 2
long-term cost than electric energy market alternatives. Chart No. 1 below shows that the 3
2018-2037 levelized cost of energy in the 2017 IRP was projected to be less costly fo r wind 4
and solar resources than for a flat energy project. 5
Chart No. 1: Levelized Electric IRP Avoided Cost of Energy*3 6
7
8
9
10
11
12
13
14
15
16
Q. How did Avista evaluate and consider alternatives to the Rattlesnake Flat 17
Wind PPA? 18
A. The Company issued an RFP on June 6, 2018 for 50 aMW of Washington RPS-19
qualified renewable energy to be online by the end of 20 20 and to secure the output through 20
a Power Purchase Agreement (PPA) and/or an option to purchase the project from renewable 21
generation resources, including electricity, capacity and associated environmental attributes. 22

3 Source: Data from 2017 IRP, Table 11.6 on pages 11-19.

Thackston, Di 62
Avista Corporation
(See Exhibit No 7, Schedule 6C). Bidders could submit one or more proposals including 1
wind, solar, geothermal, biomass, hydroelectric, and other renewable resources with or 2
without storage with a minimum net annual output of 5 aMW AC up to 50 aMW. The RFP 3
was open to parties who owned, proposed to develop, or held rights to new renewable resource 4
generating facilities. Avista engaged an independent evaluator, Black & Veatch, for this RFP 5
to review the selection criteria and provide an independent review of the received bids . The 6
Company did not accept proposals for renewable energy certificates only and did not consider 7
a self-build option in this RFP. 8
Avista produced an evaluation criteria and methodology for scoring bids in 9
consultation with the independent evaluator. The RFP evaluation methodology was shared 10
and discussed with the Staffs of the IPUC and WUTC on June 21, 2018. The methodology is 11
provided in Exhibit A of the 2018 Renewable RFP Report contained in Exhibit No 7, Schedule 12
6C. The general qualifications for each proposal were evaluated on the five characteristics 13
shown in Table No. 4 below. The weightings for each characteristic were determined based 14
on their importance in helping the Company meet its resource development goals stated in the 15
2017 IRP. Within each characteristic, points can be subtracted or added to the initial 100 16
points based on responses to the RFP and Avista’s interpretation of the data. Avista reserved 17
the right to modify the scoring criteria in consultation with Black & Veatch and the 18
Commission Staffs in Idaho and Washington if proposals were received that contained 19
circumstances not considered in the original methodology. However, this was unnecessary, 20
as the situation did not occur. 21

Thackston, Di 63
Avista Corporation
Table No. 4: 2018 Renewables RFP Evaluation Criteria and Weightings 1
2
3
4
5
6
7
8
Avista utilized a two-step bid process. Avista first evaluated and ranked projects based 9
on preliminary information by allowing developers to submit a condensed initial bid utilizing 10
a template provided in the RFP. The evaluation and ranking of the preliminary information 11
focused on conformance of each bidder’s submittal with the RFP requirements and the 12
proposed net price, among other factors. Evaluation and ranking, performed in a fair and 13
consistent manner, produced a short list of bids confirmed by Black & Veatch. Once the short 14
list was compiled, short-listed bidders were asked to submit detailed proposals. Each short-15
listed bidder’s detailed proposal was evaluated against the other proposals. In the end, 28 16
developers submitted over 40 responses to the RFP with projects in excess of 3,000 MW 17
proposed. Potential projects were evaluated both quantitatively and qualitatively based on 18
predetermined criteria shared with the staffs of the Idaho and Washington Commissions. 19
Eight projects were selected for a short list and were asked to provide detailed responses to 20
the proposal. 21
The first screening began on June 20, 2018. This screen focused on removing 22

Thackston, Di 64
Avista Corporation
proposals that did not meet the minimum RFP requirements. Preliminary information was 1
reviewed for all projects and an initial break point was established based on site control and 2
other issues. Most projects had either executed a binding option to lease the project site or 3
executed lease agreement(s) with landowner(s). Bids that had not discussed the project with 4
the landowner or had not executed any agreements were removed from further consideration. 5
Projects that did not provide a bid price were also removed. Sixteen project proposals were 6
eliminated through this initial review process. 7
Further evaluation of Preliminary Information resulted in rankings with a clear break 8
in the rankings after the top seven proposals. As we investigated one project further, it was 9
confirmed this was a repowering of an existing wind farm at the same capacity so the project 10
did not meet the RFP requirement for a new resource. Out of the top six ranked projects, five 11
were wind projects. To provide some projects for comparison to the top ranked solar project, 12
two additional solar projects were short-listed based on their next lowest solar PPA price and 13
mitigation of interconnection concerns based on commercial operation date. 14
To help Avista differentiate between the short-listed bids from the first to the second 15
rounds, eight short-listed bidders were asked to provide detailed proposals. The short-listed 16
bidders were further evaluated and additional due diligence was performed on each of the 17
more detailed offerings, which were then re-ranked according to the selection criteria. 18
Shortlisted bidders were allowed to refresh their prices in late August 2018 to help 19
differentiate their projects from the competition. Based on the new price information, and the 20
previous project descriptions, a new assessment and project ranking was performed. Exhibit 21
No. 7, Schedule 6C provides additional details about each of the short-listed bidder projects 22
and how they were ranked in the RFP. The price refresh established a clear winner based on 23

Thackston, Di 65
Avista Corporation
PPA price, permitting, and known integration and transmission costs. Ultimately, the cost for 1
the Rattlesnake Flat project along with the results from the evaluation matrix confirmed the 2
project as a top pick amongst the Avista RFP team and Black & Veatch. 3
Q. How was transmission considered in this decision? 4
A. The evaluation process included the transmission interconnection cost in the 5
case of projects with proposed direct interconnection with the Avista transmission system or 6
transmission and losses for projects proposed to interconnect to third party transmiss ion 7
systems and wheeling power to the Avista system. The Rattlesnake Flat Wind Project was 8
designed to be directly interconnected to Avista’s system, so no long-term third-party 9
transmission is required for this project to serve our customers. 10
Q. Was Avista’s Board of Directors involved with the acquisition of the 11
Rattlesnake Wind PPA by Avista Utilities? 12
A. Yes. The Company’s Board of Directors was apprised of the 2018 Renewables 13
RFP and the evaluation process that was used to compare project bids from which the 14
Rattlesnake Flat Wind PPA was selected. Documentation of Board involvement regarding 15
the Rattlesnake Wind PPA is provided in Exhibit No. 7, Schedule 8C. This confidential 16
exhibit includes presentations to the Board of Directors regarding the Rattlesnake Flat Wind 17
PPA. 18
Q. What documentation for the analysis and decision-making process has the 19
Company provided regarding the decision to enter into a contract for the Rattlesnake 20
Flat Wind Project? 21
A. Exhibit No. 7, Schedule 6C includes the complete documentation concerning 22
the RFP solicitation, and evaluation process that resulted in the selection and signing of the 23

Thackston, Di 66
Avista Corporation
Rattlesnake Flat Wind Power Purchase Agreement. 1
Q. Does the Company believe that the Rattlesnake Flat Wind PPA was a 2
prudent contract acquisition? 3
A. Yes. My testimony and exhibits provide the documentation necessary to 4
demonstrate the long-term economic benefit to Idaho customers for the Rattlesnake Flat Wind 5
PPA and provide specific supporting details regarding the Company’s analysis and decision. 6
The executed PPA will support the Company’s clean energy goals. The Rattlesnake PPA also 7
fits within the analysis performed under the Company’s IRPs. The Board of Directors agreed 8
with the recommendation to issue the RFP for 50 aMW of RPS-qualified renewable energy in 9
2018 and was apprised of management’s recommendation to negotiate a PPA with Rattlesnake 10
Flat Wind, LLC under terms and conditions consistent with their bid proposal. The Company 11
has provided and explained all of the analytical work that was completed related to this 12
acquisition through a competitive RFP with the aid of an independent evaluator, as well as 13
participation by both the Idaho and Washington Commission Staffs in the entire RPF process. 14
Q. Does this conclude your pre filed direct testimony? 15
A. Yes, it does. 16